Share Name Share Symbol Market Type Share ISIN Share Description
Serica Energy Plc LSE:SQZ London Ordinary Share GB00B0CY5V57 ORD USD0.10
  Price Change % Change Share Price Bid Price Offer Price High Price Low Price Open Price Shares Traded Last Trade
  3.60 2.85% 129.80 128.40 133.40 131.20 125.80 126.80 126,690 11:34:50
Industry Sector Turnover (m) Profit (m) EPS - Basic PE Ratio Market Cap (m)
Oil & Gas Producers 91.9 9.2 2.2 60.2 348

Serica Energy PLC Results for the year ended 31 December 2020

15/04/2021 7:00am

UK Regulatory (RNS & others)

Serica Energy (LSE:SQZ)
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RNS Number : 5131V

Serica Energy PLC

15 April 2021

Serica Energy plc

("Serica" or the "Company")

Results for the year ended 31 December 2020

London, 15 April 2021 - Serica Energy plc (AIM: SQZ), a British independent upstream oil and gas company with operations in the UK North Sea today announces its audited financial results for the year ended 31 December 2020. The results are included below and copies are available at and .

Commenting on the results, Mitch Flegg, Serica's CEO stated:

" We are reporting solid results after a challenging year and a severe industry downturn. Despite the many obstacles 2020 presented, Serica has continued to strengthen its financial and operational foundations and also to deliver returns to its shareholders. COVID-19 caused disruption to global markets and threatened operations during 2020 but Serica responded rapidly to protect its personnel and ensure continuing supplies of oil and gas into the British market. The impact of a substantial fall in commodity prices during the year plus a 45-day shut-in of BKR production in 1H to repair a damaged caisson on the Bruce platform was mitigated by the flexible structure of the BKR net cash flow sharing arrangements and the Group's gas price hedging programme. This financial and operational resilience enables the recommendation of an increased dividend of 3.5 pence per share.

The R3 workover is now nearing completion despite a series of technical challenges and periodic severe weather throughout the campaign and the Columbus development well was spudded in mid-March 2021. These projects are expected to boost production during 2H and Q4 respectively and we continue to actively pursue M&A opportunities that can broaden our asset base and add further value for our stakeholders. I look forward to updating shareholders on our progress during the rest of the year."

2020 Summary

-- Group profit before tax of GBP12.5 million (2019: GBP108.8 million) impacted by low commodity prices and Bruce caisson shut-in.

-- Average net production of 23,800 boe per day (2019: 30,000 boe per day) - reduction reflects 1H caisson repairs and other field maintenance work.

   --      Cash flow from operations of GBP44.1 million (2019: GBP137.1 million). 
   --      Capital expenditure of GBP26.6 million (2019: GBP5.3 million) . 
   --      Maiden 3 pence per share dividend paid in July totalling GBP8.0 million (2019: nil) . 

-- Closing cash and cash equivalents of GBP89.3 million (2019: GBP101.8 million) after capital expenditure and dividend payment with no debt.

-- Resource base reinforced as Group production of approx. 8.1 million boe for the year largely offset by a 12% increase oil and gas reserves, leaving year end reserves of 61.0 million boe (2019: 62.3 million boe).


-- Average 2020 sales price of approx. US$20 per boe (2019: US$30 per boe) and average operating cost of US$14.12 per boe (2019: US$12.60 per boe).

-- Gross loss of GBP2.9 million (2019: profit of GBP85.8 million) and operating loss of GBP18.7 million (2019: profit of GBP87.7 million) included GBP38.5 million (2019: GBP52.6 million) of non-cash depletion charges.

-- Realised gains of GBP12.3 million (2019: GBP3.9 million) on 2020 gas price hedging offset by unrealised losses of GBP16.6 million (2019: unrealised gains of GBP6.7 million) on 2021/2022 hedging:

o based on market futures curve at balance sheet date and reflects rapidly strengthening forward gas prices at the year end.

   --      Cash flow from operations of GBP44.1 million (2019: GBP137.1 million) after payment of: 

o GBP21.8 million of BKR cash flow sharing and other liabilities (2019: GBP57.3 million)

o GBP26.6 million of capital expenditure (2019: GBP5.3 million) and

o GBP8.0 million of dividends (2019: nil).

-- Profit after tax was GBP7.8 million (2019: GBP64.0 million) after a non-cash deferred tax provision of GBP4.8 million (2019: GBP44.8 million).


-- Updated independent audit of field reserves reported Serica's share of estimated remaining 2P reserves as 61.0 million boe as at 1 January 2021:

o approximate 12% increase over the 62.3 million boe reported as at 1 January 2020, after adjustment for 2020 production

o largely the result of improved production efficiencies and lower operating costs achieved on the BKR assets since acquisition by Serica

o projected BKR field life now extended by a further two years.

-- Bruce, Keith and Rhum fields produced 21,500 boe per day net to Serica for 2020 compared to 27,300 boe per day for 2019 - reduction largely due to the 45-day shutdown in 1H to effect caisson repairs on the Bruce platform and to planned maintenance.

-- Erskine field continued its strong performance averaging over 2,300 boe per day net to Serica during 2020 (2019: 2,700 boe per day) after five-week planned maintenance shut-in.

-- Serica continued its cost reduction programme on BKR, lowering underlying operating costs by a further 10% in 2020. However, overall Group costs per barrel increased to US$14.12 per boe from US$12.30 in 2019 as fixed cost elements were spread over lower production volumes.

-- Successful completion of the Rhum R3 workover is expected to accelerate field production, with the potential to bring additional reserves into the commercial lifespan of the field and to provide operational back-up to the existing two wells. Total costs now projected at GBP21 million, after adjustment for net cash flow sharing, of which GBP11.5 million to be spent in 2021 - represents total cost overrun of GBP9.7 million net to Serica.

-- The Maersk Resilient heavy-duty jack-up rig spudded the Columbus development well on 17 March 2021 and drilling is progressing to plan. The Arran-Shearwater export pipeline has been laid and first gas from Columbus is expected for Q4 2021.


   --      Active management on flaring resulted in a 45% reduction in flare volumes compared to 2019. 

-- CO(2) emissions on Bruce of approx. 214,500 tonnes were over 10% lower compared to 2019 (241,500 tonnes).

-- ESG performance metrics added to annual incentive scheme for all Group employees covering flaring, carbon intensity, diversity and waste.

-- As a demonstration of its commitment to reporting transparency, Serica intends to publish its second Environmental, Social and Governance ("ESG") Report in conjunction with the publication of the full Annual Report and this will be available on Serica's website .


-- The resurgence in commodity prices which commenced in Q4 2020 has continued into 2021 with average market prices for Q1 of approximately 50 pence per therm for NBP gas and US$61 per barrel for Brent oil, significantly higher than the respective average prices of 25 pence per therm and US$42 per barrel seen in 2020.

-- Gas in particular, currently some 80% of Serica's production mix, has seen prices since the year end reach sustained levels not seen since 2018. Apart from the significant benefit this brings to realised revenues, Serica also continues to build its price hedge position to cushion against commodity price falls such as seen in 2020 whilst maintaining high exposure to higher prices such as seen in the period following the year end.

-- Significant increases in Serica's retained share of production volumes in prospect with R3 expected to be contributing in Q3, Columbus from Q4 and Serica's retained share of net cash flow from the BKR assets increasing from 60% to 100% effective 1 January 2022.

-- As a core part of pursuing our objectives we will continue to increase our focus on ESG issues, in particular in efforts to reduce the carbon intensity of our production.

-- Having initiated a dividend policy last April it is the Board's intention to maintain dividend payments for future years and to grow the level when financial performance supports this.

-- Subject to shareholder approval at the AGM, a dividend of 3.5 pence per share will be payable on 23 July 2021 to shareholders registered on 25 June 2021 with an ex-dividend date of 24 June 2021.

-- With strong operating, ESG and financial credentials Serica is well-placed to grow through developing the potential of its existing assets as well as building on new opportunities to diversify risk, provide new growth prospects and achieve economies of scale.

A conference call for sell-side analysts will be held later today at 10.00 a.m. (UK time), today. If you would like to participate, please email . A copy of the accompanying presentation can be found on our website: .


This announcement is inside information for the purposes of Article 7 of Regulation 596/2014.

The technical information contained in the announcement has been reviewed and approved by Fergus Jenkins, VP Technical at Serica Energy plc. Mr. Jenkins (MEng in Petroleum Engineering from Heriot-Watt University, Edinburgh) is a Chartered Engineer with over 25 years of experience in oil & gas exploration, development and production and is a member of the Institute of Materials, Minerals and Mining (IOM3) and the Society of Petroleum Engineers (SPE).

  Serica Energy plc                               +44 (0)20 7390 0230 
   Tony Craven Walker, Executive Chairman 
   Mitch Flegg, CEO 
   Peel Hunt (Nomad & Joint Broker)                +44 (0)20 7418 8900 
   Richard Crichton / David McKeown / Alexander 
   Jefferies (Joint Broker)                        +44 (0)20 7029 8000 
   Tony White / Will Soutar 
   VIGO Communications                             +44 (0)20 7390 0230 
   Patrick d'Ancona / Chris McMahon / Simon 


Dear Shareholder

The past twelve months have seen a perfect storm of events caused by the worldwide pandemic which erupted at the start of 2020. The resultant lockdown, requiring companies to restrict travel, abandon office working, implement social distancing and introduce new digital technologies to facilitate communication, has put considerable strain on established business models and work practices.

In the oil and gas world, we also had to contend with one of the biggest commodity price collapses in recent years, with US oil prices moving into negative territory for a short time early in 2020 and European gas prices dropping to levels which have not been seen for decades. In short, 2020 has been an extraordinarily difficult year to navigate for all industries but particularly for the oil and gas industry.

I am pleased to report that Serica has not only been able to weather these storms, but we have also been able to move forward with all of the projects we set for the year, in particular the Columbus gas field development and the R3 intervention projects. A successful conclusion of these projects should see a significant increase in production levels in the second half of this year to add to the benefits we are already seeing from strengthening commodity prices. We are also entering the last year of the net cash flow sharing arrangements with BP, Total and BHP which formed the basis of our acquisition of the BKR assets in 2018. As a result, we will be retaining 100% of cash flows from these assets from the beginning of next year, up from 60% this year and further strengthening our cash generation.

We have been able to achieve our 2020 operational targets to build for the future with minimal impact on our financial resources. Cash balances remained strong at year end, standing at just under GBP90 million compared with GBP101 million at the start of the year despite the low oil and gas prices and after making significant capital investments in the Columbus and R3 projects. In addition, we are reporting a profit for the year of just under GBP8 million after providing for deferred tax. Albeit significantly less than the GBP64 million reported for the prior year this demonstrates remarkable resilience during a severe industry downturn.

Prices for both oil and gas have strengthened since the start of this year, particularly gas prices which affect some 80% of our production and which have risen some four-fold from their 2020 low, supporting ongoing spend on our Columbus and Rhum R3 projects. This strong financial position, with no debt and considerable unutilised debt capacity allows us to prepare for drilling the North Eigg gas prospect next year as well as completing our existing projects this year, continuing investment in the BKR assets and pursuing further growth opportunities.

Last year we paid our maiden dividend, amounting to 3p per share, and did so at a time of considerable upheaval in the oil and gas sector. This year, in view of the Company's continuing strong cash position, we are recommending an increased dividend of 3.5p per share reflecting the Board's confidence in the future prospects for the Company. Subject to approval at the Annual General Meeting in June, this will be paid as a single final dividend to all shareholders on the register at 25 June 2021.

The Company puts considerable emphasis on setting the highest standards that it can to meet environmental, social and good governance expectations of our shareholders, other stakeholders and of society at large. These include diversity where this can be achieved and equal opportunity. As a young company we are able to implement good modern practices and involve all of our employees in seeking to achieve and improve on our targets and we endeavour to bring new thinking and business innovation to these efforts as a focal part of our leadership team. Mitch Flegg, in his CEO's report, will be highlighting some of the steps we are taking and significant improvements we have been able to make to the carbon intensity of our offshore operations since taking over operations two years ago. Further information is provided in our Annual Report and we will also be publishing a full ESG performance report on our web-site as part of our annual reporting cycle.

Many commentators have questioned the role of oil and gas as the world enters a new phase and new technologies are developed to replace the traditional sources of energy. Targets have been set to achieve Net Zero carbon by 2050 with various stage targets in the intervening period. There is no question that the oil and gas industry is fully committed to meeting those targets and has the technological expertise and knowledge to achieve it but it is a process which will take time to implement. Oil and gas, particularly gas as a relatively clean fuel, will still be required to underpin this transition and to provide economies with the fuel and materials they need as part of the energy mix to maintain supply and living standards whilst the shift to new sources of energy is implemented and new technologies and the necessary infrastructure are developed.

Serica has a role to play in this transition. As an established North Sea production operator we have the skills and finances to work in partnership with major companies as they seek to optimise their reserves, reduce operating costs, improve profitability and move to lower carbon technologies. With our performance as Bruce operator we have strong ESG credentials and we will be looking to build on this as a fundamental part of any new investment as well as continuing to focus on our main tenets: adding shareholder value, protecting shareholder value and returning shareholder value. Serica has been able to do all three in 2020 and is well-placed to grow on the back of its existing assets as well as building on new opportunities. We are looking forward to 2021.

In summary, I am very pleased to report that we have been able to manage the challenges of 2020 and are entering 2021 financially and operationally stronger than ever. This is due in no small part to the huge commitment of Serica's teams in London, Aberdeen and on the Bruce offshore complex. I would like to thank all of them on behalf of the Board and our shareholders for their outstanding performance in such challenging times.

Tony Craven Walker


14 April 2021


The following Strategic Report of the operations and financial results of Serica Energy plc ("Serica") and its subsidiaries (the "Group") should be read in conjunction with Serica's consolidated financial statements for the year ended 31 December 2020.

References to the "Company" include Serica and its subsidiaries where relevant. All figures are reported in GB Sterling ("GBP") unless otherwise stated. With effect from 1 January 2019, the Group's results have been reported in GBP.

The Company is subject to the regulatory requirements of AIM, a market of the London Stock Exchange in the United Kingdom. Although the Company delisted from the Toronto Stock Exchange ("TSX") in March 2015, the Company is a "designated foreign issuer" as that term is defined under Canadian National Instrument 71-102 - Continuous Disclosure and Other Exemptions Relating to Foreign Issuers.

Serica is an independent oil and gas company with production, development and exploration interests in the UK Continental Shelf.


It is impossible to review any aspect of 2020 without first considering the impact of the COVID-19 pandemic. Serica was quick to implement measures to reduce the likelihood of the virus impacting our operations. We adopted new travel procedures which included reducing the number of personnel on helicopters to and from our offshore installations. We also significantly limited manning levels on the Bruce platform in order to reduce the risk of an outbreak, allow social distancing offshore and provide isolation areas for suspected cases. These reduced manning levels meant that the working conditions were more difficult for those staff remaining on the platform and also meant that we have had to prioritize essential (especially safety and environmentally critical) activities throughout the year. I am delighted to report that due to the incredible skill, hard work and professionalism of our team we have managed to avoid any cases of the virus on our installations and so we have incurred no COVID-19 related interruptions to production. Our safety performance was outstanding with zero recordable injuries sustained during the year. Serica has not furloughed any staff or taken advantage of any of the government assistance programmes.

Serica has demonstrated that it has all of the skills to thrive as a modern, dynamic energy company operating as part of the Net Zero transition. Over 80% of our production is natural gas which is a key component in this transition. Our second annual Environmental, Social and Governance ("ESG") Report will be published along with the annual report. In the past year we have reduced Bruce carbon emissions by over 11% and we have achieved a 62% reduction in flaring in only two years as operator of the Bruce platform.

Despite the severe social impact of COVID-19 and the economic impact on commodity pricing which has affected all companies in 2020, I am pleased to report that Serica Energy's strong balance sheet and robust hedging position combined with the structure of the transactions under which we acquired our interests in the Bruce, Keith and Rhum ("BKR") fields has resulted in the Company reporting a full-year profit of GBP7.8 million (2019: GBP64.0 million) after provision for deferred tax.

Production levels in 2020 were impacted by a 45-day suspension of BKR production to resolve an issue with an unused caisson on the Bruce platform. As a result, Serica's net production for the year averaged 23,800 boe/d (compared to 30,000 boe/d in 2019). It should be noted that the 45-day shut-down occurred in the early part of the year when gas prices were significantly lower than late in the year. The production from the 45-day period is not lost but deferred and the shut-down is not expected to have any impact on ultimate recovery from BKR.

Gas prices for the year averaged less than 25 pence per therm before hedging gains but Serica's gas price hedging programme effectively fixed prices for approximately one-third of our retained 2020 gas sales at approximately 39 pence per therm. This hedging programme delivered cash income of GBP12.3 million during 2020. We continue to extend our hedging position and for 2021 and 2022 Serica has swaps in place covering up to 25% of retained gas sales after adjustment for 2021 net cash flow sharing. These swaps provide some protection against severe downside gas prices whilst retaining the potential upside benefit from the majority of production.

We continue to focus on minimising our cost base and in 2020 we have realised further reductions in our absolute operating costs. However, when expressed as costs per barrel there is an increase to US$14.12/boe (2019: US$12.60/boe). The increase in operating costs per barrel reflected lower production volumes caused by the 45-day BKR production suspension in the first half and does not indicate an increase in the underlying trend.

Serica has commissioned a new Competent Person's Report ("CPR") effective 1 January 2021 and this has identified an upgrade to net 2P Reserves estimates particularly due to the successful efforts to extend the prognosed Cessation of Production ("COP") on Bruce through which all Bruce, Keith and Rhum production is processed. I am delighted to report that the latest CPR estimates that the Bruce COP (2P case) has been extended by a further two years and is now predicted to occur in 2030. In the last two years we have extended COP by a total of four years; this is a clear indication that our BKR life extension strategy is being successful. Our net 2P reserves stood at 62.3 million boe at 1 January 2020 and our 2020 net production was more than 8 million boe but due to these upgrades, after 2020 production, our net 2P reserves at 1 January 2021 stand at 61.0 million boe.

During 2020, Serica decided to withdraw from Namibia where we had originally been awarded a licence in 2011. Following a full review, we elected not to seek a further renewal period or to continue with a new licence application. The pace of exploration activity in Namibia had been slower than we hoped, and the development of any discovery would likely have been high cost, time consuming and inconsistent with our sustainability objectives. Therefore, we have decided to concentrate on the numerous lower risk, nearer term opportunities in our North Sea portfolio. In particular we have a programme of three investment projects that each have the ability to generate significant value for the Company:

1. The Rhum field currently produces from two wells (R1 and R2) which are subsea tie-backs to the Bruce platform. A third well (R3) was drilled when the field was originally developed but was not put into production due to mechanical issues with equipment in the well. In late 2020, operations commenced to remedy these problems. The completion equipment installed in the well by the previous operator in 2005 has been fully recovered. We are now in the process of regaining access to the reservoir prior to running a new completion, reperforating and flowing the well. R3 is expected to accelerate field production, with the potential to bring additional reserves into the commercial lifespan of the field, and to provide operational back-up to the existing two wells.

2. T he Columbus development well in the UK Central North Sea was spudded in March 2021. The well is being drilled with the Maersk Resilient jack up rig to a total depth of 17,600ft and will include a 5,600ft horizontal section. The Columbus development area is 35km north east of the Shearwater production facilities and will be drained by a single producing well tied into the existing Arran-Shearwater pipeline. The recent Competent Person's Report estimates the Columbus gross undeveloped 2P reserves to be in excess of 14 million barrels of oil equivalent ("boe"). Serica is operator and has a 50% interest in the project. Production is expected to commence in early Q4 2021, with average production forecast to be around 3,500 boe/d net to Serica, of which over 70% is gas.

3. Planning is ongoing for the drilling of the HPHT North Eigg exploration well which we expect to spud in 2022. This prospect is located in the area adjacent to the Serica operated Rhum field and in the event of a discovery, Serica will investigate options for subsea tie-backs to the Bruce facilities and topsides modifications to ensure a low cost, low emission design to enable early development, maximise recovery and optimise production. Serica has carried out an in-house evaluation of the prospect and estimates the unrisked prospective (recoverable) resources, based on seismic mapping and Rhum analogue data, to be around 70 million boe.

2020 was a year of solid performance and improvement which demonstrated the resilience and profitability of the Company in the face of unprecedented business challenges. 2021 will be a year of continued investment in the growth opportunities which exist in our portfolio. The end of 2021 will represent another huge milestone for the Company with the expiry of the cash flow sharing arrangement under which Serica has been sharing the net cash flow from BKR variously with BPEOC, Total E&P and BHP who originally sold us their interests. In 2021 Serica retains 60% of the net cash flow but this will increase to 100% on 1 January 2022 and stay at that level thereafter providing a significant cash boost for the Company.

Serica's strategy is to build on the strong financial and operating capabilities which the Company has established in the UK Sector of the North Sea and focus on our strong ESG credentials. Whilst we see significant benefits and potential in our existing portfolio we continue to look at new opportunities to expand our operations to diversify risk, provide new growth prospects and achieve economies of scale. We are confident that we have the resources to deliver this strategy and the platform to create additional value for shareholders.

Mitch Flegg

Chief Executive Officer

14 April 2021



Northern North Sea: Bruce Field - Blocks 9/8a, 9/9b and 9/9c, Serica 98%

Serica operates the Bruce field and facilities consisting of three bridge-linked platforms, wells, pipelines and subsea infrastructure. The platforms contain living quarters for up to 168 people, reception, compression, power generation, processing and export facilities and a drilling derrick that is currently mothballed.

The Bruce field is produced through a combination of platform wells and subsea wells tied back to the platform, with over 20 wells producing from multiple reservoirs and compartments. Bruce production is predominantly gas which is rich in NGL's. Gas is exported through the Frigg pipeline to the St Fergus terminal, where it is separated into sales gas and NGL's. Oil is exported through the Forties Pipeline System to Grangemouth.

The offshore team is supported onshore by the Serica technical headquarters in Aberdeen which has a live video link to the platform, streaming data and offering seamless communication with the offshore crew. The onshore support team was already using video links to provide support to the platform, so whilst working from home during the COVID-19 pandemic, that technology has allowed Serica to provide uninterrupted support to the offshore operation.

In January 2020, during a Bruce platform inspection, the condition of an unused seawater return caisson on the platform was observed to have deteriorated. This caisson had been taken out of service in 2009. Production through the Bruce facility was halted while the problem was fully investigated.

A subsequent underwater inspection determined that the caisson had parted below the water line. Both the upper and lower sections of the caisson were intact and engineering work to ensure that the caisson was properly secured commenced.

Work was successfully undertaken during the following weeks and the caisson sections secured allowing production to restart on 5 March. During August, further work was undertaken to remove damaged parts of the caisson back to shore.

To maintain operations during COVID-19 restrictions, increased social distancing offshore, pre-mobilisation testing, social distancing on transportation (including helicopters) and other practical control measures were introduced. This reduced the number of personnel working offshore by 30%. This had an initial impact on the quantity of work that was able to be executed offshore, but during the year Serica found ways to remove inefficiencies whilst maintaining reduced numbers offshore. No pandemic production interruptions occurred in 2020.

As part of the drive to be more efficient, during 2020 Serica created a digital twin of the Bruce facility to enable more onshore support (maintenance campaigns, visual inspection, modification design and pipework fabrication) to be undertaken without personnel having to visit the platform. As an example, one specific inspection scope that had previously been forecast to cost GBP150,000, was carried out with reductions of 75% in offshore days and 40% in the total cost. This reduces cost, shortens response time and minimises travel risk. Further enhancements to this technology will be incorporated in future years.

Bruce field production in 2020 averaged in excess of 9,600 boe/d of exported oil and gas net to Serica (2019: 13,100 boe/d) with the reduction primarily as a result of the 45-day caisson shut-down. Full year production reliability was 84.7% (96% excluding the caisson interruption).

The latest independent report of reserves, compiled by RISC Advisory, estimated 2P reserves of 15.7 million boe net to Serica as of 1 January 2021 (2020: 22.2 million boe). The restricted programme of well work during 2020 has led to declassification of some 2P reserves pending reinstatement of this work in future periods.

Northern North Sea: Keith Field - Block 9/8a, Serica 100%

Keith is an oil field produced by one subsea well tied back to the Bruce facilities. Keith produces at a relatively low rate but provides a low-cost contribution to oil export from Bruce. Keith production was interrupted in January 2020 initially due to the Bruce caisson issue and thereafter when required topsides reinstatement work was unable to progress due to the reduced number of people offshore in response to COVID-19. An intervention to restore flow from Keith was successfully carried out in late March 2021 and further enhancement work is planned in Q2. Keith production during 2020 was minimal but average production in 2019 was around 450 boe/d. No 2P reserves were included in the most recent reserves report pending successful reinstatement of production.

Northern North Sea: Rhum Field - Block 3/29a, Serica 50%

The Rhum field is a gas condensate field producing from two subsea wells tied into the Bruce facilities through a 44km pipeline. Rhum production is separated into gas and oil and exported to St Fergus and Grangemouth along with Bruce and Keith production. Rhum gas has a higher CO(2) content than Bruce gas and so is blended with Bruce gas before leaving the offshore facilities. The field continues to outperform our expectations at the time of acquisition.

An intervention campaign is under way to workover the R3 well and allow it to be brought onto production. The well was drilled at the same time as the other two Rhum production wells, however problems were encountered in 2005 by the previous operator during well completion. The well was left with an ice-like hydrate plug which prevented it flowing; attempts at that time to rectify this additionally resulted in wireline debris being left in the well.

Serica has successfully remedied both issues, recovering the wireline 'fish' and dissociating the hydrate plug with heated fluid. The well is now being prepared for production. The operation has taken longer than anticipated due largely to the unexpectedly poor condition of the equipment being recovered from the well and also to periodically severe weather conditions. Production from the well is now expected to commence in Q3. Total R3 capital costs are now projected at GBP21.0 million net to Serica, after adjustment for net cash flow sharing, of which GBP11.5 million will be spent in 2021. This represents a total cost overrun of GBP9.7 million net to Serica.

Average Rhum production in 2020 was over 11,900 boe/d net to Serica (2019: 13,775 boe/d) the reduction being primarily as a result of the Bruce caisson shut down. The latest independent report of reserves, compiled by RISC Advisory, estimated 2P reserves of 35.1 million boe net to Serica as at 1 January 2021 (2020: 28.7 million boe). The significant increase after adjustment for 2020 production demonstrates Serica's progress in extending projected field life and adding to recoverable reserves.

Central North Sea: Erskine Field - Blocks 23/26a (Area B) and 23/26b (Area B), Serica 18%

Serica holds a non-operated interest in Erskine, a gas and condensate field located in the UK Central North Sea. Serica's co-venturers are Ithaca Energy 50% (operator) and Harbour Energy 32%. Erskine fluids are processed and exported via the Lomond platform, which is 100% owned and operated by Harbour Energy.

The Erskine field is produced through five production wells over the Erskine normally unattended installation, transported to Lomond via a multiphase pipeline and processed on the Lomond platform. Then condensate is exported down the Forties Pipeline System via the CATS riser platform at Everest and gas is exported via the CATS pipeline to the CATS terminal at Teesside.

The flash and export coolers that are part of the Erskine production module located on the Lomond platform were replaced in April 2020. The 2020 Forties Pipeline System maintenance shut-in, planned for June 2020, was deferred due to COVID-19 until May 2021. However, the Lomond offtake facilities and the Erskine field were shut in for 35 days during Q3 to carry out an extensive maintenance programme.

The high frequency pigging program on the condensate export line has continued and no indications of wax build-up have been seen. Serica is supporting Ithaca and Harbour Energy with their reliability improvement plans for the Erskine system and provides a secondee to Lomond as part of the offshore management team.

Erskine production levels in 2020 averaged over 2,300 boe/d net to Serica (2019: 2,700 boe/d) after the planned 35 day maintenance shut-down in Q3. Full year production reliability in 2020 was slightly above 82%, after exclusion of the maintenance shut-down, which was comparable to 2019. The latest independent report of reserves, compiled by RISC Advisory, estimated 2P reserves of 3.1 million boe net to Serica as of 1 January 2021 (2020: 4.1 million boe).


Central North Sea: Columbus Development - Blocks 23/16f and 23/21a (part), Serica 50% and Operator

Serica is development operator with partners Tailwind Energy Limited (25%) and Waldorf Production Limited (25%). Columbus is located in the Eastern Central Graben, UK Central North Sea and the reservoir is located within the Forties Sandstone. Columbus has been designated as a development within the Lomond Field Area; it is however independent of Lomond, having separate development consent, export route and licence terms.

The development comprises a single horizontal well with a subsea completion connected to the Arran-Shearwater pipeline, through which Columbus production will be exported along with Arran field production. The Arran export pipeline was approved at a similar time to Columbus and has now been constructed and laid on the seabed, though it has not yet been tied into the Shearwater platform. When production from Arran and Columbus reaches the Shearwater facilities, it will be separated into gas which is exported via the SEGAL line to St Fergus and liquids which are exported via the Forties Pipeline System to Cruden Bay.

Columbus development timing is dependent on the export pipeline being tied into the Shearwater platform and Arran exports beginning. Columbus start-up is therefore expected during the fourth quarter of 2021, once stabilised production conditions have been achieved following the Arran field coming on-line.

The Maersk Resilient heavy-duty jack-up rig was contracted to drill the 23/16f- C 1 development well; it arrived on site on 6 March and the well was spudded on 17 March 2021. The well is planned to be drilled to a total depth of 17,600ft and will include a 5,600ft horizontal section through the reservoir. Well operations are expected to take around 70 days.

After drilling the well, an open-hole sand-screen completion will be installed and a short clean-up flow and well test will be performed to provide production data and prepare for flowing into the export system. The well will then be suspended, before being connected to the Arran-Shearwater pipeline later in the year. When production commences, average gross production is forecast to be around 7,000 boe/d, of which over 70% will be gas.

The latest independent report of reserves, compiled by RISC Advisory, estimated 2P reserves of 7.1 mmboe net to Serica as at 1 January 2021 (2020: 6.7 million boe).



North Eigg and South Eigg - Blocks 3/24c and 3/29c, Serica 100% and operator

In December 2019, Serica was awarded the P2501 Licence as part of an out of Round application; this comprises Blocks 3/24c and 3/29c and contains the North Eigg and South Eigg prospects. The official start date for the licence was 1 January 2020. The work programme involves reprocessing seismic data and drilling an exploration well within three years of the start of the licence. The North Eigg prospect has been high-graded for drilling, being clearly visible on 3D seismic data and sharing many similarities with the nearby Rhum field, operated by Serica.

Work has started on planning to drill the exploration well, which is expected to be high temperature and high pressure, during the summer of 2022. In the event of a commercial discovery, Serica would seek a fast-track route to develop the field, whilst implementing options that would reduce emissions. This could potentially be via a subsea tie-back to the Serica operated and 98% owned Bruce facilities, which are to the south of the prospect. This would bring the benefits of reducing the overall carbon intensity of the Bruce facilities and extending the life of the infrastructure.

Columbus West - Block 23/21b, Serica 50%, operator Summit Exploration and Production

An extensive work programme was undertaken to mature the prospectivity on the licence. Despite this work, stratigraphic trapping and sealing mechanisms for the prospects remained elusive and could not be satisfactorily confirmed.

The seismic data response was also suggestive of oil rather than gas accumulations and the economics were determined not to be favourable for an oil development, as there was no nearby tieback host.

Taking current market outlook into consideration, and the approaching commitment required to move to the next phase of the licence which would have meant relinquishing 50% of the initial licensed area and committing to drill a well, the risk-reward ratio related to proceeding with West Columbus was not deemed sufficient to proceed with exploration drilling.

Serica therefore supported the operator's recommendation to relinquish the licence.

Skerryvore and Ruvaal- Blocks 30/12c (part), 30/13c (split), 30/17h, 30/18c and 30/19c (part), Serica 20%, operator Parkmead

The Skerryvore and Ruvaal prospects lie in the Central North Sea, 60km south of the Erskine field. Over 500 km(2) of 3D seismic data has been purchased over the licence areas. The seismic data is being reprocessed and will then be interpreted to enable a drill or drop decision to be made on the prospects. For a variety of reasons, delivery of the reprocessed data was delayed by almost a year during 2020, so interpretation work is yet to begin; the operator therefore applied to OGA for an extension to the initial three-year licence term and it has now been extended by 12 months to September 2022. Interpretation will start as soon as data is made available.

Licence Awards in the UK 32(nd) licensing round

In December 2020 Serica was formally awarded four new blocks in the UK 32(nd) licensing round. Blocks 3/25b, 3/30, 4/26 and 9/5a are in the vicinity of the Bruce hub and include several leads which, if successful, could be tied back to Serica's existing infrastructure. The work programme does not include any commitment wells but is designed to mature these leads to drill-ready status.


Luderitz Basin: Blocks 2512A, 2513A, 2513B and 2612A (part), Serica 85% and operator

Serica Energy Namibia B.V. (the Company's subsidiary holding interests in Namibia) had an 85% interest in a Petroleum Agreement in the Luderitz Basin, offshore Namibia. Following completion of the initial licence period which had already been extended until the end of 2019 whilst partners were sought to drill an exploration well, Serica worked with the Ministry of Mines and Energy to discuss the options of a further extension or new licence application.

However, due to COVID-19 restrictions, exceptionally low oil and gas prices, and market uncertainties, these discussions were delayed. After further review Serica then elected not to progress this and made the decision to withdraw from Namibia to focus on activities in the UK North Sea which are nearer to existing infrastructure, such as drilling North Eigg in 2022 and working on the 32(nd) Round licences.

Group Proved plus Probable Reserves ("2P")

                                                 Total oil and 
                                  Oil      Gas            gas* 
                                mmbbl      bcf           mmboe 
 2P Reserves at 31 December 
 2019                            14.8    284.7            62.3 
                               ------  -------  -------------- 
 2020 production                (0.9)   (40.8)           (8.1) 
 Revisions                      (1.1)     45.3             6.8 
 2P Reserves at 31 December 
 2020                            12.8    289.2            61.0 
                               ======  =======  ============== 

*Total Group gas reserves at 31 December 2019 and 2020 have been converted to barrels of oil equivalent using a factor of 6.0 bcf per mmboe for reporting and comparison purposes. As the actual calorific values of gas produced from individual fields varies, reported production rates for each field and the total production and revisions numbers reported above do not convert precisely.

Group Proved and Probable reserves as at 31 December 2019 were based on the independent report prepared by Lloyd's Register ("LR") in accordance with the reserve definitions guidelines defined in SPE Petroleum Resources Management System 2018 ("PRMS 2018"). LR closed their consultancy division in 2020 and Serica selected RISC Advisory ("RISC") to prepare an independent report as at 31 December 2020 using the same guidelines.

Figures quoted relate to export fluids, so Fuel in Operation (reported in previous reports) is not relevant as it has already been subtracted.

Impacts of COVID-19 meant that some of the planned production enhancement work on Bruce was not carried out in 2020; as this relies on equipment upgrades which were also delayed, the work cannot be carried out in the short-term and this was reflected in the re-classification of some volumes from reserves to contingent resources (hence they do not contribute to the figures in the table above). Once this work has been reinstated in the firm work programme, these volumes will again form part of the 2P reserve.

Additional data from Rhum caused a revision to in-place gas which resulted in a material increase to the recoverable reserve estimate for the field. This offset much of the Bruce reserves reduction and Serica's 2020 production.

Aggregate reserves revisions result from several factors, including field production performance in the time between audits and prevailing commodity prices, which are used for the economic evaluation.


The following table summarises the Group's licences as at 31 December 2020.

 Licence         Block(s)               Description               Role        %        Location 
---------  -------------------  ---------------------------  -------------  -----  --------------- 
 P.090      9/9a Bruce           Bruce Field Production       Operator       99%    Northern North 
           -------------------  ---------------------------  -------------  -----  --------------- 
 P.090      9/9a Rest of Block   Development                  Operator       98%    Northern North 
             Excluding Bruce                                                         Sea 
           -------------------  ---------------------------  -------------  -----  --------------- 
 P.198      3/29a (ALL)          Rhum Field Production        Operator       50%    Northern North 
           -------------------  ---------------------------  -------------  -----  --------------- 
 P.209      9/8a Bruce           Bruce Field Production       Operator       98%    Northern North 
           -------------------  ---------------------------  -------------  -----  --------------- 
 P.209      9/8a Keith           Keith Field Production       Operator       100%   Northern North 
           -------------------  ---------------------------  -------------  -----  --------------- 
 P.209      9/8a Rest of Block   Development                  Operator       98%    Northern North 
             Excluding Bruce                                                         Sea 
             and Keith (REST) 
           -------------------  ---------------------------  -------------  -----  --------------- 
 P.276      9/9b BRUCE           Bruce Field Production       Operator       98%    Northern North 
           -------------------  ---------------------------  -------------  -----  --------------- 
 P.276      9/9c (ALL)           Bruce Field Production       Operator       98%    Northern North 
           -------------------  ---------------------------  -------------  -----  --------------- 
 P.276      9/9b Rest of Block   Development                  Operator       98%    Northern North 
             Excluding Bruce                                                         Sea 
             Unit (REST) 
           -------------------  ---------------------------  -------------  -----  --------------- 
 P.566      3/29b (ALL)          Rhum Field non-unitised      Operator       100%   Northern North 
                                  production                                         Sea 
           -------------------  ---------------------------  -------------  -----  --------------- 
 P.975      3/24b (ALL)          Rhum non-unitised            Operator       100%   Northern North 
                                  production                                         Sea 
           -------------------  ---------------------------  -------------  -----  --------------- 
 P.975      3/29d (ALL)          Rhum non-unitised            Operator       100%   Northern North 
                                  production                                         Sea 
           -------------------  ---------------------------  -------------  -----  --------------- 
 P101       23/21a Columbus      Columbus Development         Operator       50%    Central North 
                                  Area                                               Sea 
           -------------------  ---------------------------  -------------  -----  --------------- 
                                 Columbus Development                               Central North 
 P1314      23/16f                Area                        Operator       50%     Sea 
           -------------------  ---------------------------  -------------  -----  --------------- 
                                                                                    Central North 
 P57        23/26a               Erskine Field - Production   Non-operator   18%     Sea 
           -------------------  ---------------------------  -------------  -----  --------------- 
                                                                                    Central North 
 P264       23/26b               Erskine Field - Production   Non-operator   18%     Sea 
           -------------------  ---------------------------  -------------  -----  --------------- 
            30/12c, 30/13c,                                                         Central North 
 P2400       30/17h, 30/18c      Exploration                  Non-operator   20%     Sea 
           -------------------  ---------------------------  -------------  -----  --------------- 
                                                                                    Central North 
 P2402      30/19c               Exploration                  Non-operator   20%     Sea 
           -------------------  ---------------------------  -------------  -----  --------------- 
                                                                                    Northern North 
 P2501      3/24c, 3/29c         Exploration                  Operator       100%    Sea 
           -------------------  ---------------------------  -------------  -----  --------------- 
 P2506      3/25b, 3/30, 4/26,                                                      Northern North 
  *          9/5a                Exploration                  Operator       100%    Sea 
           -------------------  ---------------------------  -------------  -----  --------------- 

* Licence dated 19 January 2021


Field revenues and costs are booked for Serica's full equity interests and included within gross profits. Under the BKR deals, amounts are due to the asset vendors for net cash flow sharing (50% in 2019, 40% in 2020 and 2021) and certain other deferred payments. Estimates of these amounts were included within the fair value upon acquisition and subsequent changes are included as ' Change in fair value of BKR financial liability' within profit before tax for each reported period. Such variations are driven principally by changes in commodity sales prices and production volumes.


Serica generated a profit before taxation for 2020 of GBP12.5 million compared to GBP108.8 million for 2019. After non-cash deferred tax provisions of GBP4.8 million (2019: GBP44.8 million), profit for the year was GBP7.8 million compared to GBP64.0 million for 2019.

Results for full year 2020 were impacted by the COVID-19 crisis, which caused unprecedented falls in both oil and gas prices, and also by a 45-day shut-down of the BKR fields early in the year to secure a damaged caisson on the Bruce platform. However, the combined effects of the BKR net cash flow sharing structure and Serica's gas price hedging programme mitigated the cash impact of each substantially. Net cash flow sharing payments under the BKR deals were significantly reduced in line with lower net cash income generated during the year. In addition, Serica's gas price hedging programme effectively fixed prices for approximately one third of retained gas sales for 2020 at approximately 39 pence per therm before system fees - well above market levels. This was of particular importance during H1 when market prices averaged below 20 pence per therm.

A particular and somewhat counterintuitive feature of the strong recovery in gas prices late in 2020 was that future liabilities, valued at 31 December on the basis of forward commodity prices, increased compared to the 30 June 2020 valuation with consequent impact upon the income statement during 2H 2020. These comprised estimates of the final year of BKR net cash flow sharing and also the valuation of our gas price hedging over 2021 and 2022. As Serica retains 60% of BKR net cash flows in 2021 and 100% thereafter, it stands to benefit substantially from increased cash flows arising from strong commodity prices and this will be reflected in 2021 cash flow and net income. Equally, as no more than 25% of Serica's projected retained gas production for any period is hedged, and currently none of its oil or other liquids, the Company will also benefit during 2021 and thereafter should actual commodity pricing prove to be as strong as the basis used for valuing those hedge instrument liabilities. Nonetheless, in view of recent and ongoing volatility in commodity markets the Company's strategy remains to protect commodity pricing for a proportion of its future production.

The overall impact of this volatile year was to deliver two distinct periods. In H1, production interruption and plummeting oil and gas prices led to net operating cash flow falling to breakeven levels though this was then boosted by realised hedging income and by reduced liability valuations at 30 June 2020. In H2, stronger production and strengthening commodity prices, particularly in Q4, led to greatly improved net operating cash though this was then offset by the increased year end liability provisions described above. Earnings before interest, tax, depreciation and exploration ("EBITDAX") in H1 were GBP9.6 million and in H2 were GBP30.4 million after adjustment for unrealised hedging losses.

Sales revenues

Total product sales volumes for the year comprised approximately 386.3 million therms of gas (2019: 491.3 million therms), 1,002,000 lifted barrels of oil (2019: 1,567,100 barrels) and 71,800 metric tonnes of NGLs (2019: 85,500 metric tonnes). Overall, this represented total 2020 product sales of 22,400 boe/d (2019: 29,300 boe/d) delivering total revenue of GBP125.6 million (2019: GBP250.5 million). This consisted of BKR revenues of GBP108.8 million (2019: GBP216.6 million) and Erskine revenues of GBP16.8 million ( 2019: GBP33.9 million). Average sales prices net of system fees were 21 pence per therm (2019: 31 pence per therm), US$42.4 per barrel (2019: US$61.4 per barrel) and GBP176 per metric tonne (2019: GBP266 per metric tonne) respectively giving a combined realised sales price for lifted volumes of approximately US$20 per barrel of oil equivalent (2019: US$30 per boe). This is before gas price hedging gains detailed below.

Gross loss

The gross loss for 2020 was GBP2.9 million compared to a gross profit of GBP85.8 million for 2019. Overall cost of sales of GBP128.6 million compared to GBP164.7 million for 2019. This comprised GBP89.7 million of operating costs (2019: GBP105.1 million) and GBP38.5 million of non-cash depletion charges (2019: GBP52.6 million) plus a GBP0.3 million charge representing a reduction during the year of the opening liquids underlift position (2019: GBP7.0 million). Reductions in both operating costs and depletion charges reflected lower production volumes plus other operating cost savings, whilst depletion charges were further reduced by an increase in remaining field reserves. Operating costs comprise costs of production, processing, transportation and insurance and averaged approximately US$14.12 per boe (2019: US$12.6). An overall reduction in operating costs was achieved despite exceptional expenditures on Bruce caisson repairs and represented a reduction in underlying costs of some 10%. The increase in operating costs per barrel for the year reflected lower production volumes arising from the caisson shut-down whilst the fixed element of operating costs continued to be incurred and does not reflect an increase in the underlying trend.

Overall, despite the unprecedented fall in oil and gas sales prices and the loss of 45 days of BKR production, sales revenues for the year plus cash hedging gains covered cash operating costs for the year one and a half times over.

Operating loss before BKR fair value adjustment, net finance revenue, and tax

The operating loss for 2020 was GBP18.7 million compared to a profit of GBP87.7 million for 2019. This included GBP4.3 million of other expense from net commodity price hedging losses (2019: gain of GBP10.6 million). Realised hedging gains of GBP12.3 million (2019: GBP3.9 million) were more than offset by unrealised hedging losses of GBP16.6 million (2019: gains of GBP6.7 million). The unrealised losses reflected the surge in future gas prices at the close of 2020 and will only become fully realised should actual prices for 2021 and 2022 reach those levels. Overall, cash hedging gains realised during 2020 represented approximately US$3 per boe based upon retained volumes after adjustment for BKR cash flow sharing.

E&E asset write-offs of GBP3.7 million (2019: GBP0.1 million) principally represented the write-off of exploration costs following expiry of Serica's Namibian licence. Administrative expenses of GBP5.6 million compared to GBP6.0 million for 2019 whilst share-based payments were GBP1.9 million (2019: GBP1.1 million) and currency losses were GBP0.3 million (2019: GBP1.0 million) largely arising on US$ holdings.

Profit before taxation and profit for the year after taxation

Profit before taxation was GBP12.5 million (2019: GBP108.8 million) after a gain in the fair value of the BKR financial liability of GBP31.3 million (2019: GBP21.8 million) and negligible net finance costs (2019: GBP0.7 million). Net finance costs represent the discount unwind on decommissioning provisions less interest earned on cash deposits.

The fair value gain of GBP31.3 million arose following a downwards revision of the fair value of the balance sheet financial liability relating to consideration projected to be paid under the BKR agreements. The fair value of this liability is re-assessed at each financial period end. The most significant factors behind the downward revision in fair value in the year are the impact of lower production volumes and realised gas pricing on net cash flow payments in respect of 2020.

The 2020 taxation charge of GBP4.8 million (2019: GBP44.8 million) solely comprised a non-cash deferred tax element. As the Company continues to benefit from accumulated losses carried forward from previous years it is not currently paying cash taxes. It is nonetheless required to make provision for deferred taxes in recognition of future periods when all losses have been utilised and cash payments will commence.

Overall, this generated a profit after taxation for 2020 of GBP7.8 million compared to a profit after taxation of GBP64.0 million for 2019.


The balance sheet at 31 December 2020 demonstrates Serica's resilience during this turbulent year. This has allowed the Company to fund its significant capital expenditures on Columbus development and Rhum R3 well work from its cash resources without recourse to borrowing and also to pay its maiden cash dividend of GBP8.0 million.

A reduction in exploration and evaluation assets from GBP3.7 million in 2019 to GBP1.0 million at 31 December 2020 reflected a GBP3.7 million write-off of past expenditures (including GBP3.5 million from Namibia) following licence relinquishment partially offset by GBP1.0 million of new expenditure on UK licences during 2020.

Total property, plant and equipment decreased from GBP325.4 million at year end 2019 to GBP311.1 million at 31 December 2020 after depletion charges for 2020 of GBP38.5 million (2019: GBP52.6 million), asset revisions of GBP1.1 million (2019: GBP0.6 million) and other charges of GBP0.2 million (2019: GBP0.2 million) partly offset by capital expenditure on Columbus and Rhum during 2020 of GBP25.5 million (2019: Columbus GBP4.5 million, other GBP0.2 million). Depletion charges represent the allocation of field capital costs over the estimated producing life of each field and principally comprise costs of asset acquisitions.

An inventories balance of GBP4.6 million at 31 December 2020 showed little change from GBP4.7 million at the end of 2019. An increase in trade and other receivables from GBP35.9 million at the end of 2019 to GBP41.3 million at 31 December 2020 largely reflected higher prices for December gas sales plus increased capital expenditure amounts recoverable from field partners. The derivative financial asset of GBP6.9 million at year end 2019 had become a derivative financial liability of GBP9.7 million at 31 December 2020. This represents the valuation of gas price hedges in place at the respective year ends and the consequent amounts projected to be either due or payable based upon futures pricing prevailing at those points. Year end 2020 reflected particularly strong futures pricing which, should it be realised, would deliver greatly increased gas sales revenues during 2021 and 2022.

The reduction in cash balances from GBP101.8 million at 31 December 2019 to GBP89.3 million at 31 December 2020 reflected cash flow from operations offset by both the significant capital expenditures of GBP25.5 million and also the payment of a GBP8.0 million dividend during the year.

The increase in current trade and other payables to GBP31.1 million at 31 December 2020 from GBP24.6 million at the end of 2019 arose largely due to a high level of accruals related to the Rhum R3 well work.

A final cash dividend for 2019 of 3 pence per share (2018: nil) was proposed in April 2020 and approved at the annual general meeting on 25 June 2020. The dividend was paid in July 2020.

Current financial liabilities of GBP53.6 million (31 December 2019: GBP45.4 million) and non-current financial liabilities of GBP48.8 million (31 December 2019: GBP110.1 million) comprise total remaining amounts projected to be paid under the BKR acquisition agreements.

The current liability comprises amounts estimated to fall due over the final twelve months of the net cash flow sharing arrangements, a fixed payment of GBP16 million contingent upon the outcome of the Rhum R3 well work and contingent consideration in respect of Rhum field performance during 2021. Amounts due under the net cash flow sharing arrangements are based on forward projections of production volumes and sales prices. Subsequent payments will be calculated on volumes and prices actually achieved in 2021. The non-current liability comprises deferred consideration in respect of BKR decommissioning and oil linefill. Under arrangements for those BKR field interests acquired from BP, Total E&P and BHP, decommissioning liabilities were retained by the vendors with Serica liable to pay deferred consideration equivalent to 30% of the actual costs of decommissioning net of tax recovered by them.

The overall reduction in financial liabilities of GBP53.1 million during 2020 comprised cash amounts of GBP21.8 million paid in the period and GBP31.3 million released through the income statement. This release arose due to lower than previously forecast net cash flow sharing payments in respect of 2020 partially offset by a re-assessment of the estimated fair value of projected remaining payments as at 31 December 2020.

Non-current provisions of GBP22.8 million have been made in respect of decommissioning liabilities for the Bruce and Keith interests acquired from Marubeni (31 December 2019: GBP22.6 million). These were not subject to the same deferred consideration arrangements as applied for those field interests acquired from BP, Total E&P and BHP described above. No provision is included for decommissioning liabilities related to the Erskine facilities as these liabilities are retained by BP up to a cap which is not projected to be exceeded.

The deferred tax liability of GBP80.6 million at 31 December 2020 has increased from GBP75.8 million at year end 2019 and reflects accounting provisions expected to be released against future tax charges once the Group's tax losses have been fully utilised.

Overall, net assets have increased from GBP198.0 million at year end 2019 to GBP199.8 million at 31 December 2020 after payment of GBP8.0 million in dividends.

The increase in share capital from GBP181.4 million to GBP181.6 million arose from shares issued following the exercise of share options and shares issued under an employee share scheme, whilst the increase in other reserves from GBP17.8 million to GBP19.7 million arose from share-based payments related to share option awards.


Current cash position and price hedging

At 31 December 2020 the Group held cash and cash equivalents of GBP89.3 million (2019: GBP101.8 million). This is after capital investments during the year of GBP26.6 million and dividend payments of GBP8.0 million plus monthly net cash flow sharing payments and other BKR consideration totalling GBP11.4 million and GBP10.4 million respectively. Amounts due under the net cash flow sharing arrangements have fallen from 50% of BKR net operating cash flows for 2019 to 40% for 2020. This leaves one more year of payments at 40% and then zero thereafter. The GBP12.1 million of total cash and cash equivalents held in a restricted account against letters of credit issued in respect of certain decommissioning liabilities as at 31 December 2020 (2019: GBP12.1 million) was reduced to GBP6.4 million effective 1 January 2021 due to an upgrade in reserves and further extension of BKR field life.

At 31 December 2020 Serica held gas price swaps covering 167,000 therms per day for H1 2021 and 192,000 therms per day for H2 2021 at average prices of 37 pence per therm and 36 pence per therm respectively. It further held gas price swaps covering 200,000 therms per day for H1 2022 and 50,000 therms per day for H2 2022 at average prices of 40 pence per therm and 37 pence per therm respectively. At 31 December 2020 a cash margin call of GBP1.8 million had been paid to a hedge counterparty as security against settlement of future hedge instruments (2019: nil).

In 2021 to date, Serica has obtained additional gas price swaps covering 50,000 therms per day for H1 2022, 100,000 therms per day for H2 2022 and 50,000 therms per day for Q1 2023 at average prices of 46, 41 and 50 pence per therm respectively.

Following onset of the COVID-19 crisis in March last year, cash projections were run to examine the potential impact of extended low oil and gas prices as well as possible production interruptions and the situation was kept under review thereafter. Some 80% of Serica's production is gas with exposure to price falls partially mitigated by price hedging now extending up to Q1 2023. The BKR net cash flow sharing arrangements and structuring of elements of Rhum deferred consideration further mitigate the impact of low sales prices and any production interruptions upon net income to end 2021. This allied to the fact that Serica currently has substantial cash resources, no borrowings and relatively low operating costs per boe means that the Company is well placed to withstand such risks and its capital commitments can be funded from existing cash resources.

Field and other capital commitments

There are no existing capital commitments on the Erskine producing field and net production revenues are expected to cover all ongoing field expenditures. Serica's share of decommissioning costs relating to its 18% Erskine field interest will be met by BP up to a level of GBP31.3 million, adjusted for inflation, and Serica's current estimate of such costs is below this level.

There are no significant existing capital commitments on the BKR producing fields other than an estimated GBP11 million net to Serica outstanding at 31 December 2020 on the Rhum R3 well work, expected to be completed during Q2 2021. Potential further programmes to enhance current production profiles and extend field life are under consideration. Net revenues from Serica's share of income from the BKR fields, after net cash flow sharing payments, is expected to cover Serica's retained share of ongoing field expenditures as well as other contingent or deferred consideration due under the respective BKR acquisition agreements set out below.

The Columbus development is underway with first gas expected in Q4 2021. Total development expenditure net to Serica's share outstanding at 31 December 2020 is estimated at approximately GBP15 million.

The Group has no significant exploration commitments apart from a well on the North Eigg prospect to be drilled within three years of the 1 January 2020 licence award.

BKR asset acquisitions

On 30 November 2018 Serica completed the four BKR acquisitions. The following elements of consideration were outstanding at 31 December 2020:

-- A contingent payment of GBP16.0 million is due to BP Exploration Operating Company ("BPEOC") upon bringing the Rhum R3 well onto production and achieving a minimum cumulative 90 days of gas production at a defined level.

-- A contingent payment of up to GBP7.7 million is due to BPEOC based upon Rhum 2021 average field production and commodity sales prices in the year. The payment made in respect of 2019 was GBP2.6 million whilst the payment calculated in respect of 2020 and made in Q1 2021 was GBP1.0 million. There will be a final calculation of the combined average performance covering years 2019 to 2021 and applied to the total potential consideration for the three years of up to GBP23.1 million. Any difference between this calculation and cumulative payments to-date will then be settled.

-- In addition, Serica will pay contingent cash consideration to BPEOC, Total E&P and BHP calculated as 40% of 2021 net cash flows resulting from the respective field interests acquired from those companies. Such amounts will be paid by Serica pre-tax on a monthly basis and then offset by Serica against its own tax liabilities.

-- BP, Total E&P and BHP will retain liability, in respect of the field interests Serica acquired from each of them, for all the costs of decommissioning those facilities that existed at the date of completion. Serica will pay deferred consideration equal to 30% of actual future decommissioning costs, reduced by the tax relief that each of BP, Total E&P and BHP receives on such costs. Staged prepayments against such projected amounts will commence in 2022 and be spread over the remaining years before cessation of field production.

-- Serica will pay to each of BP, Total E&P and BHP, deferred consideration equal to 90% of their respective shares of the realised value of oil in the Bruce pipeline at the end of field life.


Asset values and impairment

At 31 December 2020, Serica's market capitalisation stood at GBP308.0 million based upon a share price of 115 pence which exceeded the net asset value of GBP199.8 million. By 13 April the Company's market capitalisation has risen to GBP320.5 million.


Serica, like all companies in the oil and gas industry, operates in an environment subject to inherent risks and uncertainties. The Board regularly considers the principal risks to which the Group is exposed and monitors any agreed mitigating actions. The overall strategy for the protection of shareholder value against these risks is to retain a broad portfolio of assets with varied risk/reward profiles, to apply prudent industry practice, to carry insurance, where both available and cost effective, and to retain adequate working capital.

Following completion of the four BKR acquisitions in 2018, Serica has built a strong working capital reserve. This is available to respond to a range of risks including production interruptions, severe commodity price falls and unexpected costs. To supplement this the Company carries business interruption insurance to mitigate the impact of deferred or lost revenues over sustained periods of production shut-in beyond an initial 60 days, where caused by events covered under such policies. The Company also uses price hedging instruments to help manage field revenues and will continue to seek cost effective opportunities to add to its existing hedge position. These currently cover up to 25% of the Company's retained share of projected 2021 and 2022 gas production.

The principal risks currently recognised and the mitigating actions taken by the management are as follows:

 Investment Returns: Management seeks to invest in a portfolio 
  of exploration, development and producing acreage capable 
  of delivering returns to shareholders through acquisitions 
  of producing assets to which it can add further value and 
  through the discovery and exploitation of commercial reserves. 
  Delivery of this business model carries a number of key risks. 
 Risk                                 Mitigation 
 Stock market support may be 
  eroded lowering investor appetite          *    Management regularly communicates its strategy to 
  and obstructing fundraising                     shareholders 
                                             *    Focus is placed on building a diverse and resilient 
                                                  asset portfolio capable of offering prospectivity 
                                                  throughout the business cycle 
 Each investment carries its 
  own risk profile and no outcome            *    Management aims to avoid over-exposure to individual 
  can be certain                                  assets, to identify the associated risks objectively 
                                                  and mitigate where practical 
 Operations: Operations may not go according to plan leading 
  to damage, pollution, cost overruns or poor outcomes. 
 Risk                                                   Mitigation 
 Production may be interrupted 
  generating significant revenue                    *    The Company seeks to diversify its revenue streams 
  loss whilst costs continue to 
  be incurred 
                                                    *    Management determines and retains an appropriate 
                                                         level of working capital 
                                                    *    Business interruption cover is carried when cost 
 Third party offtake routes may 
  experience restrictions or interruptions          *    The Group aims to diversify its exposure to offtake 
  and full availability may depend                       routes where possible though all of its oil 
  upon sustained production from                         production currently uses the FPS system 
  other fields in the system 
                                                    *    The Group carries business interruption cover 
 The Company is reliant upon 
  its IT systems to maintain operations             *    The Group employs specialist support 
  and communications 
                                                    *    Protection against external intrusion is incorporated 
                                                         within the system and tested regularly 
 Personnel: The Group relies upon a pool of experienced and 
  motivated personnel to conduct its operations and execute 
  successful investment strategies 
 Risks                                   Mitigation 
 Key personnel may be lost to 
  other companies                               *    The Remuneration Committee regularly evaluates 
                                                     incentivisation schemes to ensure they remain 
                                                *    The Group seeks to build depth of experience in all 
                                                     key functions to ensure continuity 
 Personal safety may be at risk 
  in demanding operating environments,          *    A culture of safety is encouraged throughout the 
  typically offshore                                 organisation 
                                                *    Responsible personnel are designated at all 
                                                     appropriate levels 
                                                *    The Group maintains up-to-date emergency response 
                                                     resources and procedures 
 Political and commercial environment: World share and commodity 
  markets and political environments continue to be volatile 
  Risk                                 Mitigation 
 Sanctions imposed by the U.S. 
  government may threaten continuing          *    An OFAC Licence has been obtained which has enabled 
  production from the Rhum field                   continuing production from Rhum 
  and licences are required to 
  be renewed periodically 
                                              *    Serica initiates the renewal process well in advance 
                                                   of the specified date 
 The UKCS licensing regime under 
  which Serica's operational rights           *    Management maintains regular communication with 
  and obligations are defined                      regulatory authorities 
  may be subject to future change 
                                              *    The Company aligns its standards and objectives with 
                                                   government policies as closely as possible 
 Volatile commodity prices mean 
  that the Group cannot be certain            *    Planning and forecasting considers downside price 
  of the future sales value of                     scenarios 
  its products 
                                              *    Oil and gas floor price hedging may be utilised where 
                                                   deemed cost effective 
                                              *    Price mitigation strategies may be employed at the 
                                                   point of major capital commitment 
 COVID-19: The impact of the virus has significantly affected 
  the majority of global activities and markets. The full extent 
  and duration of the crisis remains uncertain. 
  Risk                                 Mitigation 
 The Company's personnel may 
  be at risk from catching the                      *    The Company has instituted recommended safe practices 
  virus                                                  and will maintain these as necessary 
                                                    *    Serica has instituted a programme of working from 
                                                         home where feasible and temporarily closed its London 
                                                         and Aberdeen offices 
 The spread of infection and 
  associated counter measures                       *    The Company has reduced the number of staff working 
  may interrupt offshore operations                      offshore to a safe minimum 
                                                    *    Management encourages safe practices travelling to 
                                                         and from the platform and mandates additional 
                                                         precautions whilst offshore 
 The continued operation of Serica's 
  fields may be adversely affected            *    Serica carries a working capital reserve to cover 
  by interruptions to operations                   such eventualities 
  of fields and infrastructure 
                                              *    Serica works with the regulatory bodies and 
                                                   infrastructure owners to identify and mitigate any 
                                                   such risks 

ESG strategy and risk management

Details of ESG strategies directed towards reducing carbon emissions and contributing to government net zero targets are described on pages 48 and 49 and also in a separate ESG Report which will be issued in conjunction with publication of the 2020 Annual Report.

Serica has reviewed guidance issued by the Task Force on Climate-related Financial Disclosures ("TCFD") with regard to the identification, management and reporting of climate-related financial risks. The Company is in the process of developing its capabilities to report under TCFD guidance.

Management considers climate-related strategic and financial risks in both its existing asset portfolio and future business growth including potential acquisitions. This includes consideration of the potential impact of both transition and physical risks.

Key Performance Indicators ("KPIs")

The Company's main business is the acquisition, development and production of commercially attractive oil and gas reserves in a safe and environmentally sensitive manner. This is achieved both through pursuing the full cycle of exploration, discovery, development and production and also through acquiring existing reserves where management believe that further value can be added.

Operational and financial performance is tracked through the following KPI's whose progress is covered within the Review of Operations and Finance Review within this strategic report:

   --      Daily production volumes 
   --      Production costs per barrel of oil equivalent 
   --      Realised sales income per barrel of oil equivalent 

HSE performance is tracked through the following KPI's whose progress is covered within the ESG Report to be issued along with the 2020 Annual Report:

   --      Recordable incidents and injuries 
   --      Workforce engagement in HSE 
   --      Quality of discharges to water and air 

ESG performance is tracked through the following KPI's whose progress is covered within the ESG Report to be issued along with the 2020 Annual Report:

   --      Carbon intensity 
   --      Flare volumes 
   --      Workforce engagement in ESG 
   --      Waste volumes generated 
   --      Diversity of personnel 

Elements falling within each of the above categories are included within annual incentive schemes for all Group employees.

The Company tracks its new business development objectives through the building of a risk-balanced portfolio of full cycle assets. Specific KPI's are not applied due to the range of different potential acquisition targets. However, successful delivery will add to future production volumes and net realised income.

Further information upon the Company's HSE and ESG policies and delivery can be found in an updated ESG Report which will be issued along with the 2020 Annual Report.

Section 172 statement

The Directors' statement under Section 172 of the Companies Act 2006 is included on pages 45 to 47.

Additional Information

Additional information relating to Serica, can be found on the Company's website at and on SEDAR at

The Strategic Report has been approved by the Board of Directors.

On behalf of the Board

Mitch Flegg

Chief Executive Officer

14 April 2021

Forward Looking Statements

This disclosure contains certain forward looking statements that involve substantial known and unknown risks and uncertainties, some of which are beyond Serica Energy plc's control, including: the impact of general economic conditions where Serica Energy plc operates, industry conditions, changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced, increased competition, the lack of availability of qualified personnel or management, fluctuations in foreign exchange or interest rates, stock market volatility and market valuations of companies with respect to announced transactions and the final valuations thereof, and obtaining required approvals of regulatory authorities. Serica Energy plc's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward looking statements and, accordingly, no assurances can be given that any of the events anticipated by the forward looking statements will transpire or occur, or if any of them do so, what benefits, including the amount of proceeds, that Serica Energy plc will derive therefrom.

 Serica Energy plc 
 Group Income Statement 
 For the year ended 31 December 
  Registered Number: 5450950 
  Balance Sheet 
  As at 31 December 
                                                                  2020        2019 
                                                      Note      GBP000      GBP000 
 Continuing operations 
 Sales revenue                                           4     125,641     250,533 
 Cost of sales                                           5   (128,560)   (164,748) 
 Gross (loss)/profit                                           (2,919)      85,785 
 Other (expense)/income                                  6     (4,276)      10,618 
 Pre-licence costs                                                   -       (566) 
 E&E asset write-offs                                   14     (3,725)        (80) 
 Administrative expenses                                       (5,579)     (5,963) 
 Foreign exchange loss                                           (344)     (1,020) 
 Share-based payments                                   27     (1,862)     (1,094) 
 Operating (loss)/profit before net finance revenue           (18,705)      87,680 
 and tax 
 Change in fair value of BKR financial liabilities      22      31,296      21,771 
 Finance revenue                                         9         465         571 
 Finance costs                                          10       (508)     (1,252) 
 Profit before taxation                                         12,548     108,770 
 Taxation charge for the year                         11a)     (4,769)    (44,750) 
 Profit for the year                                             7,779      64,020 
                                                            ==========  ========== 
 Earnings per ordinary share - EPS 
 Basic EPS on profit for the year (GBP)                 12        0.03        0.24 
 Diluted EPS on profit for the year (GBP)               12        0.03        0.23 

Group Statement of Comprehensive Income

There are no other comprehensive income items other than those passing through the income statement.

Serica Energy plc

Registered Number: 5450950

Balance Sheet

As at 31 December

                                               Group               Company 
                                                2020        2019      2020       2019 
                                    Note      GBP000      GBP000    GBP000     GBP000 
 Non-current assets 
 Exploration & evaluation assets    14         1,043       3,652         -          - 
 Property, plant and equipment      15       311,125     325,404       215        387 
 Investments in subsidiaries        16             -           -   105,256    105,256 
                                             312,168     329,056   105,471    105,643 
                                          ----------  ----------  --------  --------- 
 Current assets 
 Inventories                        17         4,633       4,671         -          - 
 Trade and other receivables        18        41,329      35,906   162,291     93,330 
 Derivative financial asset         19             -       6,880         -          - 
 Cash and cash equivalents          20        89,333     101,825     7,078     11,348 
                                          ----------  ----------  --------  --------- 
                                             135,295     149,282   169,369    104,678 
                                          ----------  ----------  --------  --------- 
 TOTAL ASSETS                                447,463     478,338   274,840    210,321 
                                          ----------  ----------  --------  --------- 
 Current liabilities 
 Trade and other payables           21      (31,121)    (24,600)     (995)    (1,738) 
 Derivative financial liability     19       (9,691)           -         -          - 
 Financial liabilities              22      (53,634)    (45,351)         -          - 
 Provisions                         23       (1,002)     (1,848)         -          - 
 Non-current liabilities 
 Financial liabilities              22      (48,770)   (110,108)         -          - 
 Provisions                         23      (22,799)    (22,590)         -          - 
 Deferred tax liability             11d)    (80,600)    (75,831)         -          - 
                                          ----------  ----------  --------  --------- 
 TOTAL LIABILITIES                         (247,617)   (280,328)     (995)    (1,738) 
                                          ----------  ----------  --------  --------- 
 NET ASSETS                                  199,846     198,010   273,845    208,583 
                                          ==========  ==========  ========  ========= 
 Share capital                      25       181,606     181,385   153,907    153,686 
 Merger reserve                     16             -           -    88,088     88,088 
 Other reserve                                19,680      17,818    19,680     17,818 
 Accumulated (deficit)/funds                 (1,440)     (1,193)    12,170   (51,009) 
 TOTAL EQUITY                                199,846     198,010   273,845    208,583 
                                          ==========  ==========  ========  ========= 

The profit for the Company was GBP71.2 million for the year ended 31 December 2020 (2019: loss of GBP2.6 million). In accordance with the exemption granted under section 408 of the Companies Act 2006 a separate income statement for the Company has not been presented.

Approved by the Board on 14 April 2021

   Antony Craven Walker                            Mitch Flegg 
   Executive Chairman                               Chief Executive Officer 

Serica Energy plc

Statement of Changes in Equity

For the year ended 31 December

 Group                                                   Other    Accum'd 
                               Note   Share capital    reserve    deficit     Total 
                                             GBP000     GBP000     GBP000    GBP000 
 At 1 January 2019                          180,294     16,724   (65,213)   131,805 
 Profit for the year                              -          -     64,020    64,020 
                                     --------------  ---------  ---------  -------- 
 Total comprehensive income                       -          -     64,020    64,020 
 Share-based payments           27                -      1,094          -     1,094 
 Issue of share capital         25            1,091          -          -     1,091 
 At 31 December 2019                        181,385     17,818    (1,193)   198,010 
 Profit for the year                              -          -      7,779     7,779 
 Total comprehensive income                       -          -      7,779     7,779 
 Share-based payments           27                -      1,862          -     1,862 
 Issue of share capital         25              221          -          -       221 
 Dividend paid                  13                -          -    (8,026)   (8,026) 
 At 31 December 2020                        181,606     19,680    (1,440)   199,846 
                                     ==============  =========  =========  ======== 
                                  Share     Merger      Other     Accum'd 
   Company                      capital    reserve    reserve      funds/     Total 
                                 GBP000     GBP000     GBP000      GBP000    GBP000 
 At 1 January 2019              152,595     88,088     16,724    (48,426)   208,981 
 Loss for the year                    -          -          -     (2,583)   (2,583) 
                              ---------  ---------  ---------  ----------  -------- 
 Total comprehensive income           -          -          -     (2,583)   (2,583) 
 Share-based payments (note 
  27)                                 -          -      1,094           -     1,094 
 Issue of share capital 
  (note 25)                       1,091          -          -           -     1,091 
 At 31 December 2019            153,686     88,088     17,818    (51,009)   208,583 
 Profit for the year                  -          -          -      71,205    71,205 
                              ---------  ---------  ---------  ----------  -------- 
 Total comprehensive income           -          -          -      71,205    71,205 
 Share-based payments (note 
  27)                                 -          -      1,862           -     1,862 
 Issue of share capital 
  (note 25)                         221          -          -           -       221 
 Dividend paid (note 13)              -          -          -     (8,026)   (8,026) 
 At 31 December 2020            153,907     88,088     19,680      12,170   273,845 
                              =========  =========  =========  ==========  ======== 
 Serica Energy plc 
 Cash Flow Statement 
 For the year ended 31 December 
                                                       Group               Company 
                                                        2020       2019       2020      2019 
                                             Note     GBP000     GBP000     GBP000    GBP000 
 Operating activities: 
 Profit/(loss) for the year                            7,779     64,020     71,205   (2,583) 
 Adjustments to reconcile profit 
  for the year 
 to net cash flow from operating 
 Taxation charge                                       4,769     44,750          -         - 
 Change in BKR fair value liability                 (31,296)   (21,771)          -         - 
 Net finance costs/(income)                               43        681       (20)     (176) 
 Depreciation and depletion                           38,495     52,631          -         - 
 Oil and NGL over/underlift                              342      6,969          -         - 
 E&E asset write-offs                                  3,725         80          -         - 
 Unrealised hedging losses/(gains)                    16,571    (6,742)          -         - 
 Write-back of loans and investments                       -          -          -         - 
 Share-based payments                                  1,862      1,094      1,862     1,094 
 Other non-cash movements                                629        638        182     (149) 
 (Increase)/decrease in trade and 
  other                                              (5,423)      6,147   (74,906)     1,100 
 Decrease/(increase) in inventories                       38      (386)          -         - 
 Increase/(decrease) in trade and 
  other                                                6,537   (11,056)      (438)   (1,690) 
                                                   ---------  ---------  ---------  -------- 
 Net cash in/(out)flow from operations                44,071    137,055    (2,115)   (2,404) 
                                                   ---------  ---------  ---------  -------- 
 Investing activities: 
 Interest received                                       465        571         57       225 
 Purchase of E&E assets                              (1,116)      (549)          -         - 
 Purchase of property, plant and 
  equipment                                         (25,530)    (4,736)          -         - 
 Cash outflow from business combination        22   (21,759)   (57,259)          -         - 
 Cash outflow arising on asset acquisitions                -          -          -         - 
 Changes in term deposits                                  -      1,000          -     1,000 
 Receipts/(payments) from Group 
  subsidiaries                                             -          -      5,945   (8,196) 
 Net cash flow from investing activities            (47,940)   (60,973)      6,002   (6,971) 
                                                   ---------  ---------  ---------  -------- 
 Financing activities: 
 Repayments of borrowings                    22             -   (15,673)           -         - 
 Payments of lease liabilities               28         (133)      (178)       (133)     (178) 
 Proceeds from issue of shares               25           221      1,091         221     1,091 
 Dividends paid                              13       (8,026)          -     (8,026)         - 
 Finance costs paid                                      (56)      (962)        (37)      (49) 
 Net cash flow from financing activities              (7,994)   (15,722)     (7,975)       864 
                                                  -----------  ---------  ----------  -------- 
 Net (decrease)/increase in cash 
  and cash equivalents                        26     (11,863)     60,360     (4,088)   (8,511) 
 Effect of exchange rates on cash 
  and cash 
 equivalents                                 26         (629)      (638)       (182)       149 
 Cash and cash equivalents at 1 
  January                                    26       101,825     42,103      11,348    19,710 
 Cash and cash equivalents at 31 
  December                                   26        89,333    101,825       7,078    11,348 
                                                  ===========  =========  ==========  ======== 

Serica Energy plc

Notes to the Financial Statements

1. Authorisation of the Financial Statements and Statement of Compliance with International Accounting Standards in conformity with the requirements of the Companies Act 2006

These are not the statutory accounts of the Company prepared in accordance with the Companies Act. The Group's and Company's financial statements for the year ended 31 December 2020 were authorised for issue by the Board of Directors on 14 April 2021 and the balance sheets were signed on the Board's behalf by Antony Craven Walker and Mitch Flegg. Serica Energy plc is a public limited company incorporated and domiciled in England & Wales with its registered office at 48 George Street, London, W1U 7DY. The principal activity of the Company and the Group is to identify, acquire and subsequently exploit oil and gas reserves. Its current activities are located in the United Kingdom. The Company's ordinary shares are traded on AIM.

The Group's financial statements have been prepared in accordance with International Accounting Standards in conformity with the requirements of the Companies Act 2006 as they apply to the financial statements of the Group for the year ended 31 December 2020. The Company's financial statements have been prepared in accordance with International Accounting Standards in conformity with the requirements of the Companies Act 2006 as they apply to the financial statements of the Company for the year ended 31 December 2020 and as applied in accordance with the provisions of the Companies Act 2006. The principal accounting policies adopted by the Group and by the Company are set out in note 2.

The Company has taken advantage of the exemption provided under section 408 of the Companies Act 2006 not to publish its individual income statement and related notes. The profit dealt with in the financial statements of the parent Company was GBP71,205,000 (2019: loss GBP2,583,000).

2. Accounting Policies

Basis of Preparation

The accounting policies which follow set out those policies which apply in preparing the financial statements for the year ended 31 December 2020.

The Group and Company financial statements have been prepared on a historical cost basis and following the change in functional and presentational currency from US$ to GBP sterling with effect from 1 January 2019 are presented in GBP sterling. All values are rounded to the nearest thousand pounds (GBP000) except when otherwise indicated.

Going Concern

The Directors are required to consider the availability of resources to meet the Group's liabilities for the foreseeable future. The financial position of the Group, its cash flows and capital commitments are described in the Financial Review above.

At 31 December 2020 the Group held cash and term deposits of GBP89.3 million which had increased to approximately GBP93.6 million by 31 March 2021 after payment of GBP4.6 million of margin calls related to outstanding gas price hedging. The balance at 31 March 2021 included GBP6.4 million of restricted funds. The bulk of contingent and deferred consideration due under the BKR acquisition agreements is related to future successful field performance and consequently will be either reduced or deferred in the event of lower net cash generation from either production interruptions or lower oil and gas prices.

The Group regularly monitors its cash, funding and liquidity position. Near term cash projections are revised and underlying assumptions reviewed, generally monthly, and longer-term projections are also updated regularly. Downside price and other risking scenarios are considered. In addition to commodity sales prices the Group is exposed to potential production interruptions and these are also considered under such scenarios. Serica's acquisitions to-date have been structured to reduce post-completion risk and, following completion of the BKR transactions, management has given priority to building a strong cash reserve which can respond to different types of risk. For the purposes of the Group's going concern assessment we have reviewed cash projections for the period ending 30 June 2022, the 'going concern period'.

Following onset of the COVID-19 crisis, we stress tested future cash flow forecasts for the Group to evaluate the impact of plausible downside scenarios. The environment has since improved but Serica continues to model the downside impact of production interruption and lower than forecast commodity prices. These include scenarios that reflect extended low oil and gas prices over 2021 and 2022, which are lower than current forecasts and forward prices, and a three-month production shut-in to reflect potential operational or COVID-19 related issues that could impact the Group. Under such scenarios we retain sufficient liquidity in our business. We have also performed a reverse stress test to assist our judgement which is designed to model the extreme price conditions that would have to exist such that the Group required additional cash resources or had to rely upon additional cash resources within the going concern period.

The impact of low gas prices is partially mitigated by price hedging up to 31 March 2023 for a proportion of projected gas sales volumes, which deliver monthly cash inflows to Serica where market prices are lower than 31 up to 50 pence per therm with the price variations reflecting the periods covered. The BKR net cash flow sharing arrangements, which run to end 2021, vary in line with actual net cash generated and therefore the impact of lower sales prices and production volumes will be shared by Serica and the previous BKR owners.

Serica currently has no borrowings, relatively low operating costs per boe and its limited capital commitments can be funded from existing cash resources. Additionally, we have implemented operating cost reductions which provide further resilience against softer commodity prices. In particular, Serica has reduced the level of offshore personnel through the COVID-19 period by deferring non-essential work and has facilitated remote working wherever possible.

After making enquiries and having taken into consideration the above factors, the Directors have reasonable expectation that the Group has adequate resources to continue in operational existence for the going concern period. Accordingly, they continue to adopt the going concern basis in preparing the financial statements

Use of judgement and estimates and key sources of estimation uncertainty

The preparation of financial statements in conformity with International Accounting Standards in conformity with the requirements of the Companies Act 2006 requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities as well as the disclosure of contingent assets and liabilities at the balance sheet date and the reported amounts of revenues and expenses during the reporting period. Estimates and judgements are continuously evaluated and are based on management's experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. Actual outcomes could differ from these estimates.

The key sources of estimation uncertainty that have a significant risk of causing material adjustment to the amounts recognised in the financial statements are: determining the fair value of contingent consideration, determining the fair value of property, plant and equipment on a business combination, decommissioning provisions, the assessment of commercial reserves, the impairment of the Group and Company's assets (including oil and gas development assets and Exploration and Evaluation "E&E" assets), and the recoverability of deferred tax assets.

Determining the fair value of contingent consideration on BKR acquisitions

The Group determined the fair value of initial contingent consideration payable based on discounted cash flows at the time of the acquisition in 2018, calculated for each separate component of the contingent consideration. The same models and assumptions were used in the calculation of the fair value of property, plant and equipment arising on the business combination. Any cash flows specific to the contingent consideration also reflect applicable commercial terms and risks. In calculating the fair value of contingent consideration on the BKR acquisitions payable as at 31 December 2020, assumptions underlying the calculation were updated from 2019. These included updated commodity prices, production profiles, future opex, capex and decommissioning cost estimates, discount rates, proved and probable reserves estimates and risk assessments. For further details including sensitivities of the calculation to changes in input variables, see note 22.

Decommissioning provision

Amounts used in recording a provision for decommissioning are estimates based on current legal and constructive requirements and current technology and price levels for the removal of facilities and plugging and abandoning of wells. Due to changes in relation to these items, the future actual cash outflows in relation to decommissioning are likely to differ in practice. To reflect the effects due to changes in legislation, requirements and technology and price levels, the carrying amounts of decommissioning provisions are reviewed on a regular basis. The effects of changes in estimates do not give rise to prior year adjustments and are dealt with prospectively. While the Group uses its best estimates and judgement, actual results could differ from these estimates (see note 23).

Assessment of commercial oil and gas reserves

Management is required to assess the level of the Group's commercial reserves together with the future expenditures to access those reserves, which are utilised in determining the amortisation and depletion charge for the period and assessing whether any impairment charge is required. The Group employs independent reserves specialists who periodically assess the Group's level of commercial reserves by reference to data sets including geological, geophysical and engineering data together with reports, presentation and financial information pertaining to the contractual and fiscal terms applicable to the Group's assets. In addition, the Group undertakes its own assessment of commercial reserves and related future capital expenditure by reference to the same data sets using its own internal expertise.

Assessment of the recoverable amount of intangible and tangible assets

The Group monitors internal and external indicators of impairment relating to its intangible and tangible assets, which may indicate that the carrying value of the assets may not be recoverable. The assessment of the existence of indicators of impairment in E&E assets involves judgement, which includes whether licence performance obligations can be met within the required regulatory timeframe, whether management expects to fund significant further expenditure in respect of a licence, and whether the recoverable amount may not cover the carrying value of the assets. For development and production assets judgement is involved when determining whether there have been any significant changes in the Group's oil and gas reserves.

The Group determines whether E&E assets are impaired at an asset level and in regional cash generating units ('CGUs') when facts and circumstances suggest that the carrying amount of a regional CGU may exceed its recoverable amount. As recoverable amounts are determined based upon risked potential, or where relevant, discovered oil and gas reserves, this involves estimations and the selection of a suitable pre-tax discount rate relevant to the asset in question. The calculation of the recoverable amount of oil and gas development and production properties involves estimating the net present value of cash flows expected to be generated from the asset in question. Future cash flows are based on assumptions on matters such as estimated proven and probable oil and gas reserve quantities and commodity prices. The discount rate applied is a pre-tax rate which reflects the specific risks of the country in which the asset is located.

Management is required to assess the carrying value of investments in subsidiaries in the parent company balance sheet for impairment by reference to the recoverable amount. This requires an estimate of amounts recoverable from oil and gas assets within the underlying subsidiaries (see note 16).

A review was performed for any indication that the value of the Group's oil and gas assets may be impaired at the balance sheet date of 31 December 2020 in accordance with the stated policy and no impairment triggers were noted.

Deferred taxation

Deferred tax assets, including those arising from unutilised tax losses, require management to assess the likelihood that the Group will generate sufficient taxable profits in future periods, in order to utilise recognised deferred tax assets. Assumptions about the generation of future taxable profits depend on management's estimates of future cash flows. These estimates are based on forecast cash flows from operations (which are impacted by production and sales volumes, oil and natural gas prices, reserves, operating costs, decommissioning costs, capital expenditure, dividends and other capital management transactions) and judgement about the application of existing tax laws. To the extent that actual events differ significantly from estimates, the ability of the Group to realise deferred tax assets could be impacted.

Basis of Consolidation

The consolidated financial statements include the accounts of Serica Energy plc (the "Company") and its wholly owned subsidiaries Serica Holdings UK Limited, Serica Energy Holdings B.V., Serica Energy (UK) Limited, Serica Glagah Kambuna B.V., Serica Sidi Moussa B.V., Serica Energy Slyne B.V., Serica Energy Rockall B.V., Serica Energy Namibia B.V., Serica Energy Corporation, Asia Petroleum Development Limited, Petroleum Development Associates (Asia) Limited and Petroleum Development Associates (Lematang) Limited. Together these comprise the "Group".

All inter-company balances and transactions have been eliminated upon consolidation.

Foreign Currency Translation

The functional and presentational currency of Serica Energy plc and its subsidiaries is GBP sterling following the change in functional and presentational currency from US$ to GBP sterling with effect from 1 January 2019.

Transactions in foreign currencies are initially recorded at the functional currency rate ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated at the foreign currency rate of exchange ruling at the balance sheet date and differences are taken to the income statement. Non-monetary items that are measured in terms of historical cost in a foreign currency are translated using the exchange rate as at the date of initial transaction. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rate at the date when the fair value was determined. Exchange gains and losses arising from translation are charged to the income statement as an operating item.

Business Combinations and Goodwill

Business combinations from 1 January 2010

Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of consideration transferred, measured at acquisition date fair value and the amount of any non-controlling interest in the acquiree. Acquisition costs incurred are expensed.

When the Group acquires a business, it assesses the financial assets and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. Any contingent consideration to be transferred to the acquirer will be recognised at fair value at the acquisition date. Contingent consideration classified as an asset or liability that is a financial instrument and within the scope of IFRS 9 Financial Instruments, is measured at fair value with the changes in fair value recognised in the statement of profit or loss in accordance with IFRS 9. Other contingent consideration that is not within the scope of IFRS 9 is measured at fair value at each reporting date with changes in fair value recognised in profit or loss.

Goodwill on acquisition is initially measured at cost being the excess of purchase price over the fair market value of identifiable assets, liabilities and contingent liabilities acquired. Following initial acquisition, it is measured at cost less any accumulated impairment losses. Goodwill is not amortised but is subject to an impairment test at least annually and more frequently if events or changes in circumstances indicate that the carrying value may be impaired. If the fair value of the net assets acquired is in excess of the aggregate consideration transferred, the Group re-assesses whether it has correctly identified all of the assets acquired and all of the liabilities assumed and reviews the procedures used to measure the amounts to be recognised at the acquisition date. If the reassessment still results in an excess of fair value of net assets acquired over the aggregate consideration transferred, then the gain is recognised in profit or loss.

At the acquisition date, any goodwill acquired is allocated to each of the cash-generating units, or groups of cash generating units expected to benefit from the combination's synergies. Impairment is determined by assessing the recoverable amount of the cash-generating unit, or groups of cash generating units to which the goodwill relates. Where the recoverable amount of the cash-generating unit is less than the carrying amount, an impairment loss is recognised.

Joint Arrangements

A joint operation is a type of joint arrangement whereby the parties that have joint control of the arrangement have the rights to the assets and obligations for the liabilities, relating to the arrangement.

The Group conducts petroleum and natural gas exploration and production activities jointly with other venturers who each have direct ownership in and jointly control the operations of the ventures. These are classified as jointly controlled operations and the financial statements reflect the Group's share of assets and liabilities in such activities. Income from the sale or use of the Group's share of the output of jointly controlled operations, and its share of joint venture expenses, are recognised when it is probable that the economic benefits associated with the transaction will flow to/from the Group and their amount can be measured reliably.

Full details of Serica's working interests in those petroleum and natural gas exploration and production activities classified as joint operations are included in the Review of Operations.

Exploration and Evaluation Assets

As allowed under IFRS 6 and in accordance with clarification issued by the International Financial Reporting Interpretations Committee, the Group has continued to apply its existing accounting policy to exploration and evaluation activity, subject to the specific requirements of IFRS 6. The Group will continue to monitor the application of these policies in light of expected future guidance on accounting for oil and gas activities.

Pre-licence Award Costs

Costs incurred prior to the award of oil and gas licences, concessions and other exploration rights are expensed in the income statement.

Exploration and Evaluation (E&E)

The costs of exploring for and evaluating oil and gas properties, including the costs of acquiring rights to explore, geological and geophysical studies, exploratory drilling and directly related overheads, are capitalised and classified as intangible E&E assets. These costs are directly attributed to regional CGUs for the purposes of impairment testing; UK & Ireland and Africa.

E&E assets are not amortised prior to the conclusion of appraisal activities but are assessed for impairment at an asset level and in regional CGUs when facts and circumstances suggest that the carrying amount of a regional cost centre may exceed its recoverable amount. Recoverable amounts are determined based upon risked potential, and where relevant, discovered oil and gas reserves. When an impairment test indicates an excess of carrying value compared to the recoverable amount, the carrying value of the regional CGU is written down to the recoverable amount in accordance with IAS 36. Such excess is expensed in the income statement. Where conditions giving rise to impairment subsequently reverse, the effect of the impairment charge is reversed as a credit to the income statement.

Costs of licences and associated E&E expenditure are expensed in the income statement if licences are relinquished, or if management do not expect to fund significant future expenditure in relation to the licence.

The E&E phase is completed when either the technical feasibility and commercial viability of extracting a mineral resource are demonstrable or no further prospectivity is recognised . At that point, if commercial reserves have been discovered, the carrying value of the relevant assets, net of any impairment write-down, is classified as an oil and gas property within property, plant and equipment, and tested for impairment. If commercial reserves have not been discovered then the costs of such assets will be written off.

Asset Purchases and Disposals

When a commercial transaction involves the exchange of E&E assets of similar size and characteristics, no fair value calculation is performed. The capitalised costs of the asset being sold are transferred to the asset being acquired. Proceeds from a part disposal of an E&E asset, including back-cost contributions are credited against the capitalised cost of the asset, with any excess being taken to the income statement as a gain on disposal.


In accordance with industry practice, the Group does not record its share of costs that are 'carried' by third parties in relation to its farm-in agreements in the E&E phase. Similarly, while the Group has agreed to carry the costs of another party to a Joint Operating Agreement ("JOA") in order to earn additional equity, it records its paying interest that incorporates the additional contribution over its equity share.

Property, Plant and Equipment - Oil and gas properties


Oil and gas properties are stated at cost, less any accumulated depreciation and accumulated impairment losses. Oil and gas properties are accumulated into single field cost centres and represent the cost of developing the commercial reserves and bringing them into production together with the E&E expenditures incurred in finding commercial reserves previously transferred from E&E assets as outlined in the policy above. The cost will include, for qualifying assets, any applicable borrowing costs.


Oil and gas properties are not depleted until production commences. Costs relating to each single field cost centre are depleted on a unit of production method based on the commercial proved and probable reserves for that cost centre. The depletion calculation takes account of the estimated future costs of development of management's assessment of proved and probable reserves, reflecting risks applicable to the specific assets. Changes in reserve quantities and cost estimates are recognised prospectively from the last reporting date. Proved and probable reserves estimates obtained from an independent reserves specialist have been used as the basis for 2019 and 2020 calculations.


A review is performed for any indication that the value of the Group's development and production assets may be impaired.

For oil and gas properties when there are such indications, an impairment test is carried out on the cash generating unit. Each cash generating unit is identified in accordance with IAS 36. Serica's cash generating units are those assets which generate largely independent cash flows and are normally, but not always, single development or production areas. If necessary, impairment is charged through the income statement if the capitalised costs of the cash generating unit exceed the recoverable amount of the related commercial oil and gas reserves.

Acquisitions, Asset Purchases and Disposals

Acquisitions of oil and gas properties are accounted for under the acquisition method when the assets acquired and liabilities assumed constitute a business.

Transactions involving the purchase of an individual field interest, or a group of field interests, that do not constitute a business, are treated as asset purchases. Accordingly, no goodwill and no deferred tax gross up arises, and the consideration is allocated to the assets and liabilities purchased on an appropriate basis. Proceeds from the entire disposal of a development and production asset, or any part thereof, are taken to the income statement together with the requisite proportional net book value of the asset, or part thereof, being sold.


Liabilities for decommissioning costs are recognised when the Group has an obligation to dismantle and remove a production, transportation or processing facility and to restore the site on which it is located. Liabilities may arise upon construction of such facilities, upon acquisition or through a subsequent change in legislation or regulations. The amount recognised is the estimated present value of future expenditure determined in accordance with local conditions and requirements. A corresponding tangible item of property, plant and equipment equivalent to the provision is also created.

Any changes in the present value of the estimated expenditure is added to or deducted from the cost of the assets to which it relates. The adjusted depreciable amount of the asset is then depreciated prospectively over its remaining useful life. The unwinding of the discount on the decommissioning provision is included as a finance cost.


Lifting arrangements for oil and gas produced in certain fields are such that each participant may not receive its share of the overall production in each period. The difference between cumulative entitlement and cumulative production less stock is 'underlift' or 'overlift'. Underlift and overlift are valued at market value and included within debtors ('underlift') or creditors ('overlift').

Property, Plant and Equipment - Other

Computer equipment and fixtures, fittings and equipment are recorded at cost as tangible assets. The straight-line method of depreciation is used to depreciate the cost of these assets over their estimated useful lives. Computer equipment is depreciated over three years and fixtures, fittings and equipment over four years, and right-of-use assets over the period of lease.


Inventories are valued at the lower of cost and net realisable value. Cost is determined by the first-in first-out method and comprises direct purchase costs and transportation expenses.


In its separate financial statements the Company recognises its investments in subsidiaries at cost less any provision for impairment.

Financial Instruments

Financial instruments comprise financial assets, cash and cash equivalents, financial liabilities and equity instruments. Financial assets and financial liabilities are recognised when the Group becomes a party to the contractual provisions of the financial instrument.

Financial assets

Financial assets are classified, at initial recognition, as subsequently measured at amortised cost, fair value through profit or loss, and fair value through other comprehensive income (OCI).

The classification of financial assets at initial recognition depends on the financial asset's contractual cash flow characteristics and the Group's business model for managing them.

With the exception of trade receivables that do not contain a significant financing component or for which the Group has applied the practical expedient, the Group initially measures a financial asset at its fair value plus transaction costs (in the case of a financial asset not at fair value through profit or loss). Trade receivables that do not contain a significant financing component or for which the Group has applied the practical expedient are measured at the transaction price determined under IFRS 15.

The Group determines the classification of its financial assets at initial recognition and, where allowed and appropriate, re-evaluates this designation at each financial year end.

Financial assets at fair value through profit or loss include financial assets held for trading and derivatives. Financial assets are classified as held for trading if they are acquired for the purpose of selling in the near term.

In order for a financial asset to be classified and measured at amortised cost it needs to give rise to cash flows that are 'solely payments of principal and interest (SPPI)' on the principal amount outstanding. This assessment is referred to as the SPPI test and is performed at an instrument level. Financial assets with cash flows that are not SPPI are classified and measured at fair value through profit or loss, irrespective of the business model.

Cash and cash equivalents

Cash and cash equivalents include balances with banks and short-term investments with original maturities of three months or less at the date acquired.

Financial liabilities

Financial liabilities are classified, at initial recognition, as financial liabilities at fair value through profit or loss, loans and borrowings, payables, or as derivatives designated as hedging instruments in an effective hedge, as appropriate. The Group's financial liabilities currently include trade and other payables. All financial liabilities are recognised initially at fair value. Obligations for loans and borrowings are recognised when the Group becomes party to the related contracts and are measured initially at the fair value of consideration received less directly attributable transaction costs.

After initial recognition, interest-bearing loans and borrowings are subsequently measured at amortised cost using the effective interest method.

Gains and losses are recognised in the income statement when the liabilities are derecognised as well as through the amortisation process.

Derivative financial instruments

The Group uses derivative financial instruments, such as forward commodity contracts, to hedge its commodity price risks. The Group has elected not to apply hedge accounting to these derivatives. Such derivative financial instruments are initially recognised at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value. Derivatives are carried as financial assets when the fair value is positive and as financial liabilities when the fair value is negative. Any gains or losses arising from changes in the fair value of derivatives are taken directly to the statement of profit or loss and other comprehensive income and presented within operating profit.

Further details of the fair values of derivative financial instruments and how they are measured are provided in Note 19.


Equity instruments issued by the Company are recorded in equity at the proceeds received, net of direct issue costs.

Trade and other receivables and contract assets

Trade receivables and contract assets

A receivable represents the Group ' s right to an amount of consideration that is unconditional (i.e., only the passage of time is required before payment of the consideration is due). A contract asset is the right to consideration in exchange for goods or services transferred to the customer.

Provision for expected credit losses of trade receivables and contract assets

For trade receivables and contract assets, the Group applies a simplified approach in calculating expected credit losses 'ECLs'. Therefore, the Group does not track changes in credit risk, but instead, recognises a loss allowance based on lifetime ECLs at each reporting date. The Group has established a provision matrix that is based on its historical credit loss experience, adjusted for forward-looking factors specific to the debtors and the economic environment. A financial asset is written off when there is no reasonable expectation of recovering the contractual cash flows. The Group's receivables have a good credit rating and there has been no noted change in the credit risk of receivables in the year.


Provisions are recognised when the Group has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate can be made of the amount of the obligation.

The Group's estimate in respect of contingent consideration that may be payable following the acquisition of its interest in the Erskine field, is capitalised as an asset acquisition cost. The value of the provision is determined by the amounts and nature of operating costs incurred over a contractual period.

Revenue from contracts with customers

Revenue from contracts with customers is recognised when control of the goods or services are transferred to the customer at an amount that reflects the consideration to which the Group expects to be entitled to in exchange for those goods or services. Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for goods provided in the normal course of business, net of discounts, customs duties and sales taxes. The Group has concluded that it is the principal in its revenue arrangements because it typically controls the goods or services before transferring them to the customer.

The sale of crude oil, gas or condensate represents a single performance obligation, being the sale of barrels equivalent on collection of a cargo or on delivery of commodity into an infrastructure. Revenue is accordingly recognised for this performance obligation when control over the corresponding commodity is transferred to the customer. The normal credit term is 15 to 45 days upon collection or delivery.

Finance Revenue

Finance revenue chiefly comprises interest income from cash deposits on the basis of the effective interest rate method and is disclosed separately on the face of the income statement.

Finance Costs

Finance costs of debt are allocated to periods over the term of the related debt using the effective interest method. Arrangement fees and issue costs are amortised and charged to the income statement as finance costs over the term of the debt.

Share-Based Payment Transactions

Employees (including Executive Directors) of the Group receive remuneration in the form of share-based payment transactions, whereby employees render services in exchange for shares or rights over shares ('equity-settled transactions').

Equity-settled transactions

The cost of equity-settled transactions with employees is measured by reference to the fair value at the date on which they are granted. In valuing equity-settled transactions, no account is taken of any service or performance conditions, other than conditions linked to the price of the shares of Serica Energy plc ('market conditions'), if applicable.

The cost of equity-settled transactions is recognised, together with a corresponding increase in equity, over the period in which the relevant employees become fully entitled to the award (the 'vesting period'). The cumulative expense recognised for equity-settled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and the Group's best estimate of the number of equity instruments that will ultimately vest. The income statement charge or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period.

No expense is recognised for awards that do not ultimately vest, except for awards where vesting is conditional upon a market or non-vesting condition, which are treated as vesting irrespective of whether or not the market or non-vesting condition is satisfied, provided that all other performance conditions are satisfied. For equity awards cancelled by forfeiture when vesting conditions are not met, any expense previously recognised is reversed and recognised as a credit in the income statement. Equity awards cancelled are treated as vesting immediately on the date of cancellation, and any expense not recognised for the award at that date is recognised in the income statement. Estimated associated national insurance charges are expensed in the income statement on an accruals basis.

Where the terms of an equity-settled award are modified or a new award is designated as replacing a cancelled or settled award, the cost based on the original award terms continues to be recognised over the original vesting period. In addition, an expense is recognised over the remainder of the new vesting period for the incremental fair value of any modification, based on the difference between the fair value of the original award and the fair value of the modified award, both as measured on the date of the modification. No reduction is recognised if this difference is negative.

Income Taxes

Current tax, including UK corporation tax and overseas corporation tax, is provided at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted by the balance sheet date.

Deferred tax is provided using the liability method and tax rates and laws that have been enacted or substantively enacted at the balance sheet date. Provision is made for temporary differences at the balance sheet date between the tax bases of the assets and liabilities and their carrying amounts for financial reporting purposes. Deferred tax is provided on all temporary differences except for:

-- temporary differences associated with investments in subsidiaries, where the timing of the reversal of the temporary differences can be controlled by the Group and it is probable that the temporary differences will not reverse in the foreseeable future; and

-- temporary differences arising from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the income statement nor taxable profit or loss.

Deferred tax assets are recognised for all deductible temporary differences, to the extent that it is probable that taxable profits will be available against which the deductible temporary differences can be utilised. Deferred tax assets and liabilities are presented net only if there is a legally enforceable right to set off current tax assets against current tax liabilities and if the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority.

Earnings Per Share

Earnings per share is calculated using the weighted average number of ordinary shares outstanding during the period. Diluted earnings per share is calculated based on the weighted average number of ordinary shares outstanding during the period plus the weighted average number of shares that would be issued on the conversion of all relevant potentially dilutive shares to ordinary shares. It is assumed that any proceeds obtained on the exercise of any options and warrants would be used to purchase ordinary shares at the average price during the period. Where the impact of converted shares would be anti-dilutive, these are excluded from the calculation of diluted earnings.


In applying IFRS 16 for the first time the Group applied the short-term lease practical expedient by not recognising lease liabilities in respect to lease arrangements with a remaining lease term of less than 12 months as at 1 January 2019. The Group adopted the modified retrospective approach to adoption on 1 January 2019, measuring right-of use assets at an amount based on their respective lease liability on adoption, with the cumulative effect of adopting the standard recognised at the date of initial application without restatement of comparative information.

As a lessee, the Group recognises a right-of-use asset and a lease liability at the lease commencement date. The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted by using the rate implicit in the lease, or, if that rate cannot be readily determined, the Group uses its incremental borrowing rate.

The lease liability is subsequently recorded at amortised cost, using the effective interest rate method. The liability is remeasured when there is a change in future lease payments arising from a change in an index or rate or if the Group changes its assessment of whether it will exercise a purchase, extension or termination option. When the lease liability is remeasured in this way, a corresponding adjustment is made to the carrying amount of the right-of-use asset or is recorded in profit or loss if the carrying amount of the right-of-use asset has been reduced to zero.

The right-of-use asset is measured at cost, which comprises the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or the site on which it is located, less any lease incentives received. Right-of-use assets are depreciated over the shorter period of lease term and useful life of the underlying asset.

The Group does not currently act as a lessor.

New and amended standards and interpretations

The Group has adopted and applied for the first time, certain standards and amendments, which are effective for annual periods beginning on or after 1 January 2020. The Group has not early adopted any other standard, interpretation or amendment that has been issued but is not yet effective. The nature and effect of the changes that result from the adoption of these new standards are described below. Other than the changes described below, the accounting policies adopted are consistent with those of the previous financial year.

Several other amendments and interpretations apply for the first time in 2020, but do not have an impact on the consolidated financial statements of the Group. The Group has not early adopted any standards, interpretations or amendments that have been issued but are not yet effective.

Amendments to IFRS 3: Definition of a Business

The amendment to IFRS 3 Business Combinations clarifies that to be considered a business, an integrated set of activities and assets must include, at a minimum, an input and a substantive process that, together, significantly contribute to the ability to create output. Furthermore, it clarifies that a business can exist without including all of the inputs and processes needed to create outputs. These amendments had no impact on the consolidated financial statements of the Group, but may impact future periods should the Group enter into any additional business combinations.

Amendments to IFRS 7, IFRS 9 and IAS 39 Interest Rate Benchmark Reform

The amendments to IFRS 9 and IAS 39 Financial Instruments: Recognition and Measurement provide a number of reliefs, which apply to all hedging relationships that are directly affected by interest rate benchmark reform. A hedging relationship is affected if the reform gives rise to uncertainty about the timing and/or amount of benchmark-based cash flows of the hedged item or the hedging instrument. These amendments have no impact on the consolidated financial statements of the Group.

Amendments to IAS 1 and IAS 8 Definition of Material

The amendments provide a new definition of material that states, "information is material if omitting, misstating or obscuring it could reasonably be expected to influence decisions that the primary users of general purpose financial statements make on the basis of those financial statements, which provide financial information about a specific reporting entity." The amendments clarify that materiality will depend on the nature or magnitude of information, either individually or in combination with other information, in the context of the financial statements. A misstatement of information is material if it could reasonably be expected to influence decisions made by the primary users. These amendments had no impact on the consolidated financial statements of, nor is there expected to be any future impact to the Group.

Conceptual Framework for Financial Reporting issued on 29 March 2018

The Conceptual Framework is not a standard, and none of the concepts contained therein override the concepts or requirements in any standard. The purpose of the Conceptual Framework is to assist the IASB in developing standards, to help preparers develop consistent accounting policies where there is no applicable standard in place and to assist all parties to understand and interpret the standards. This will affect those entities which developed their accounting policies based on the Conceptual Framework. The revised Conceptual Framework includes some new concepts, updated definitions and recognition criteria for assets and liabilities and clarifies some important concepts. These amendments had no impact on the consolidated financial statements of the Group.

Standards issued but not yet effective

Certain standards or interpretations issued but not yet effective up to the date of issuance of the Group's financial statements are listed below. This listing of standards and interpretations issued are those that the Group reasonably expects to have an impact on disclosures, financial position or performance when applied at a future date. The Group is currently assessing the impact of these standards and intends to adopt them when they become effective. In reviewing the below standards, the Group does not believe that there will be a material impact on the financial statements.

Amendments to IAS 1: Classification of Liabilities as Current or Non-current

The amendments are effective for annual reporting periods beginning on or after 1 January 2023 and must be applied retrospectively. The Group is currently assessing the impact the amendments will have on current practice.

Reference to the Conceptual Framework - Amendments to IFRS 3

The amendments are effective for annual reporting periods beginning on or after 1 January 2022 and apply prospectively.

Property, Plant and Equipment: Proceeds before Intended Use - Amendments to IAS 16

The amendment is effective for annual reporting periods beginning on or after 1 January 2022 and must be applied retrospectively to items of property, plant and equipment made available for use on or after the beginning of the earliest period presented when the entity first applies the amendment.


 bbl                 barrel of 42 US gallons 
 bcf                 billion standard cubic feet 
 boe                 barrels of oil equivalent (barrels of oil, condensate and LPG plus the heating equivalent 
                      of gas converted into barrels at the appropriate rate) 
 BKR                 Bruce, Keith and Rhum fields 
  BPEOC               BP Exploration Operating Company 
 CGU                 Cash generating unit 
 CPR                 Competent Persons Report 
  ESG                 Environmental, Social and Governance 
 FDP                 Field Development Plan 
  FPS                 Forties Pipeline System 
 GRI                 Global Reporting Index (framework for sustainability reporting) 
 HPHT                High pressure high temperature 
 mscf                thousand standard cubic feet 
 mmbbl               million barrels 
 mmboe               million barrels of oil equivalent 
 mmscf               million standard cubic feet 
 mmscfd              million standard cubic feet per day 
 NGLs                Natural gas liquids extracted from gas streams 
 NTS                 National Transmission System 
 OGA                 Oil and Gas Authority 
 Overlift            Volumes of oil or NGLs sold in excess of volumes produced 
 Underlift           Volumes of oil or NGLs produced but not yet sold 
 P10                 A high estimate that there should be at least a 10% probability that the quantities recovered 
                      will actually equal or exceed the estimate 
 P50                 A best estimate that there should be at least a 50% probability that the quantities recovered 
                      will actually equal or exceed the estimate 
 P90                 A low estimate that there should be at least a 90% probability that the quantities recovered 
                      will actually equal or exceed the estimate 
 Pigging             A process of pipeline cleaning and maintenance which involves the use of devices called pigs 
 Proved Reserves     Proved reserves are those Reserves that can be estimated with a high degree of certainty to 
                      be recoverable. It is likely that the actual remaining quantities recovered will exceed the 
                      estimated proved reserves 
 Probable Reserves   Probable reserves are those additional Reserves that are less certain to be recovered than 
                      proved reserves. It is equally likely that the actual remaining quantities recovered will 
                      be greater or less than the sum of the estimated proved + probable reserves 
 Possible Reserves   Possible reserves are those additional Reserves that are less certain to be recovered than 
                      probable reserves. It is unlikely that the actual remaining quantities recovered will exceed 
                      the sum of the estimated proved + probable + possible reserves 
 Reserves            Estimates of discovered recoverable commercial hydrocarbon reserves calculated in accordance 
                      with the revised June 2018 Petroleum Resources Management System (PRMS) version 1.01 
 SASB                Sustainability accounting standards board 
 Tcf                 trillion standard cubic feet 
 TCFD                Taskforce on Climate-related Financial Disclosures 
 UKCS                United Kingdom Continental Shelf 
 UNSDG               United Nations Sustainable Development Goals 

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