Results for the year ended 31 December 2017

RNS Number : 3506K

Serica Energy plc

10 April 2018

 

Serica Energy plc

("Serica" or the "Company") 

Results for the year ended 31 December 2017

London, 10 April 2018 - Serica Energy plc (AIM: SQZ) today announces its financial results for the year ended 31 December 2017.  The results are included below and copies are available at www.serica-energy.com and www.sedar.com.

A conference call for analysts will be held at 10.00 a.m. (UK time) on Tuesday 10 April. If you would like to participate in this call, please email [e-mail] or call [phone].  The presentation will be available on the investors section of the Serica website at www.serica-energy.com.

Highlights

Financial

·     Operating profit for 2017 of US$14.1 million, a four-fold increase over 2016 operating profit of US$3.4 million

·     Group profit after tax of US$17.1 million (2016: US$10.8 million) after deferred tax credits of US$6.3 million (2016: US$7.5 million) arising from tax losses brought forward  

·     Revenues boosted by strengthening average realised sales prices of US$53.2 per barrel of oil (2016: US$42.1 per barrel) and 41 pence per therm of gas (2016: 33 pence per therm)

·     Total cash balances and term deposits at 31 December 2017 of US$34.0 million, increased from US$16.6 million at 31 December 2016

·     Balance sheet strength maintained with limited capital commitments and borrowings

BKR Assets Acquisition

The acquisition of BP's interests in the Bruce, Keith and Rhum ("BKR") fields, announced on 21 November 2017 and expected to complete in late Q3 2018, transformational for Serica:

·     Additional revenue streams counterbalance Serica's current Erskine single field exposure

·     Significant additions to production volumes and reserves

·     Accelerated utilisation of tax losses enhances value to Serica

·     Deal structured to control risk and minimise shareholder dilution

Operational

Erskine Field

·     Production averaged just under 2,000 boe per day net to Serica during 2017 despite wax restrictions and December Forties Pipeline System shut-in

·     Serica's operating and transportation costs maintained at approximately US$15 per barrel for the year despite production interruptions

·    Capabilities of the Erskine reservoir and wells continue to outperform the projections that Serica made when the asset was first acquired  

·     Work continues to clear early 2018 blockage in Lomond to Everest condensate export line

·     Engineering and procurement commenced for export pipeline bypass to avoid future wax restrictions with expected completion in Q3 2018

Columbus Field

Serica, as operator of Columbus with a 50% interest, is moving the field towards development:  

·     Columbus partners have selected an offtake route via the proposed Arran-to-Shearwater pipeline

·     Submission of a field development plan to the OGA targeted for mid-year

Exploration

·       Preparations for a well on the Rowallan prospect in the second half of 2018 are progressing to plan with a site survey completed last December and tendering for a rig underway

·     Serica is fully carried on all Rowallan well costs on this high pressure, high temperature prospect

·     The Company has participated in three licence applications in the UKCS 30^th Offshore Licensing Round

 
Outlook for 2018

·     Completion of the Lomond to Everest export line bypass during Q3 is expected to deliver more consistent Erskine production performance and sales revenues

·     Serica's 40% share in 2018 net cash flows from the BKR Assets, accruing under the acquisition agreement, adds to the Company's cash resources upon completion expected in late Q3 2018

·     Transition work for the BKR Assets acquisition is well underway:

o  Consultations with transferring staff close to completion and recruitment for additional positions in progress

o  New premises for Aberdeen operations headquarters identified with occupation targeted for mid-summer

o  Serica working with BP, OGA and partners to ensure safe and orderly transition

·     Serica's management believes that the increased scale and diversification that the BKR deal brings, along with the associated operating capability, will provide a platform from which to further grow the business through:

o  Identifying and implementing operational efficiencies

o  Targeting investment to further enhance the value of its assets

o  Seeking complementary acquisitions with a continuing focus on the UK North Sea.

Mitch Flegg, Serica's CEO commented:

"2017 has been a landmark year for Serica, delivering our highest annual profit to date and providing us with the platform to grow further.

Building on a strong set of financial results, the announcement of the BKR Assets acquisition in late November rounded off an excellent year.  Though much of our effort is currently directed towards the transition of BKR operations from BP, we continue to seek new opportunities to add to our portfolio of assets. We believe that the UK North Sea, where there are strategic benefits for Serica, will continue to provide new opportunities to grow the business and add shareholder value.

Erskine delivered good performance on average for the year, despite the wax build-up issues and production shut-in. Whilst we continue to attempt to address the current wax build-up we fully support Chrysaor's proposal for a pipeline bypass, as a cost-effective and permanent solution through regular pigging of a new line.

The selection of the Shearwater hub as the optimum offtake route for the Columbus field, and our planned submission of the field development plan scheduled for mid-2018 are significant steps towards first production from the field.

Operationally, we are delighted that work will soon commence on the Rhum R3 well intervention and that preparations continue for drilling a well on the Rowallan prospect in which we have a 15% carried interest. A successful outcome in one or both of these projects will have a material impact on Serica."

Technical Information

The technical information contained in the announcement has been reviewed and approved by Clara Altobell, VP Technical at Serica Energy plc. Clara Altobell (MSc in Petroleum Engineering from Imperial College, London) has over 20 years of experience in oil & gas exploration, production and development and is a member of the Society of Petroleum Engineers (SPE) and the Petroleum Exploration Society of Great Britain (PESGB).

Regulatory

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

Enquiries:

Serica Energy plc
Tony Craven Walker Mitch Flegg		[e-mail] [e-mail]	[phone]  [phone]
Peel Hunt
Richard Crichton		[e-mail]	[phone]
Ross Allister		[e-mail]	[phone]
James Bavister		[e-mail]	[phone]
Instinctif Partners
David Simonson		[e-mail]	[phone]
Laura Syrett		[e-mail]	[phone]
George Yeomans		[e-mail]	[phone]

NOTES TO EDITORS

Serica Energy is an oil and gas exploration and production company with exploration, development and production assets in the UK and exploration interests in the Atlantic margins offshore Ireland, and Namibia. Serica holds an 18% non-operated interest in the Erskine field in the UK Central North Sea. 

In November 2017 Serica announced the proposed acquisition of interests in the Bruce, Keith and Rhum fields in the North Sea and associated infrastructure from BP. Under the terms of proposed acquisition Serica will acquire a 36% interest in Bruce, a 34.83% interest in Keith and a 50% interest in Rhum (collectively the "BKR Assets"). The deal has an effective date of 1 January 2018 and completion of acquisition is expected to take place late in the third quarter of 2018.

Further information on the Company and the proposed acquisition of the BKR Assets can be found at www.serica-energy.com.

The Company is listed on the AIM market of the London Stock Exchange under the ticker SQZ and is a designated foreign issuer on the TSX. To receive Company news releases via email, please contact [e-mail] and specify "Serica press releases" in the subject line.

  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: geological, geophysical and technical risk, 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.

EXECUTIVE CHAIRMAN'S STATEMENT

Dear Shareholder

I am delighted to report that Serica made strong progress in 2017.  With the announcement in late November of Serica's acquisition of operated interests in the Bruce, Keith and Rhum fields (BKR Assets), the Company had a very strong finish to what was an excellent year.  Gross profits from operations amounted to just under US$20 million, a three-fold increase over the prior year, derived solely from our interest in Erskine.

Serica's target over the past two/three years has been to diversify the risk associated with being reliant on Erskine as a single production source and grow into a profitable mid-tier independent oil and gas producer through an acquisition led strategy, concentrating on assets where we believed that we could add value through our own expertise.  I am very pleased to report that, with the agreement to purchase the BKR Assets from BP we are now well on our way to achieving this goal.  These fields hold significant potential which Serica believes it can unlock as a focused, low cost and innovative operator under the leadership of Mitch Flegg who joined us as Chief Executive upon announcement of the transaction.

We welcome Mitch and the team who have joined with him.  They will be joined on completion of the acquisition by experienced staff from BP who bring their expertise and knowledge of the assets to cement what I believe will be a very strong and technically competent team capable of running an exciting new growth phase for the Company.

The acquisition of the BKR Assets provides for an effective date of 1 January 2018.  Apart from a short period of production interruptions in early January linked to a shutdown of the Forties Pipeline System and the impact of very severe weather conditions in the latter part of February and early March, the assets have been performing well since the start of this year. The assets are expected to bring material benefit to Serica upon completion of the acquisition, now expected in the third quarter this year.  The ensuing period will be taken up by implementing the complex programme to enable a safe and efficient transfer of operations and securing the various consents required for the transfer and ensuing operations.  To-date we are making good progress with all of these transition requirements, working closely with BP, partners and the various regulatory bodies.

Further information, as well as an update on Erskine where production is currently suspended due to a pipeline blockage, is provided in the Chief Executive's Report and the Operations and Financial Reviews but the overall impact of the acquisition will be significant to the Company and its future prospects.  Underlying reserves will have increased some sixteen-fold to approximately 50 million boe as at 1 January 2018 and the strength and depth of the Company will have been transformed by combining the Company's skills with those of the BP employees joining us.  Production is projected to increase significantly, with potential for further increases, and the Company's financial position is expected to increase commensurately.

Following completion of the transaction, Serica's production will be predominantly gas, with the Rhum and Bruce fields alone accounting for up to 5% of total UK gas production.   At a time of rising political tensions and limited UK gas storage capacity this focus on gas should also provide a strong underpinning for Serica.

Whilst there will undoubtedly be challenges ahead I am very optimistic about the Company's future and its ability to consolidate our recent acquisition and build on the platform that we have now created.  Our future plans include organic growth, developing the position we will have in four North Sea producing fields as well as developing our Columbus interest and commencing an exploration programme with the Rowallan well whilst we review options for our interests in Namibia and Ireland.  However, we will also continue to seek ways in which we can add new assets through selective acquisition to complement our strong production base and build a robust and exciting portfolio with further potential for value-generating growth.

In summary, I am delighted with the positive outcome which has resulted from the skills and focus of Serica's team and a considerable amount of effort on their part.  I would like to thank them on shareholders' behalf, welcome all newcomers to the Company and look forward to an exciting period ahead.

Tony Craven Walker

Executive Chairman

9 April 2018

STRATEGIC REPORT 

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 2017. 

References to the "Company" include Serica and its subsidiaries where relevant. All figures are reported in US dollars ("US$") unless otherwise stated. The Company is subject to the regulatory requirements of the 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 and exploration interests in Ireland and Namibia.

CHIEF EXECUTIVE OFFICER'S REPORT

Net production of 722,000 boe (2016 - 597,000 boe) and operating profits of US$14.1 million (2016 - US$3.4 million) represent Serica's strongest annual performance to-date even though wax control in the condensate export pipeline restricted Erskine second half volumes. The year also saw the announcement of the BKR Assets acquisition and significant progress on bringing Columbus to a development decision.

The problems with a wax build-up in the Lomond to Everest condensate export line have deferred production from Erskine but it is expected that this production will be recovered once the pipeline restrictions have been cleared.  Erskine partners' focus has therefore been placed on resolving the restrictions that have been preventing delivery of the field's full capability. A long-term solution has been sanctioned and work on this has commenced alongside the ongoing efforts to clear the build-up.

The capability of the Erskine reservoir and wells continues to outperform the projections that Serica made when the asset was first acquired. Estimated remaining 2P reserves at 1 January 2018 of 3.1 million boe net to Serica compare to an estimated 3.3 million boe when Serica first acquired the field interest in mid-2015 even though 1.9 million boe net to Serica have been produced during the intervening period. When not subject to external restrictions, the field has demonstrated an ability to sustain production at rates around 3,000 boe per day net to Serica.

The acquisition of the BP interests in the BKR Assets will provide Serica with the opportunity to build on the experience gained from Erskine in order to move forward as a production operator.  I have been tremendously impressed with the professionalism and enthusiasm of the BP staff that will be transferring to Serica and I look forward to welcoming these staff as well as our new recruits into our new operational headquarters which will be opened in Aberdeen in the second half of 2018.

Meanwhile, we are pleased to confirm that Serica and the other Columbus partners have notified the Oil and Gas Authority ("OGA") of a selected offtake route for the Columbus field development. This is discussed in more detail below and in the Operations Report.  We now look forward to working with our partners and infrastructure owners to develop and submit a Field Development Plan ("FDP") to the OGA for Columbus, targeted for mid-year.

Serica remains committed to exploration and the forthcoming Rowallan well, on which Serica is fully carried, is one of the few significant UK exploration wells due to be drilled in 2018 targeting gross reserves over 100 million boe. Elsewhere in the UK Continental Shelf ("UKCS") Serica is looking to grow its exploration portfolio and has participated in three applications for new licences in the UKCS 30^th Offshore Licensing Round. 

Industry activity in both Ireland and Namibia is showing strong signs of recovery as oil prices recover from the lows seen in 2015-16; this is expected to enhance our ongoing efforts to secure drilling partners in these areas.

Erskine

During the first five months of 2017 Serica's primary asset, the Erskine field, delivered a particularly strong performance with production averaging 3,100 boe per day net to the Company.  This was followed by a period when wax build-up in the Lomond to Everest condensate export line restricted rates through June and July leading into a two-month field shut-in as a planned August maintenance programme extended into September for additional wax management processes and repairs to a Lomond caisson. The recommencement of production in late September brought a further period of steady production, averaging close to 2,500 boe per day net, until an unplanned outage of the Forties Pipeline System ("FPS") on 11 December shut-in Erskine along with approximately 80 other North Sea production platforms.

Though frustrating not to have been able to maintain Erskine early year performance, Serica's net share of production for 2017 still averaged close to 2,000 boe per day, delivered at improving oil and gas prices, and generating profit before tax of US$10.8 million compared to US$3.3 million for 2016. It should also be emphasised that output restrictions during 2017 were almost entirely related to the oil offtake pipelines.

The FPS interruption was a rare event which the operator, Ineos FPS, was quick to address given the strategic importance of this line which transports to shore over 40% of total UK oil production. However, the wax build-up in the Lomond to Everest condensate export line has been a recurring challenge and, as already reported, has caused a further interruption to Erskine production in early 2018. Response to-date has been to manage the problem through rate control, periodic soaking of the line with solvents and pigging. However, pigging programmes have historically been limited due to the risk of full blockage. 

New Lomond operator, Chrysaor Holdings Limited, after reviewing the various wax management measures employed in recent years, has concluded that the best long-term solution is to bypass the area of wax build-up by replacing a 26 km section of line, a proposal that Serica fully supports. A clean line will allow full and regular pigging right from the start thus preventing the wax build-up that has proved so difficult to remove. Serica's share of the cost is comparable to some 40 days of Serica's field revenues. Equipment procurement has commenced and the installation is expected to be completed in Q3 2018.

So, although field production is again being curtailed during early 2018, Serica has confidence that the bypass solution will assist delivery of full field potential in future years and pay for itself many times over. In the meantime, the Lomond operator continues to make every effort to clear the blockage with further equipment currently being mobilised.

BKR Asset acquisition

Since the 2015 acquisition of an interest in the producing Erskine field, Serica's management has been seeking additional North Sea production interests. In addition to diversifying risk away from a single revenue stream, this would also assist in accelerating and fully exploiting the value of Serica's UK North Sea ringfence tax losses. It has taken considerable time and patience to deliver the right deal but we believe the structure of the BKR transaction allows Serica to achieve further transformation whilst managing downside risk and avoiding excessive dilution or leverage.

As the deal also brings operating responsibilities, the transition phase will necessarily be of sufficient duration to allow the Company to put in place systems and resources and obtain the necessary consents. This work is progressing well, the consultation phase for over 110 staff transferring from BP is almost complete, recruitment for additional positions is underway, new offices have been identified in Aberdeen and the Company is working with BP, the OGA and field partners to ensure a safe and ordered transition. Completion is targeted for late Q3 2018.

During Q1 2018, BKR production has remained strong, routinely exceeding 20,000 boe per day net to BP. However interruptions for the FPS shut-in and the recent severe weather conditions in the North Sea mean that in Q1 2018 the average production was 16,000 boe per day net to BP. Importantly, Ofgem has recently approved the raising of the National Transmission System ("NTS") entry specification for CO₂ content of gas delivered at the St Fergus Gas Terminal to 5.5mol% CO₂ largely eliminating the need for costly blending gas required up to now to offset the relatively higher CO₂ content of Rhum gas.

BP has entered into a contract for a rig to carry out the re-entry and re-completion of the previously drilled (but not yet producing) Rhum R3 well. Operations are expected to commence in May this year. The well is already connected to the necessary infrastructure and it is expected that production will commence before the year-end.

Under the terms of the SPA, Serica will benefit from a 40% share of 2018 net cashflow from the acquired assets rising on a stepped basis to 100% in 2022. The amount generated in the period up to completion, adjusted for notional tax, will be offset against the £12.8 million consideration due at completion. At current production volumes and sales prices, this is expected to exceed the initial consideration delivering a net cash receipt to Serica.

Columbus

Under the extension terms of the Columbus licences, Serica and its partners in the Columbus field were required to notify the OGA by 31 March 2018 of the choice of an offtake route and to submit an FDP by 30 June 2018. Work has concluded on the evaluation of two potential offtake routes for Columbus production and the Columbus partners have selected the Shearwater hub as providing the optimum export route for Columbus gas and liquids. This selection is contingent on a near-term commitment being made by the Arran field partners to the construction of a pipeline from the Arran field to Shearwater passing near the Columbus field with appropriate tie-in points. The OGA has been informed of the decision and Serica has commenced the preparation of the field development plan which is intended to be ready for submission by mid-2018. 

Exploration

The Rowallan well, will be Serica's first exploration well since 2014 and our 15% fully carried interest brings significant potential with an independently assessed 19.7 mmboe of P50 Prospective Resources net to Serica. A tender process is underway to contract a drilling rig to commence drilling of the exploration well in H2 2018. Though Serica has been careful to manage its exploration commitments during the industry downturn, this well, targeting material hydrocarbon volumes, is close to infrastructure within the general Erskine/Lomond area making it a strong candidate for early development should the well prove successful and will be drilled at no cost to Serica.

Serica intends to continue targeting exploration opportunities where an attractive balance can be struck between financial commitment and risked commercial return and has participated in three applications for new licences in the UKCS 30^th Offshore Licensing Round.

Further Opportunities

Though the main effort must necessarily be directed towards preparing for BKR operations and completing the transaction with BP, Serica will continue to look for opportunities to build the Company and deliver further shareholder value. As the time taken to deliver the BKR opportunity demonstrates, it requires patience to achieve this but we believe that Company progress to date provides a sound platform from which to further build our upstream business.

Mitch Flegg

9 April 2018

BKR ASSET ACQUISITION

On 21 November 2017 Serica announced that it had reached agreement to conditionally acquire the BKR Assets from BP. The BKR Assets comprise of BP's interests in the Bruce, Keith and Rhum fields (36%, 34.83% and 50% respectively) in the North Sea along with associated oil and gas infrastructure. BP is retaining a 1% interest in the Bruce field. Subject to completion, Serica will also become the operator of the BKR Assets and the Directors anticipate that approximately 110 BP employees will be transferred to Serica with additional employees currently being recruited. 

The consideration being paid to BP, comprises:

i.   an initial consideration of £12.8 million payable on completion to be adjusted for working capital calculated from an effective date of 1 January 2018;

ii.  a further contingent amount of up to £16 million dependent on the Rhum R3 Well (the third well on the Rhum field) achieving a specified minimum production threshold for 90 days during the first year following completion of the workover of the well, anticipated to take place in the summer of 2018;

iii.  an additional contingent consideration of up to £23.1 million in aggregate payable in three instalments of up to approximately £7.7 million each in respect of 2019, 2020 and 2021 if the Rhum field production volumes and sales prices meet or exceed certain agreed levels. The amounts payable will be reduced if Rhum field production and the price achieved for sales of Rhum gas do not meet the agreed levels;

iv. deferred cash consideration calculated as a percentage (60% in 2018, 50% in 2019 and 40% in each of 2020 and 2021) of the pre-tax net cash flows resulting from BP's interests in the BKR Assets from 2018 through to 2021;

v.  deferred consideration equal to 30% of BP's retained share of future decommissioning costs, reduced by the tax relief BP receives on such costs; and

vi. deferred consideration equal to 90% of Serica's share of the realised value of oil in the Bruce pipeline at the end of field life.

The deferred and contingent cash consideration is expected to be financed from the expected cash flow from the BKR Assets.

BP will retain liability for all the costs of decommissioning facilities, including wells existing at completion relating to the BKR Assets. Serica will pay for the costs of decommissioning new facilities.

As part of the acquisition, Serica has entered into product sales agreements with certain BP entities to off-take Serica's share of production of gas, oil and natural gas liquids from the BKR Assets on market terms. In addition, BP Gas has agreed to provide Serica with a prepayment facility of up to £16 million to provide for drawings to cover the cost of gas price hedging instruments which have been purchased by Serica in conjunction with signing the acquisition agreement and, if required, the initial consideration.

REVIEW OF OPERATIONS

Production

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

All of Serica's 2017 production came from its 18% interest in Erskine, a gas and condensate field located in the UK Central North Sea. Serica's co-venturers are Chevron, 50% (operator), and Chrysaor Holdings Limited, 32% as of November 2017. Erskine fluids are processed and exported via the Lomond platform, which is 100% owned and operated by Chrysaor Holdings Limited.

An updated independent audit of the Erskine field confirmed Serica's share of estimated proven plus probable reserves at 3.1 million boe as of 1 January 2018.

Production for 2017 averaged 1,976 boe per day net to Serica. Between 1 January and 31 May 2017, production was excellent, with a net average of 3,100 boe per day and peaking at over 4,100 boe per day net. This was achieved through high uptime performance from export facilities and good performance from the Erskine wells.  During June and July, production was reduced by approximately 50% to regulate wax deposition in the condensate export pipeline and some wax treatment procedures were carried out. 

A planned maintenance programme on the Lomond platform took place in August, coinciding with maintenance activities at the FPS.  The operator also took the opportunity to undertake a chemical clean of the condensate export pipeline to treat wax deposits.  Production restart was delayed as the operator of FPS imposed a restriction on production from the field, in order to manage the specialist fluids used in the wax treatment process.

Erskine was brought back into production on 22 September and rates net to Serica were gradually increased to over 2,500 boe per day, achieved with only three out of five wells producing.  During the following months, further chemical and mechanical processes were carried out to maintain flow down the export pipeline.

In early December, the FPS, the export route for Erskine condensate, was shut in due to a hairline crack found in an onshore section of pipe.  This impacted production for much of December and Erskine re-start occurred in early January 2018. However later in January during routine pipeline cleaning operations of the Lomond to Erskine condensate export pipeline, a blockage occurred in the pipeline. The operator of this pipeline is continuing to clear this wax build up.

Serica is working with the operators of Erskine and Lomond to implement long-term solutions to improve uptime of the export facilities and return to performance levels seen at the beginning of 2017. 

Development

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

The Columbus gas condensate field is located in close proximity to the Lomond platform, which is the offtake route for production from Serica's Erskine producing interest. Serica is Columbus field operator with partners EOG Resources United Kingdom Limited (25%) and Endeavour Energy UK Limited (25%). The field is located in the Eastern Central Graben, UK Central North Sea and the reservoir is located within the Forties Sandstone.

The Columbus field has been appraised with four wells and is planned to be developed with a single production well. Serica is currently working towards a full field development plan for submission to the OGA by mid-2018 with a view to commencing development work before the end of 2018. First gas is currently targeted for 2021.

During 2017, Serica pursued two alternative development options for Columbus.  One option was to drill a subsea well into Columbus and connect it to a proposed pipeline between the nearby Arran field and the Shearwater platform.  The alternative option was to drill an extended-reach development well into Columbus directly from the Lomond platform, located 5 km away.  The economic benefits of both options were very similar.

Under the extension terms of the Columbus licences, Serica and its partners in the Columbus field were required to notify the OGA by 31 March 2018 of the choice of an offtake route and to submit an FDP by 30 June 2018.

Serica has informed the OGA that it will prepare an FDP to develop Columbus by tying a subsea well into the pipeline proposed to be laid between Arran and Shearwater.  Under this option, Arran and Columbus fluids will combine in the new pipeline and be produced together over the Shearwater processing facilities via an existing riser onto the Shearwater platform.  Although the expected first gas date would be around a year later than the Lomond alternative, the overall capital costs under this option are lower.  The Columbus partners will now work with the operator of the Arran field and the operator of the Shearwater platform and move forward with a Columbus FDP, to be submitted by end of Q2 2018, the timing requested by the OGA.

Final commitment to this offtake route and submission of an FDP in the timetable required by the OGA is, however, dependent upon the Arran field owners committing to development of the Arran field in the timeframe prescribed by the OGA.  If the Arran development does not proceed as planned, Columbus cannot be developed through Shearwater on a stand-alone basis.  The selection of this route has been made conditional on that decision being made to the satisfaction of Serica.  Therefore, discussions on commercial arrangements will continue with the Lomond field operator, in the event that the Shearwater option does not mature in the requisite time frame.  The Lomond option has been engineered in detail and is capable of being fully implemented.

A CPR carried out in 2017 estimates net 2C contingent resources to Serica on the Columbus field to be 6.7 mmboe.  Once the FDP is submitted, Columbus contingent resources will be redefined as reserves, based on the economic cut off for the selected development. 

Exploration

Central North Sea: Rowallan Prospect - Block 22/19c, Serica 15%

Block 22/19c is located in the Central North Sea, around 20 km west of the Columbus field. It contains the Rowallan Prospect comprising potential condensate targets in the Triassic Skagerrak and the Middle Jurassic Pentland formations. Serica's partners comprise ENI UK Limited (operator - 40%), JX Nippon Exploration and Production (U.K.) Limited (25%) and Mitsui E&P UK Limited (20%).

Well preparations for the Rowallan Prospect are underway, with spending on a site survey and long-lead items approved by partners for 2017. A vessel was deployed in December 2017 to complete a site survey in preparation for the drilling of a well in the second half of 2018 and the operator, ENI UK Limited, is now conducting a tendering process to contract a rig to drill the well. The prospect is located within Serica's core Central North Sea area, close to Erskine and Columbus. Serica is fully carried on all costs for a well on this high pressure, high temperature prospect.

A Serica CPR carried out in 2017 estimated the net P50 Prospective Resources to Serica on the Rowallan Prospect to be 19.7 mmboe.

East Irish Sea: Doyle Prospect - Blocks 113/22a, 113/26b and 113/27c, Serica 20%

Serica held a 20% non-operated interest in Blocks 113/26b and 113/27c in partnership with Zennor Petroleum. Zennor were unable to secure a partner prior to the licence termination date of 30 April 2017 and, as a result, these blocks were relinquished in Q2 2017.  The licence to the north over Block 113/27c was relinquished in December 2017.

Ireland

Rockall Basin: Frontier Exploration Licences 1/09 and 4/13, Serica 100%

Serica secured a two-year extension on Licence 4/13 up to the end of November 2018.  The licence contains structural prospects Aghla Beg and Aghla More and the overlying stratigraphic prospect Derryveagh.  During 2017, Serica completed a process to enhance the 3D seismic data over the prospects which has enabled the identification of a fractured basement play within the Aghla Beg prospect.  This work has also shown Aghla More to be relatively unfractured and so strengthens the interpretation that it comprises a clastic sedimentary section comparable to nearby Dooish discovery.

Serica estimates P50 Prospective Resources for these stacked prospects to be in the order of 4Tcf of gas and 250 million barrels of condensate.

Serica secured an extension of Licence 1/09 to January 2019. Licence 1/09 contains a large, clearly defined structural prospect, which is also analogous to the Dooish discovery.

Serica is seeking a partner to drill a well in one or both of blocks 1/09 and 4/13.

Slyne Basin: Frontier Exploration Licence 1/06, Serica 100%

Serica increased its equity from 50% to 100% following the withdrawal of DEA from the licence and secured an extension on licence 1/06 until November 2018 to further explore the potential first identified through the Bandon oil discovery drilled by Serica on the licence in 2009. Serica has completed a study to investigate the quality of oil that could be expected in the Boyne prospect located on the licence.  Results indicate that oil would be over 30^◦ API, significantly lighter than that discovered in the Bandon well and capable of producing without assistance.

Serica is seeking to identify a farm-in partner to drill the Boyne oil prospect and take advantage of current low drilling and development costs.  In the event of a commercial discovery, a swift development could be implemented to achieve an early first oil date.

Namibia

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

Serica has progressed to the first renewal period of the licence, running until the end of 2018. This licence period does not include a commitment to drill a well. The excellent 3D seismic data acquired in a major seismic programme operated by Serica, has identified giant carbonate prospects as well as large, more conventional Cretaceous fan prospects supported by seismic anomalies.  Serica plans to work on identifying more prospects supported by the latest seismic visualisation techniques as well as seeking a partner.

Morocco  

Sidi Moussa Licence: Serica 5%

Serica held 5% working interest and has withdrawn from the licence. The licence operator was previously considering a second well, in which Serica retained a back-in option, but decided to seek to undertake an alternative work programme.  In view of this decision, the materiality of a 5% interest to Serica and in line with Serica's view of the costs and benefits of retaining an interest, Serica elected to withdraw in October 2017.

LICENCE HOLDINGS

The following table summarises the Group's licences as at 31 December 2017.

Block(s)	Description	Role	% at	Location
			31/12/17
UK
22/19c	Exploration	Non-operator	15%	Central North Sea
23/16f, 23/21a (part)	Columbus Field - Development planned	Operator	50%	Central North Sea
23/26a, 23/26b	Erskine Field - Production	Non-operator	18%	Central North Sea
Ireland
27/4 (part)	Exploration	Operator	100%	Slyne Basin
27/5 (part)	Exploration	Operator	100%	Slyne Basin
27/9 (part)	Exploration	Operator	100%	Slyne Basin
5/17 (part)	Exploration	Operator	100%	Rockall Basin
5/18	Exploration	Operator	100%	Rockall Basin
5/22 (part)	Exploration	Operator	100%	Rockall Basin
5/23 (part)	Exploration	Operator	100%	Rockall Basin
5/27 (part)	Exploration	Operator	100%	Rockall Basin
5/28 (part)	Exploration	Operator	100%	Rockall Basin
11/10	Exploration	Operator	100%	Rockall Basin
11/15	Exploration	Operator	100%	Rockall Basin
12/1 (part)	Exploration	Operator	100%	Rockall Basin
12/6	Exploration	Operator	100%	Rockall Basin
12/11 (part)	Exploration	Operator	100%	Rockall Basin
Namibia
2512A	Exploration	Operator	85%	Luderitz Basin
2513A	Exploration	Operator	85%	Luderitz Basin
2513B	Exploration	Operator	85%	Luderitz Basin
2612A (part)	Exploration	Operator	85%	Luderitz Basin

GLOSSARY

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 Assets	Bruce, Keith and Rhum fields
CPR	Competent Persons Report
FDP	Field Development Plan
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 Canadian National Instrument 51‑101
Contingent Resources	Estimates of discovered recoverable hydrocarbon resources for which commercial production is not yet assured, calculated in accordance with the Canadian National Instrument 51‑101
Prospective Resources	Estimates of the potential recoverable hydrocarbon resources attributable to undrilled prospects, calculated in accordance with the Canadian National Instrument 51‑101
TAC	Technical Assistance Contract
Tcf	trillion standard cubic feet
UKCS	United Kingdom Continental Shelf

FINANCIAL REVIEW

Group profit after tax of US$17.1 million for 2017 compares to a profit after tax of US$10.8 million for 2016. Results for 2016 were adversely impacted by a six-month Erskine field shut-in running from March until August of that year.

BKR Asset acquisition

Details of the proposed acquisition, announced on 21 November 2017, of the BKR Assets from BP are covered above. The deal has an effective date of 1 January 2018 and completion of the acquisition is expected to take place in late Q3 2018. Although the most significant accounting aspects of the transaction will apply at the date of completion, under the prepayment facility arranged with BP Gas and dated 21 November 2017, BP Gas agreed to provide for drawings to cover the initial consideration and cost of premiums payable for gas price puts (hedging instruments which set a floor price for certain volumes of gas production from the BKR assets) which have been purchased by Serica in conjunction with signing the acquisition agreement.

Results from operations

Income statement - continuing operations

Serica generated a gross profit of US$19.3 million in 2017 from its Erskine field operations. The 2016 comparative gross profit of US$6.6 million reflected performance impacted by a six-month field shut-in. Serica's 18% field interest generated net combined liquids and gas production of 722,000 boe in 2017 compared to 597,000 boe for 2016.

Sales revenues

The Company currently generates all its sales revenue from the Erskine field. Revenue is earned from oil, gas and NGL product streams. Serica's condensate allocation is sold as Forties crude oil. All products are sold at monthly average spot prices for the respective products. The Brent oil benchmark averaged over US$54 per barrel in 2017 (2016: average of US$45 per barrel) whilst UK NBP gas prices averaged approximately 42 pence per therm across the 2017 period (2016: average of 35 pence per therm).

Erskine field production averaged 1,976 boe per day net to Serica in 2017 (2016: 1,636 boe per day net). Net gas production averaged 6.3 mmscf per day during 2017 (2016: 5.0 mmscf per day), whilst condensate production averaged 931 barrels per day (2016: 800 barrels per day).

Sales revenues in 2017 from lifted barrels of oil were US$17.2 million (2016: US$11.1 million) at an average realised price of US$53.2 per barrel (2016: US$42.1 per barrel). Associated NGL products earned additional revenue of US$0.4 million (2016: US$0.3 million).

Sales revenues in 2017 were offset by a US$1.2 million charge (2016: US$0.5 million credit) reflecting the movement from a combined liquids underlift position at 31 December 2016 to an overlift position at 31 December 2017 (2016: movement from overlift position at 31 December 2015 to underlift position at 31 December 2016).

The 2017 gas production was sold at prices averaging US$5.4 per mscf (2016: US$4.6 per mscf) and generated US$12.5 million (2016: US$8.4 million) of revenue net to Serica. A gas sales contract, under which Serica supplied approximately one quarter of its Erskine gas production at relatively low contract prices (approximately 30 pence per therm in the 2015/6 contract year), terminated on 30 September 2016.

Three NGL products (Propane, Butane and Naphtha) are derived from associated gas production and contributed revenue of US$3.1 million (2016: US$1.2 million) net to Serica.

Cost of sales and depletion charges

Cost of sales is driven by production from the Erskine field and comprises field operating costs and a depletion charge against the asset's net book amount.

The overall 2017 charge of US$12.7 million (2016: US$14.9 million) comprised direct field operating costs of US$11.0 million (2016: US$13.6 million) and non-cash depletion of US$1.7 million (2016: US$1.3 million). Serica's operating costs including transportation and processing were around US$15 per boe during 2017, averaging well below 2016 levels of US$23 per boe, which were adversely affected by the shut-in.  The most significant elements of the field operating costs are as follows: Erskine's contribution to the running costs of the Lomond facilities, standalone Erskine field operating costs, other transportation costs for use of the FPS and CATS pipelines, and charges for any necessary surface or sub-surface maintenance work. Significant operational expenditure continues during periods of field shut-in when no revenue is earned.

The US$2.6 million decrease in field operating costs from 2016 to 2017 is largely due to lower overall contributions by Erskine to Lomond facilities operating costs, arising from   cost savings generated by the Lomond operator. The 2016 expense also included an agreed level of contribution from the Erskine partners to the exceptional costs incurred by the Lomond operator to resolve a Lomond to Everest pipeline blockage. Operating costs are billed in £ and, with the average £/US$ exchange rate falling from 1.36 in 2016 to 1.29 in 2017, the reported US$ equivalent figures have reduced accordingly in 2017.

Depletion charges principally represent the costs of Erskine acquisition spread over the estimated remaining commercial life of the field on a unit of production basis. 

Other expenses and income

The Company generated a profit before tax from continuing operations of US$10.8 million for 2017 compared to a profit before tax of US$3.3 million for 2016.

Other expenditure of US$1.4 million in 2017 (2016: US$0.1 million) represented hedging premium, including unrealised hedging losses of US$1.1 million, net of gains.

Pre-licence expenditure of US$0.3 million for 2017 has increased slightly from the 2016 charge of US$0.2 million. Pre-licence costs included direct costs and allocated general administrative costs incurred on oil and gas activities prior to the award of licences, concessions or exploration rights.

The Exploration and Evaluation ('E&E') asset impairment charge of US$1.6 million in 2017 (2016: US$0.1 million) comprised US$1.5 million of asset write-offs from the relinquished Doyle block in the UK and minor asset write-offs from licences in Morocco and the UK.

Administrative expenses of US$2.2 million for 2017 increased slightly from US$2.1 million in 2016.

Foreign exchange

Serica retains certain non-US$ cash holdings and other financial instruments relating to its operations. The US$ value of these may fluctuate from time to time causing reported foreign exchange gains and losses.

Foreign exchange gains of US$0.5 million for 2017 (2016: US$0.6 million charge) largely reflect an increase in the reported US$ equivalent of £ cash balances caused by the strengthening of £ against the US$ during 2017. Unrealised gains on the revaluation of £ cash balances have been partially offset by realised losses on settlement of significant £ creditors.  

Other

Significant transaction costs of US$3.4 million were expensed in 2017 on the proposed acquisition, announced on 21 November 2017, of the BKR Assets from BP. These were largely incurred on the negotiation and documentation of the transaction and on the AIM Admission Document published on 30 November 2017. It also included other consultancy and advisor fees arising throughout the process.

Finance costs of US$0.1 million were incurred in 2017 (2016: US$0.2 million) largely comprising the interest accruing on the liability payable to BP relating to the Erskine acquisition.

Serica's significant UK ring fence tax losses brought forward have been applied to fully shelter Erskine net income from tax payments and are expected to be sufficient to cover future income from the field leaving a surplus available that can be applied to revenues from BKR Asset acquisition after completion. The Group held approximately US$146 million of UK ring fence tax losses as at 31 December 2017.

The deferred taxation credit of US$6.3 million (2016: US$7.5 million) arose from the recognition of a corresponding deferred tax asset from historic tax losses expected to be utilised from future Erskine field profits.

Income statement - discontinued operations

Following the cessation of production and the decommissioning of the Kambuna field facilities in Indonesia in the second half of 2013, the financial results of the Kambuna field business segment are disclosed within 'discontinued operations' in the financial statements and separate from the results of the retained core business segments.

This discontinued operation loss of US$8,000 in 2016 comprised the final charge recorded against this operation.

Balance Sheet

During 2017, the total carrying value of investments in E&E assets increased by US$0.2 million from US$53.2 million to US$53.4 million. This increase consisted of US$1.8 million of additions in the year largely offset by US$1.6 million of E&E asset write-offs. In the UK, US$0.8 million was incurred on the Columbus development and other exploration licences. In Ireland, US$0.4 million was incurred on exploration work on the Rockall licences and US$0.3 million on the Slyne interest. In Africa, US$0.3 million was incurred in respect of the Luderitz basin licence interests in Namibia.

The property, plant and equipment balance of US$7.6 million as at 31 December 2017 (2016: US$9.1 million) comprises the net book amount of the Erskine asset acquisition costs capitalised on completion of the transaction net of depletion charges to date.

Trade and other receivables at 31 December 2017 totalled US$2.3 million, a decrease of US$4.5 million from the 2016 balance of US$6.8 million. The 2017 balance includes US$1.2 million (2016: US$4.3 million) from December oil, gas and NGL sales earned from the Erskine field.

The financial asset of US$2.7 million reflects the fair value as at 31 December 2017 of a prepayment for gas put options covering production volumes through 2018 to 1H 2020, purchased in conjunction with signing the BKR Assets acquisition agreement (2016: US$nil).

Cash and cash equivalents, and short-term deposits, increased from US$16.6 million to US$34.0 million during the year. Operating cash inflows from net Erskine field sales were generated in 2017 providing a strong cash build for the Company in the year. The Company also paid the third US$2.8 million tranche of Erskine consideration to BP and significant corporate costs arising from the BKR Assets acquisition. Other cash outflows were incurred on E&E assets across the portfolio in the UK, Ireland and Namibia, ongoing administrative costs and corporate activity. 

Short-term trade and other payables totalled US$7.8 million at 31 December 2017 (2016: US$5.9 million). This balance comprises the US$3.0 million (including accrued interest) final tranche of Erskine consideration payable to BP on 1 July 2018, US$1.5 million of liabilities associated with the BKR Assets acquisition, capital and operational liabilities for the Erskine interest, a US$0.8 million non-cash overlift liability reflecting the combined year end liquids overlift position (2016: US$0.4 million underlift classified as an asset within trade and other receivables) and other creditors and accruals for E&E asset, corporate and administrative expenditure.

Provisions of US$2.7 million comprise current (US$2.2 million) and non-current (US$0.5 million) components of an estimate for certain contingent payments related to savings in field operating costs that may be made to BP under the terms of the Erskine acquisition.

Long-term financial liabilities of US$3.8 million as at 31 December 2017 comprise drawings under the BKR prepayment facility. These cover the up-front premium cost of gas price puts purchased in conjunction with signing the BKR Assets acquisition agreement. The prepayment facility carries interest at one-month LIBOR plus 4.5% per annum compounded monthly and added to the outstanding amount and has a maximum duration of three years from initial drawings. Repayments will commence six months after completion and be based on 35% of Serica's retained share of gas sales revenues from the BKR Assets including any price related hedging gains and after deduction of those proportions due to BP under the Net Cash Flow Sharing Deed.

Long-term liabilities of US$2.9 million as at 31 December 2016 comprised the final tranche of Erskine consideration payable to BP on 1 July 2018. 

Serica's share of estimated decommissioning costs relating to its 18% Erskine field interest will be met by BP up to a level of £31.3 million, adjusted for inflation, with Serica being responsible for any costs beyond that. No provision for decommissioning liabilities for the Erskine field is recorded at 31 December 2017 as the Company's current estimate for such costs is under the level to be funded by BP.

Cash balances and future commitments

Current cash position, capital expenditure commitments and other obligations

At 31 December 2017, the Group held cash and cash equivalents, and term deposits of US$34.0 million. Cash and term deposits had reduced to US$33.0 million by 6 April 2018, including cash receipts in respect of approximately 35,000 barrels of oil overlift that will be adjusted for during Q2 2018.

At 31 December 2017, the Group held put options covering 2018, 2019 and 1H 2020 daily volumes of 230,000, 240,000 and 160,000 therms of gas per day respectively, at floor prices of 35 pence per therm.

At 31 December 2017, in addition to the gas price puts referred to above, the Group held put options covering Q1 2018 daily volumes of 900 barrels of oil per day at a floor price of US$55 per barrel.

Erskine field commitments

Net revenues from the Erskine field are expected to cover ongoing field expenditures as well as the remaining tranche of US$2.8 million (before interest) cash consideration payable to BP on or before 1 July 2018.   

Management believes there are sufficient resources to meet the current committed programme for 2018 but remains conscious that a single field income stream exposes it to operational and infrastructure risks and the consequent need for adequate working capital to cover associated fluctuations in revenue.  The field has a history of intermittent production performance and operational expenditure continues during periods of field shut-down when no revenue is earned. Completion of the BKR Assets acquisition will diversify the Group's sources of revenue.

Non-Erskine commitments

The Group has no significant exploration commitments.

Progress towards the Columbus development continues with a target to compile a Field Development Plan by mid-2018. Financing plans for the project will be worked in conjunction with the FDP submission.

Other

Asset values and Impairment

At 31 December 2017, Serica's market capitalisation stood at US$298.8 million (£221.5 million), based upon a share price of £0.84, which exceeded the net asset value at that date of US$102.3 million. By 6 April 2018 the Company's market capitalisation had decreased to US$241.6 million (£171.4 million). Management has conducted a thorough review of the carrying value of the Group's assets and determined that no significant write-downs were required.

Business Risk and Uncertainties

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 in all operations, to carry insurance where available and cost effective, and to retain adequate working capital.

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

Investment Returns: Management seeks to raise funds and then to generate shareholder returns though investment in a portfolio of exploration, development and producing acreage leading to the discovery and exploitation of commercial reserves. Delivery of this business model carries a number of key risks.
Risk	Mitigation
Market support may be eroded obstructing fundraising and lowering the share price	·      Management regularly communicates its strategy to shareholders ·     Focus is placed on building an asset portfolio capable of delivering regular news flow and offering continuing prospectivity
Management's decisions on capital allocation may not deliver the expected successful outcomes	·      Rigorous analysis is conducted of all investment proposals ·      Investments are spread over a range of areas and risk profiles
Each asset carries its own risk profile and no outcome can be certain	·      Management aims to avoid over-exposure to individual assets and to identify the associated risks objectively

Operations: Operations may not go according to plan leading to damage, pollution, cost overruns or poor outcomes.
Risk	Mitigation
The Group's income is currently derived from a single producing field	·      Efforts are underway to add to producing assets with a major acquisition in progress ·      Management places a priority on building and retaining sufficient working capital
Individual wells may not deliver recoverable oil and gas reserves	·      Thorough pre-drill evaluations are conducted to identify the risk/reward balance ·      Exposure is selectively mitigated through farm-out
Wells may blow out or equipment may fail causing environmental damage and delays	·      The Group retains fully trained and experienced personnel ·      The planning process involves risk identification and establishment of mitigation measures ·      Emphasis is placed on engaging experienced contractors ·      Appropriate insurances are retained
Operations may take far longer or cost more than expected	·      Management applies rigorous budget control ·      Adequate working capital is retained to cover reasonable eventualities
Production may be interrupted generating significant revenue loss	·      Business interruption cover will be considered when appropriate
Offtake routes may depend upon a series of facilities and pipelines requiring a balance of throughput from a number of different fields	·      The Group aims to diversify its sources of income when suitable opportunities can be identified
Resource estimates may be misleading and exceed actual reserves recovered	·      The Group deploys qualified personnel ·      Regular third-party reports are commissioned ·      A prudent range of possible outcomes are considered within the planning process

Personnel: The Group relies upon a pool of experienced and motivated personnel to identify 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 competitive ·      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, typically offshore	·      A culture of safety is encouraged throughout the organisation ·      Responsible personnel are designated at all appropriate levels ·      The Group maintains up-to-date emergency response resources and procedures ·      Insurance cover is carried in accordance with industry best practice
Staff and representatives may find themselves exposed to bribery and corrupt practices	·      Group policies and procedures are communicated to personnel regularly ·      Management reviews all significant contracts and relationships with agents and governments

Commercial environment: World and regional markets continue to be volatile with fluctuations and infrastructure access issues that might hinder the Group's business success
Risk	Mitigation
Volatile commodity prices mean that the Group cannot be certain of the future sales value of its products	·      Budget planning considers a range of commodity prices ·      Price mitigation strategies may be employed at the point of major capital commitment ·      Oil and gas price hedging contracts may be utilised where viable
The Group may not be able to get access, at reasonable cost, to infrastructure and product markets when required	·      A range of different off-take options are pursued wherever possible
Credit to support field development programmes may not be available at reasonable cost	·      Serica seeks to build and maintain strong banking relationships and   initiates funding discussions at as early a stage as practicable
Fiscal regimes may vary, increasing effective tax rates and reducing the expected value of reserves	·      Operations are currently spread over a range of different fiscal regimes in Western Europe and Africa ·      Before committing to a significant investment the likelihood of fiscal term changes is considered when evaluating the risk/reward balance

In addition to the principal risks and uncertainties described herein, the Group is subject to a number of other risk factors generally, a description of which is set out in our latest annual information form available on www.sedar.com.

Key Performance Indicators ("KPIs")

The Company's main business is the acquisition of interests in prospective exploration acreage, the discovery of hydrocarbons in commercial quantities and the crystallisation of value whether through production or disposal of reserves. The Company tracks its non-financial performance through the accumulation of licence interests in proven and prospective hydrocarbon producing regions, the level of success in encountering hydrocarbons and the development of production facilities. In parallel, the Company tracks its financial performance through management of expenditures within resources available, the cost-effective exploitation of reserves and the crystallisation of value at the optimum point. A review of the Company's progress against these KPIs is covered in the operations and financial review within this Strategic Report.

Additional Information

Additional information relating to Serica, can be found on the Company's website at www.serica-energy.com and on SEDAR at www.sedar.com

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

On behalf of the Board

Mitch Flegg

Chief Executive Officer

9 April 2018

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

		2017	2016
	Note	US$000	US$000
Continuing operations
Sales revenue	4	31,966	21,432
Cost of sales	5	(12,668)	(14,860)
Gross profit		19,298	6,572
Other expense		(1,426)	(113)
Pre-licence costs		(303)	(240)
Impairment and write-offs of E&E assets	14	(1,612)	(62)
Administrative expenses		(2,244)	(2,062)
Foreign exchange gain/(loss)		511	(556)
Share-based payments	27	(98)	(90)
Operating profit before net finance revenue, tax		14,126	3,449
and transaction costs
BKR transaction costs		(3,386)	-
Finance revenue	10	246	61
Finance costs	11	(138)	(185)
Profit before taxation		10,848	3,325
Taxation credit for the year	12a)	6,255	7,521
Profit for the year from continuing operations		17,103	10,846
Discontinued operations
Loss for the year from discontinued operations	3	-	(8)
Profit for the year		17,103	10,838
Earnings per ordinary share - EPS
Basic and diluted EPS on continuing operations (US$)	13	0.06	0.04
Basic and diluted EPS on profit for the year (US$)	13	0.06	0.04

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
		2017	2016	2017	2016
	Note	US$000	US$000	US$000	US$000
Non-current assets
Exploration & evaluation assets	14	53,413	53,170	-	-
Property, plant and equipment	15	7,640	9,078	-	-
Investments in subsidiaries	16	-	-	1,350	1,350
Deferred tax asset	12d)	16,209	9,954	-	-
		77,262	72,202	1,350	1,350
Current assets
Inventories	17	453	401	-	-
Trade and other receivables	18	2,274	6,849	83,269	70,141
Derivative financial asset	19	2,670	-	-	-
Term deposits	20	5,698	-	1,350	-
Cash and cash equivalents	20	28,279	16,593	18,712	14,066
		39,374	23,843	103,331	84,207
TOTAL ASSETS		116,636	96,045	104,681	85,557
Current liabilities
Trade and other payables	21	(7,825)	(5,877)	(2,385)	(462)
Provisions	23	(2,234)	-	-	-
Non-current liabilities
Trade and other payables	22	-	(2,883)	-	-
Financial liabilities	19	(3,825)	-	-	-
Provisions	23	(456)	(2,190)	-	-
TOTAL LIABILITIES		(14,340)	(10,950)	(2,385)	(462)
NET ASSETS		102,296	85,095	102,296	85,095
Share capital	25	229,308	229,308	194,036	194,036
Merger reserve	16	-	-	-	-
Other reserve		20,813	20,715	20,813	20,715
Accumulated deficit		(147,825)	(164,928)	(112,553)	(129,656)
TOTAL EQUITY		102,296	85,095	102,296	85,095

The profit for the Company was US$17,103,000 for the year ended 31 December 2017 (2016: profit of US$10,838,000). 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 9 April 2018

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	Note	Share capital	Other reserve	Accum'd deficit	Total
		US$000	US$000	US$000	US$000
At 1 January 2016		229,308	20,625	(175,766)	74,167
Profit for the year		-	-	10,838	10,838
Total comprehensive income		-	-	10,838	10,838
Share-based payments	27	-	90	-	90
At 31 December 2016		229,308	20,715	(164,928)	85,095
Profit for the year		-	-	17,103	17,103
Total comprehensive income		-	-	17,103	17,103
Share-based payments	27	-	98	-	98
At 31 December 2017		229,308	20,813	(147,825)	102,296

Company		Share capital	Other reserve	Accum'd deficit	Total
		US$000	US$000	US$000	US$000
At 1 January 2016		194,036	20,625	(140,494)	74,167
Profit for the year		-	-	10,838	10,838
Total comprehensive income		-	-	10,838	10,838
Share-based payments	27	-	90	-	90
At 31 December 2016		194,036	20,715	(129,656)	85,095
Profit for the year		-	-	17,103	17,103
Total comprehensive income		-	-	17,103	17,103
Share-based payments	27	-	98	-	98
At 31 December 2017		194,036	20,813	(112,553)	102,296

Serica Energy plc

Cash Flow Statement

For the year ended 31 December

	Note	Group 2017 US$000	2016 US$000	Company 2017 US$000	2016 US$000
Operating activities:
Profit for the year		17,103	10,838	17,103	10,838
Adjustments to reconcile profit for the year
to net cash flow from operating activities:
Taxation credit		(6,255)	(7,521)	-	-
BKR transaction costs		3,386	-	-	-
Net finance (income)/costs		(108)	124	(246)	(56)
Depreciation and depletion		1,710	1,274	-	-
Oil and NGL over/underlift		1,163	(516)	-	-
Impairment and write-offs of E&E assets		1,612	62	-	-
Unrealised hedging losses		1,133	-	-	-
Write-back of loans and investments		-	-	(17,909)	(12,954)
Share-based payments		98	90	98	90
Other non-cash movements		(406)	866	(302)	1,100
Cash outflow on BKR transaction		(1,867)	-	-	-
Increase in financial assets		(3,803)	-	-	-
Decrease/(increase) in trade and other		4,110	(1,862)	(671)	(197)
receivables
(Increase)/decrease in inventories		(52)	52	-	-
(Decrease)/increase in trade and other		(291)	(3,270)	1,905	(109)
payables
Net cash in/(out)flow from operations		17,533	137	(22)	(1,288)
Investing activities:
Interest received		246	61	246	61
Purchase of E&E assets		(1,855)	(1,418)	-	-
Purchase of P,P&E		(72)	-	-	-
Cash outflow arising on asset acquisition	21	(2,775)	(2,775)	-	-
Receipts from Group subsidiaries		-	-	5,358	2,336
Net cash flow from investing activities		(4,456)	(4,132)	5,604	2,397

Financing activities:
Changes in term deposits		(5,698)	-	(1,350)	-
Proceeds from borrowings	19	3,803	-	-	-
Finance costs paid		(135)	(77)	-	(5)
Net cash flow from financing activities		(2,030)	(77)	(1,350)	(5)
Net increase/(decrease) in cash and cash equivalents	26	11,047	(4,072)	4,232	1,104
Effect of exchange rates on cash and cash
equivalents	26	639	(937)	414	(768)
Cash and cash equivalents at 1 January	26	16,593	21,602	14,066	13,730
Cash and cash equivalents at 31 December	26	28,279	16,593	18,712	14,066

Serica Energy plc

Notes to the Financial Statements

1.   Authorisation of the Financial Statements and Statement of Compliance with IFRS

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 2017 were authorised for issue by the Board of Directors on 9 April 2018 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 52 George Street, London, W1U 7EA. 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, Ireland, and Namibia. The Company's ordinary shares are traded on AIM.

The Group's financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as adopted by the EU as they apply to the financial statements of the Group for the year ended 31 December 2017. The Company's financial statements have been prepared in accordance with IFRS as adopted by the EU as they apply to the financial statements of the Company for the year ended 31 December 2017 and as applied in accordance with the provisions of the Companies Act 2006. The Group's financial statements are also prepared in accordance with IFRS as issued by the IASB. 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 US$17,103,000 (2016: profit US$10,838,000).

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 2017.

The Group and Company financial statements have been prepared on a historical cost basis and are presented in US dollars. All values are rounded to the nearest thousand dollars (US$000) 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 2017 the Company held net current assets of US$29.3 million including cash and term deposits of US$34.0 million.  The Erskine asset acquisition, completed in early June 2015 brought to Serica a producing interest capable of generating robust positive cash flow at current oil and gas prices. Existing resources plus Erskine revenues are expected to be sufficient to cover ongoing Erskine costs and the outstanding instalments of the acquisition price plus other operational, technical and administrative costs in the short-to-medium term. When the final decision to proceed with the Columbus development is made, the Group would consider a range of alternative means of finance to fund its share of development costs.

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 foreseeable future. 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 IFRS 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: the assessment of commercial reserves, the impairment of the Group and Company's assets (including oil & gas development assets and Exploration and Evaluation "E&E" assets), and the recoverability of deferred tax assets.

Assessment of commercial 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. There has been no significant change to the management estimates and assumptions during the year that may impact the assessment of commercial reserves.

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 Group's most significant E&E asset is Columbus which is recorded in the Balance Sheet as at 31 December 2017 with a net book amount of US$40.8 million. The carrying amount is dependent on the assumption that the terms of the licence extension to September 2018 continue to be met, as outlined in further detail in the Review of Operations. 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 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).

Deferred tax assets

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. The most significant variable behind the increased deferred tax asset recognised in 2017 from 2016 is the increase in management's estimate of short-term forward commodity prices from prior year as other variables have remained largely unchanged. The most significant pricing assumptions are based on forward curve prices for the first three years. To the extent that future cash flows and taxable income 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 Foum Draa 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 all its subsidiaries is US dollars.

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 and included in administrative expenses.

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.

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.

Farm-ins

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

Capitalisation

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, borrowing costs.

Depletion

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 recognised proved and probable reserves. Changes in reserve quantities and cost estimates are recognised prospectively from the last reporting date.

Impairment

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.

Decommissioning

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.

Underlift/Overlift

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'). Movements during an accounting period are adjusted through revenue, such that gross profit is recognised on an entitlement basis.

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.

Inventories

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.

Investments

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

Financial assets within the scope of IAS 39 are classified as either financial assets at fair value through profit or loss, or loans and receivables, as appropriate. When financial assets are recognised initially, they are measured at fair value. Transaction costs that are directly attributable to the acquisition or issue of the financial asset are capitalised unless they relate to a financial asset classified at fair value through profit and loss in which case transaction costs are expensed in the income statement.

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.

Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. After initial measurement loans and receivables are subsequently carried at amortised cost, using the effective interest rate method, less any allowance for impairment. Amortised cost is calculated by taking into account any discount or premium on acquisition over the period to maturity. Gains and losses are recognised in the income statement when the loans and receivables are de-recognised or impaired, as well as through the amortisation process.

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 include interest bearing loans and borrowings, and trade and other payables.

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.

Equity

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

Provisions

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 fair value 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. In determining fair value it is necessary to make a series of assumptions to estimate future operating costs and other variables. Accordingly, the fair value is categorised as Level 3 in the fair value hierarchy.

Leases

Operating lease payments are recognised as an operating expense in the income statement on a straight line basis over the lease term.

Revenue Recognition

Revenue is recognised to the extent that it is probable that the economic benefits will flow to the Group and the revenue can be reliably measured. 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. Revenue from oil and natural gas production is recognised on an entitlement basis for the Group's net working interest.

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 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.

New and amended standards and interpretations

The Group has adopted and applied the following standards that are relevant to its operations for the first time for the annual reporting period commencing 1 January 2017:

-   Amendments to IAS 12 Income Taxes - Recognition of Deferred Tax Assets for Unrealised Losses;

-   Annual Improvements to IFRSs (2014 - 216 Cycle): IFRS 12 Disclosure of interests in other entities; and

-   Disclosure Initiative Amendments - IAS 7 Statement of Cash Flows.

There are no new or amended standards or interpretations effective for the first time for periods beginning on or after 1 January 2017 that had a significant impact on the financial statements.

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.

Standard	Effective year commencing on or after
IFRS 9 - Financial Instruments	1 January 2018
IFRS 15 - Revenue from Contracts with Customers	1 January 2018
IFRS 16 - Leases	1 January 2019 *

*Not yet endorsed by the EU

IFRS 9 Financial Instruments

In July 2014, the IASB issued the final version of IFRS 9 Financial Instruments which replaces IAS 39 Financial Instruments: Recognition and Measurement and all previous versions of IFRS 9. The standard introduces new requirements for classification and measurement, impairment under the 'expected credit loss' ('ECL') model and hedge accounting. IFRS 9 is effective for annual periods beginning on or after 1 January 2018, with early application permitted. The Group plans to adopt the new standard on the required effective date and will not restate comparative information. During 2017, the Group has performed an impact assessment for the application of IFRS 9. This assessment is based on currently available information and may be subject to changes arising from further reasonable and supportable information being made available to the Group in 2018. 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, therefore the Group does not believe that the new ECL impairment methodology will have a material impact on the valuation of financial assets. The Company's review of the impact of the new ECL impairment methodology on intercompany receivables is ongoing.

IFRS 15 Revenue from Contracts with Customers

IFRS 15 was issued in May 2014 and amended in April 2016. It establishes a single comprehensive model that will apply to revenue arising from contracts with customers. IFRS 15 will supersede the current revenue recognition guidance including IAS 18 Revenue and related interpretations when it becomes effective, for annual periods beginning on or after 1 January 2018.

Although IFRS 15 does not generally represent a change from Serica's current practice, and the impact review is ongoing, the accounting for certain contracts, such as those for underlifts and overlifts, have been identified as areas of potential change. Movements in liquids overlift/underlift currently disclosed in sales revenue (see note 4) will be classified in cost of sales.

IFRS 16 Leases

IFRS 16 Leases, issued in January 2016, sets out the principles for the recognition, measurement, presentation and disclosure of leases for both lessors and lessees. It replaces the previous leases standard IAS 17 Leases and is effective from 1 January 2019. Under the new standard all lease contracts, with limited exceptions, are recognised in financial statements by way of right of use assets and corresponding lease liabilities. Compared with the existing accounting for operating leases, it will also impact the classification and timing of expenses and consequently the classification between cash flow from operating activities and cash flow from financing activities.

Serica will not early adopt IFRS 16. The impact of the adoption of the new standard at 1 January 2019, will be dependent on factors such as Serica's lease contracts at that date and the discount rate to be applied in accordance with IFRS 16, and therefore the impact cannot be determined from the disclosure of the minimum lease payments in accordance with IAS 17 in Note 28, which are not currently material. A detailed review of Serica's contracts is under way to determine the impact of the new standard.

 

END

 

 

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