Results for the year ended 31 December 2018
Serica Energy plc
("Serica" or the "Company")
Results for the year ended 31 December 2018
London, 17 April 2019 - Serica Energy plc (AIM: SQZ) today announces its financial results for the year ended 31 December 2018. The results are included below and copies are available at www.serica-energy.com and www.sedar.com.
Corporate Highlights
· Acquisitions comprising 98% of the Bruce field, 100% of the Keith field and 50% of the Rhum field completed and operatorship transferred on 30 November 2018
· Net US$28 million receipt at completion with initial consideration more than offset by share of net field cash flows from 1 January 2018 up to completion
· Columbus Field Development Plan ("FDP") approved by the Oil and Gas Authority ("OGA") and Joint Venture Partners
· Net 2P reserves at year end have increased to 68.8 million boe reflecting an increase in Erskine reserves and addition of Columbus reserves
Financial
· Gross profit increased by 30.6% to US$25.2 million (2017: US$19.3 million) reflecting one month of post completion BKR income plus two and a half months of income from Erskine after an extended shut-in to complete a bypass of the condensate export line
· Operating profit of US$9.1 million (2017: US$14.1 million) was impacted by one-off BKR transition costs of US$11.7 million
· Group profit after tax of US$74.7 million (2015: US$17.1 million) showed a 337% increase. This figure includes a bargain purchase gain of US$52.9 million on the BKR acquisitions calculated in accordance with IFRS
· Cash balances and term deposits stood at US$91.8 million at 31 March 2019, compared to US$54.9 million at 31 December 2018, a US$36.9 increase during the first three months of 2019
Operational
Bruce, Keith and Rhum Fields (Serica 98%, 100%, 50%)
· Full year production (net to the BKR interests acquired by Serica) for 2018 amounted to over 24,000 boe/d.
Erskine Field (Serica 18%)
· The Erskine field has performed strongly since production was restarted on 24 October 2018 after replacing a section of Lomond to CATS riser condensate export line
· Production has averaged over 3,100 boe per day net to Serica during the five-month period to end March 2019
· An updated independent audit of Erskine field reserves, following the Lomond export facilities upgrade, has increased Serica's share of estimated remaining 2P reserves to 5.7 million boe as at 31 December 2018, an 84% increase over the 3.1 million boe estimated at 31 December 2017
Columbus Development (Serica 50%)
· Serica submitted an FDP to the OGA in June 2018 and was granted development and production consent in October 2018. Development work started as soon as FDP approval was received. First gas is targeted for 2021
· Columbus resources have been re-classified as reserves by independent reserves auditors who ascribe to Serica net 2P reserves of 6.2 million boe within the Columbus development area as of 1 January 2019
Exploration
· The Rowallan exploration well (22/19c-7) was drilled to target the high pressure, high temperature Rowallan Prospect. The well encountered 182 metres of sandstones and shales but did not contain hydrocarbons. Serica was fully carried on all costs associated with this licence and so did not incur any costs in the planning and drilling of the Rowallan exploration well
· The Company was awarded four licences on the UK Continental Shelf in the UK's 30th Offshore Licensing Round
Outlook
· The Company continues to see strong income flows since the turn of the year. Net production from the Bruce, Keith, Rhum and Erskine fields has totalled over 30,000 boe/d in Q1 2019
Other
· Serica is pleased to announce the appointment of Jefferies as joint broker to the Company with immediate effect. Peel Hunt will continue to act as Nominated Advisor and joint broker to the Company
Commenting on the results, Mitch Flegg, Serica's CEO stated:
"2018 has been a year of incredible achievement. Serica has established itself as one of the leading independent UKCS operating companies and has assembled a talented and motivated operating team. We intend to use these skills to continue to optimise the value of all of our assets. In particular we aim to extend the field life of the BKR assets by concentrating on enhancing recovery and reducing costs through eliminating unnecessary complexity. The multi-disciplinary team is already delivering exceptional results as demonstrated by the continued strong production during the first four months of Serica BKR operatorship.
We also aim to expand the portfolio at all stages - exploration, appraisal, development and production. Our operating expertise is based around the Central and Northern North Sea and (coupled with tax synergies) this means that the search for new opportunities is currently focused on the UKCS. Serica's growth has been supported by our commitment to identify opportunities based on value rather than volume. We will continue to look for assets (preferably operated rather than non-operated), where Serica can add value when the current operator may be unable to do so."
Regulatory
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).
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Enquiries:
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Serica Energy plc |
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Tony Craven Walker Executive Chairman |
tony.cravenwalker@serica-energy.com |
+44 (0)20 7457 2020 |
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Mitch Flegg CEO |
+44 (0)20 7457 2020 |
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Peel Hunt (Nomad & Joint Broker) |
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Richard Crichton |
+44 (0)20 7418 8900 |
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Ross Allister |
+44 (0)20 7418 8900 |
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James Bavister |
james.bavister@peelhunt.com |
+44 (0)20 7418 8900 |
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Jefferies (Joint Broker) |
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Tony White |
+44 (0)20 7029 8000 |
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Will Souter |
will.souter@jefferies.com |
+44 (0)20 7029 8000 |
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Instinctif |
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David Simonson |
+44 (0)20 7457 2020 |
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Sarah Hourahane |
+44 (0)20 7457 2020 |
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Dinara Shikhametova |
dinara.shikhametova@instinctif.com |
+44 (0)20 7457 2020 |
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NOTES TO EDITORS
Serica Energy is a British independent 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.
Towards the end of 2018, Serica completed transactions which resulted in Serica UK holding a 98% interest in the Bruce field, a 100% interest in the Keith field and a 50% interest in the Rhum field and being operator of all three fields and asset infrastructure.
Serica holds an 18% non-operated interest in the producing Erskine field in the UK Central North Sea and a 50% operated interest in the Columbus Development which has been approved by the OGA and is scheduled to commence development in 2019.
Further information on the Company can be found at www.serica-energy.com.
The Company's shares are traded on the AIM market of the London Stock Exchange under the ticker SQZ and the Company is a designated foreign issuer on the TSX. To receive Company news releases via email, please subscribe via the Company website.
FORWARD LOOKING STATEMENTS
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.
EXECUTIVE CHAIRMAN'S STATEMENT
The past year has been pivotal for Serica, a year of real achievement for all stakeholders, employees and shareholders alike and lays the foundations for future growth. Completion of the purchase of operated interests in the Bruce, Keith and Rhum fields from BP (the "BKR fields") together with subsequent transactions to buy additional interests in the Bruce and Keith fields from Total, BHP and Marubeni, has brought very material financial and strategic benefits to the Company and its shareholders. The transactions included a complex restructuring of partnership interests which has enabled production to continue seamlessly to the benefit of the UK as well as to Serica and field partners. We are delighted with the outcome.
Serica is now one of the leading UK Independent companies operating in the UK sector of the North Sea. We operate one of the major offshore facilities, handling up to 50,000 boe/d of gas and liquids production. Plans to improve and extend field performance are in hand, Columbus is now approved for development and, with new investment opportunities continually under review, we are strongly placed to grow and generate value for shareholders.
Although production from the Erskine field was closed for over nine months of last year and production from the BKR fields is only included for the month of December we are reporting strong results for the year. Gross profit for 2018 was up by 31% at US$25.2 million and profit after tax was US$74.7 million, the latter largely influenced by the significant purchase gain that we are required to record on the BKR transactions under IFRS and also by the accelerated utilisation of tax assets.
We continue to see strong levels of production. Serica's net share of production from Erskine and the BKR fields for the first three months of 2019 has exceeded 30,000 boe/d, an approximately fifteen-fold increase over the levels prior to suspension of Erskine production one year earlier. This indicates the impact of the BKR transactions.
This major production increase is generating substantial inward net cash flows. With 37% of our 2019 gas production, adjusted for net cash flow sharing, hedged at a floor of 35p/therm and over 20% of our production in oil, revenue generation is well balanced and robust at the current price deck. Serica's net cash balances at 31 March 2019 have risen to US$92 million, up from US$55 million at the end of December, and give an indication of the cash generating capability of our assets.
We are very proud of the team at Serica which has enabled this to happen and the optimum risk/reward sharing basis on which it was structured, obviating the need for further fund raising and protecting shareholders' interests. Our strong cash flow and operating capabilities provide an enviable platform from which Serica can continue to build for the future. It is a testament to what can be achieved by a small but highly experienced team.
By building up a production base to which we can add value though our own expertise Serica is well on its way to achieving the first steps of its strategic objectives. This commenced with the acquisition of our interest in the producing Erskine field just under four years ago. Although a small beginning this generated material benefit to the Company and continues to do so. The acquisition of the BKR field interests now opens up a whole new dimension and range of opportunity for Serica to broaden its portfolio and participate in the full cycle of upstream activities.
Whilst we are not averse to taking on assets overseas we will be focusing our immediate attention on the North Sea which is going through a period of evolution as major companies restructure their asset portfolios. As an experienced and now fully established North Sea operating company Serica is in a good position to play its part and benefit from these changes. We have opened a new operating base in Aberdeen to handle operations. The team which has joined us from BP to operate the fields and the new employees who have joined us to help manage the operations provide us with the capability to take on new projects and we have both the balance sheet strength with minimal borrowings and the increasing cash resources to do so.
Which brings me to the people. None of this would be possible without the skills of the people involved and the knowledge and experience of those who were responsible for the efficient and safe transfer of operations from BP and who will take the Company forward. I know that shareholders will wish me to thank them.
At the Board we are also seeing changes in parallel with the Company's expanding operations and we will continue to review the optimum Board composition for a Company of Serica's size and responsibilities. We have recently appointed Trevor Garlick and Malcolm Webb as non-executive Directors, both of them joining the Company at the end of November. Trevor's knowledge of the North Sea industry from his time at BP, where he was latterly Regional President of BP's North Sea Business, will be invaluable to us whilst Malcolm brings a deep knowledge of the UK industry gained from his time in the industry and latterly as CEO of Oil & Gas UK. Both bring experience and knowledge complementing that already existing on the Board. We welcome them both.
In summary, Serica has had a remarkable year and now has an enviable portfolio of cash generating assets which have considerable unlocked value. I strongly believe that the Company has the team, the experience, the financial strength and the capability to unlock this value and also build new opportunities for increased returns for the benefit of shareholders. We intend to achieve these objectives both organically and through further asset acquisitions and consolidations which have the potential to utilise our strengths, exploit synergies and build upon our strong operating capabilities.
Our underlying target and focus is to increase shareholder value. We will continually be seeking ways of doing so as our financial position strengthens. This will include the possibility of generating financial returns for shareholders commensurate with our value growth objectives when we feel that the Company has the capacity to do so. I am confident that the Company has the capability and is well on the path to achieving these goals.
Tony Craven Walker
Chairman
16 April 2019
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 2018.
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 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.
CEO's REVIEW OF 2018
The word transformational is perhaps overused in corporate reports but 2018 was a truly transformational year for Serica. We had finished 2017 with seven employees, net 2P reserves of 3.1 million boe, average net production of less than 2,000 boe/d and cash and deposits of US$34 million. By the end of 2018 the Group had 140 employees, net 2P reserves of 68 million boe, average net production of over 25,000 boe/day and despite completing the major acquisition of the Bruce, Keith and Rhum assets we had grown our cash and deposits to US$55 million. We still hold no debt other than a prepayment facility arranged with BP as part of the BKR Acquisition and our liquidity has remained strong throughout the period.
There were a number of significant events during the year and these illustrate the diversity of Serica's full-lifecycle portfolio of assets
· The completion of the Bruce, Keith and Rhum asset transactions
· The installation of a bypass pipeline to address the historic waxing issues affecting Erskine production leading to a significant reserves upgrade from 3.1 mmboe net 2P reserves (at 1 January 2018) to 5.7 mmboe net 2P reserves (at 1 January 2019)
· The approval of the Columbus Field Development Plan (FDP) leading to the upgrade of 2C contingent resources to 6.2 mmboe of net 2P reserves
· The spud of the fully-carried Rowallan exploration well
Bruce, Keith and Rhum ("BKR")
In November 2017 Serica announced the BKR Acquisition under which Serica UK acquired a 36% interest in the Bruce field, a 34.83% interest in the Keith field and a 50% interest in the Rhum field and associated infrastructure. The deal had an effective date of 1 January 2018.
In August 2018, Serica announced the Total E&P Transaction under which Serica UK acquired a 42.25% interest in the Bruce field and a 25% interest in the Keith field and associated infrastructure. The Total E&P Transaction also had an effective date of 1 January 2018.
In November 2018, Serica announced the BHP Transaction under which Serica UK acquired a 16.0% interest in the Bruce field and a 31.83% interest in the Keith field and associated infrastructure. The BHP Transaction also had an effective date of 1 January 2018.
Later in November 2018, Serica announced the Marubeni Transaction under which Serica acquired a 3.75% interest in the Bruce field and the 8.33% interest in the Keith field and associated infrastructure. The Marubeni Transaction also had an effective date of 1 January 2018.
All four transactions were completed on 30 November 2018 meaning that Serica now has a 50% interest in the Rhum field, a 98% interest in the Bruce field and a 100% interest in the Keith field.
The bulk of the consideration for the transactions was deferred and contingent. Consequently, Serica did not have to raise equity. The combined initial consideration of US$22 million was exceeded by Serica's US$50 million share of the net post-tax cash flows between 1 January 2018 and completion which benefitted from higher than anticipated gas prices in 2018. In addition to these net proceeds of US$28 million received by Serica at completion, further proceeds in excess of US$5 million are expected to fall due to Serica once final completion statements have been agreed.
A completion condition of the sale and purchase agreement under which Serica acquired interests in the BKR fields from BP was replacing the Licence issued to BP by the U.S. government Office of Foreign Assets Control ("OFAC"). This Licence enabled certain U.S. companies and their owned or controlled non-U.S. affiliates to provide goods, services and support to Rhum field operations notwithstanding the 50% participation in the field by Iran Oil Company (U.K.) Limited ("IOC"), which was part of the National Iranian Oil Company group.
On 8 May 2018 the United States announced that it would withdraw from the Iran nuclear deal and re-impose the full range of U.S. primary and secondary sanctions against Iran. Thus, it became apparent that in order to continue Rhum field operations, it would be necessary to address the application of both U.S. primary and secondary sanctions to the field.
On 9 October 2018, Serica announced that a new conditional Licence had been issued by OFAC to BP (as the then operator and 50% owner of Rhum) and Serica (the proposed acquirer of BP's interest and operatorship in Rhum). The Licence allows specified U.S. entities and their owned or controlled non-U.S. affiliates to provide goods, services and support to Rhum operations. OFAC also provided an assurance that any other non-U.S. entities providing goods, services and support involving Rhum are not to be exposed to U.S. secondary sanctions provided that the Licence remains in force. The Licence was contingent upon certain arrangements being put in place in relation to IOC's participation in the Rhum field. This condition was satisfied by the implementation of these arrangements on 2 November 2018.
As was announced by Serica on 9 October 2018, the arrangements implemented in relation to IOC's participation in Rhum involve the following provisions. All benefits accruing from and relating to IOC's interest in the Rhum field are being held in escrow for such period as U.S. sanctions apply. This ensures that neither IOC nor any direct or indirect parent company of IOC will derive economic benefit from the Rhum field during that period. In addition, IOC exercises no decision-making powers in respect of Rhum during the same period. Such powers are being exercised by a management company that operates independently of IOC and Serica.
Since the full re-imposition of U.S. sanctions against Iran on 5 November 2018, BP until 30 November and Serica thereafter, have been able to procure the goods, services and support necessary to maintain Rhum field operations, thereby preserving production from a strategic UK natural resource. The existing Licence issued by OFAC expires on 31 October 2019. Serica will be applying for the renewal of the Licence during this year.
Production levels from the assets have been good. During the early part of 2018 there were production interruptions due to poor weather conditions and also due to a temporary shutdown of the Forties Pipeline System which is used to export liquids from BKR. 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. Performance was stronger in the second half of the year resulting in an average full-year net production in excess of 24,000 boe/day. During the year Ofgem approved the raising of the National Transmission System ("NTS") entry specification for CO2 content of gas delivered at the St Fergus Gas Terminal to 5.5%molCO2 thereby eliminating the need for costly blending gas previously required to offset the relatively higher CO2 content of Rhum gas.
An independent Competent Person's Report ("CPR") performed by Ryder Scott estimates net combined Bruce, Keith and Rhum 2P Reserves at 1 January 2019 to be 56.9 million boe.
BP had 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. This work was due to commence in May 2018 but BP decided to defer the work due to uncertainty caused by the announcement on 8 May 2018 by the US Government of its withdrawal from the Joint Comprehensive Plan of Action ("JCPOA") and the reintroduction of wider U.S. sanctions on Iran and certain transactions with Iranian entities.
Following the receipt of the OFAC Licence and completion of the BKR Acquisition, Serica has continued the planning for the R3 project and expects to start inspection work on the well this year. Final well planning is in progress and it is likely that the re-entry and re-completion will take place in early 2020. The well is already connected to the necessary infrastructure which will facilitate bringing the R3 well on stream quickly after the operations have been concluded.
Throughout 2018 Serica worked with BP and the relevant authorities to ensure a safe and seamless transition of operatorship. As part of the integration process 114 members of staff transferred across from BP to Serica on 30 November 2018 when the BKR acquisitions completed and Serica assumed operatorship of Bruce, Keith and Rhum. During the year Serica also recruited a further 23 staff members in order to ensure that the team would be fully resourced to handle all aspects of operatorship from day one.
Aberdeen premises were identified, secured and fitted out in order to provide a new high-tech Operational Headquarters for the Company. The centerpiece of this facility is a real-time video and communications link to the control room on the Bruce platform.
The key objectives of the transition process were that there should be no HSE incidents associated with the transition and that there should be no detrimental impact on production. It is to the immense credit of the entire workforce that both of these objectives were fully achieved.
Erskine
Production from the Erskine field was suspended on 16 January 2018 due to a wax build-up in the Lomond to CATS Riser Platform condensate export line. A section of this pipeline had been affected by wax-build up and this had led to reductions in Erskine production over a number of years. Historically the problem has been managed 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 Limited, after reviewing the various wax management measures employed in recent years, concluded that the best long-term solution would be to bypass the area of wax build-up by replacing a 26 km section of line, a proposal that Serica fully supported. The line was successfully replaced during the summer of 2018 and Erskine production was restarted at the end of October after the line had been recommissioned.
A regular pigging programme on the new line has been initiated from the start aimed at preventing the wax build-up that has previously proved so difficult to remove.
An independent CPR performed by Netherland Sewell and Associates has taken account of the increase in uptime associated with the bypass pipeline and estimates Net Erskine 2P Reserves of 5.7 million boe in place as at 31 December 2018. This is a significant increase on the 3.1 million boe reported at the end of the previous year.
Net production averaged in excess of 3,000 boe/day during the period from the restart of production until the end of 2018 giving a full year average net production of 650 boe/day. Production in the first three months of 2019 has continued to average in excess of 3,000 boe/day.
Columbus
In Q1 2018 Serica and its partners in the Columbus development concluded the evaluation of two potential offtake routes for Columbus production and selected the Shearwater hub as providing the optimum export route for Columbus gas and liquids. This scheme will utilize a new pipeline to be constructed by the owners of the nearby Arran field. This pipeline, connecting the Arran field to the Shearwater complex, operated by Shell UK, is planned to pass close to Columbus and provides a commercial route for field development.
A Field Development Plan ("FDP") was submitted for approval in June 2018. Peak production is expected to be 7,800 gross boe/day. The Development Area will be drained by a single well, which will be connected to the recently approved Arran-Shearwater pipeline, through which Columbus production will be exported along with Arran field production. When the production reaches the Shearwater platform facilities, it will be separated into gas and liquids and exported via pipelines to terminals onshore. Columbus development timing is dependent on the Arran-Shearwater pipeline being tied into the Shearwater platform in Q3 2020. Columbus start-up is targeted for mid-2021.
OGA approval of the FDP was granted in October 2018. This means that the 2C Contingent Resources previously assigned to Columbus have been upgraded to 2P Reserves. An independent CPR performed by Netherland Sewell and Associates estimates net Columbus 2P Reserves at 31 December 2018 to be 6.2 million boe.
Exploration
The ENI UK Limited ("ENI") operated Rowallan exploration well, 22/19c-7, spudded on 30 December 2018. Serica had a 15% fully carried interest in this well which was drilled to target the gas condensate Rowallan prospect, a significant structural fault and dip-closed trap in the east of Block 22/19c in the Central North Sea. The Ensco 121 heavy duty jack-up rig was used to drill the well.
On 4 April 2019 it was announced that well 22/19c-7, had reached a total depth of 4,641 metres and would be plugged and abandoned. The well encountered a 182 metre section of sandstone and shale, but was not found to be hydrocarbon bearing. The well was high pressure and high temperature and drilled using managed pressure drilling and continuous circulating technology. The well was drilled on time and on budget.
We will now assess the valuable data acquired before deciding the forward plan for the remaining prospects on block 22/19c and adjacent blocks. This result justifies our policy of reducing financial exposure to exploration risk by means of farm-out. In this case we were fully carried and did not pay anything towards the cost of the well.
Serica intends to continue targeting exploration opportunities where an attractive balance can be struck between financial commitment and risked commercial return and therefore participated in three applications for new licences in the UKCS 30th Offshore Licensing Round. All three applications were successful and Serica was awarded four new exploration licence areas
· Rowallan South - Blocks 22/24g (split) and 22/25f (split), Serica Energy (UK) Limited: 20% working interest, operator ENI UK. These blocks lie directly to the south of the Rowallan well, in which Serica holds a 15% interest. The blocks were offered on condition of making a 'drill or drop' decision to enter the next phase.
· Columbus West - Block 23/21b, Serica Energy (UK) Limited: 50% working interest, operator Summit Exploration and Production. The block lies immediately to the west of Serica's Columbus development. The proposed work programme contains further seismic reprocessing with a drill or drop decision.
· Skerryvore/Ruvaal - Blocks 30/12c (part), 30/13c (split), 30/17h, 30/18c and 30/19c (part), Serica Energy (UK) Limited: 20% working interest, operator Parkmead. The blocks lie in the Central North Sea and contain the Skerryvore and Ruvaal prospects 60km south of the Erskine field. The proposed work programme for the Skerryvore licence area includes acquiring and reprocessing 3D seismic data and a contingent well decision. There is a separate licence for the Ruvaal area on block 30/19c with a drill or drop decision.
Opportunities
Serica has established itself as one of the leading independent UKCS operating companies and has assembled a talented and motivated operating team. We intend to use these skills to continue to optimize the value of all of our assets. In particular we aim to extend the field life of the BKR assets by concentrating on enhancing recovery and reducing costs by eliminating unnecessary complexity.
Particular attention is being applied to the Bruce platform where we feel that our focused team can continue to improve the uptime of the facility. The fact that Serica has managed to complete the transactions with the all of the previous Bruce owners is a very important step forward because this will remove any potential partner misalignment issues that could have impacted our ability to extend field life, increase the utilisation of the facilities and maximise economic recovery from the area as a whole. The extensive infrastructure associated with the Bruce field offers significant capacity for third party tiebacks and Serica intends to fully investigate all opportunities to attract new business in this area.
The current corporate growth strategy is to identify and acquire assets where Serica can generate value in order to enhance shareholder returns. This started with the 2015 Erskine acquisition and continued with the 2018 BKR transactions and in each case Serica has demonstrated the ability to unlock value by solving commercial and/or political problems. Serica has now developed a sizable operating capability and will be able to use this to solve operational and/or subsurface problems. Serica is largely debt-free and benefits from the strong cash flow from ongoing operations (Erskine and BKR) which can be deployed for future projects.
Serica is not just a late-life production operator. We aim to expand the portfolio at all stages - exploration, appraisal, development and production. Our operating expertise is based around the Central and Northern North Sea and (coupled with tax synergies) this means that that the search for new opportunities is currently focused on the UKCS. Serica is committed to identifying opportunities based on value rather than volume and will continue to look for assets (preferably operated rather than non-operated) where Serica can add value when the current operator may be unable to do so.
Mitch Flegg
CEO
16 April 2019
REVIEW OF OPERATIONS
Production
Northern North Sea: Bruce Field - Blocks 9/8a, 9/9b and 9/9c, Serica 98%
Serica completed the acquisition of the Bruce field on 30 November 2018 and took over as operator from BP. Serica now operates the field and facilities consisting of three bridge-linked platforms, wells, pipelines and subsea infrastructure. The platforms contain living quarters for up to 168 people, reception, compression, power generation, processing and export facilities and a drilling platform that is currently mothballed. There is also the subsea Western Area Development (WAD) that produces from the edges of the Bruce area. Serica is now responsible for actively maintaining, monitoring, repairing and optimising all equipment, wells and pipelines.
The Bruce field is produced through a combination of platform wells and subsea wells tied back to the platform, with over 20 producing wells in total producing from multiple reservoirs and compartments. Bruce production is predominantly gas which is rich in NGL's. Gas is exported through the Frigg pipeline to the St Fergus terminal, where it is separated into sales gas and NGL's. Oil is exported through the Forties Pipeline System to Grangemouth.
The offshore team is supported onshore by the Serica technical headquarters in Aberdeen which has a live video link to the platform, streaming data and offering seamless communication with the offshore crew. Serica has established a highly skilled asset team consisting of the experienced and knowledgeable former BP staff and newly employed experts covering the full range of engineering and maintenance support. Serica has installed the necessary systems and measures to ensure continued safe and efficient operations.
Serica's 98% field interest and focus on the Bruce asset means that it can identify and implement changes that improve performance swiftly and efficiently. One of the first actions Serica as operator carried out was to change the route the helicopters took from Aberdeen to the platform. The flight path used by the previous operator was via Shetland, which included a change of aircraft and made the journey more prone to delays and cancellations. After a thorough HSE review and risk assessment, Serica changed this to one direct flight from Aberdeen to the platform, which has significantly reduced flight times and increased reliability, meaning people get home in a timely manner at the end of their rota.
Serica is striving to simplify processes to improve efficiency and reduce risk. A new asset integrity management software has been introduced which also delivers safety and risk management. This one system has replaced nine individual IT systems that were previously used. The result is a much more integrated tool that tracks and reports modifications, incidents and actions in one place, giving users the information they require and a live update of risk profiles. There is also a new maintenance management system which is linked to the materials, purchasing and storage system, again simplifying the process and reducing duplication and errors.
Bruce field production in 2018 averaged in excess of 12,000 boe/d of exported oil and gas net to Serica. Production reliability was 89% with a planned maintenance shut down period that coincided with a planned shut-down of the Forties Pipeline System. The latest independent estimate of reserves by Ryder Scott estimated 2P reserves of 21.9 million boe net to Serica as of 1 January 2019.
An annual maintenance shutdown was carried out in 2018 and was completed on time and on budget. During this time the flare system was overhauled to ensure safe and reliable operations going forward. Engine change outs were carried out on two of the compression systems. The engines were replaced with upgraded models of improved design to increase reliability. The oil line to the Forties Unity platform was investigated with an intelligent pig and found to be in excellent condition.
Three wells were brought back on production after repairs to the conductors (pipes connecting the wells from the seabed to the platform) adding to production rates. A further two conductor clamps were added to wells to prevent possible shut-ins. Further conductor work is planned for 2019.
Northern North Sea: Keith Field - Block 9/8a, Serica 100%
Keith is an oil field produced by one subsea well tied back to the Bruce facilities and requires very little maintenance. Keith produces at a relatively low rate but provides a low-cost contribution to the oil export from Bruce. Average Keith production in 2018 was around 800 boe/d. The latest independent estimate of reserves by Ryder Scott estimated 2P reserves of 656,000 boe net to Serica as of 1 January 2019.
Northern North Sea: Rhum Field - Blocks 3/29a, Serica 50%
The Rhum field is a gas condensate field producing from two subsea wells tied into the Bruce facilities through a 44km pipeline. Rhum production is separated into gas and oil and exported to St Fergus and Grangemouth along with Bruce and Keith production. Both wells are capable of producing at high rates, up to 100,000 mmscf/d each of gas in 2018. Rhum gas has a higher CO2 content than Bruce gas and so is blended with Bruce gas before leaving the offshore facilities. The field has produced at a relatively constant rate and has not shown significant decline. Average Rhum production in 2018 was around 12,000 boe/d net to Serica. The reservoir pressure is actively monitored via a third well (R3) that is not producing and so there is a good understanding of reservoir performance.
The R3 well requires intervention work before it can be brought on production. This was not carried out in 2018 due to concerns about secondary sanctions and their impact on contractors. The issue has now been resolved. Serica plans to carry-out investigative work on the well prior to finalising a well workover programme. Rhum production has not been materially constrained to-date by the delay in work on R3.
The latest independent estimate of reserves by Ryder Scott estimated 2P reserves of 34.5 million boe net to Serica as of 1 January 2019.
Central North Sea: Erskine Field - Blocks 23/26a (Area B) and 23/26b (Area B), Serica 18%
Serica holds a non-operated interest in Erskine, a gas and condensate field located in the UK Central North Sea. Serica's co-venturers are Chevron 50% (operator) and Chrysaor Holdings Limited 32%. Erskine fluids are processed and exported via the Lomond platform, which is 100% owned and operated by Chrysaor.
The Erskine field is produced through five production wells over the Erskine normally unmanned platform, transported to Lomond via a multiphase pipeline and processed on the Lomond platform. Then condensate is exported down the Forties Pipeline System via the CATS riser platform at Everest and gas is exported via the CATS pipeline to the CATS terminal at Teeside.
During 2018 a major project was carried out to significantly improve production export reliability for Erskine fluids. Over the last five years the export route for Erskine production has been severely impacted by wax build-up in the condensate export pipeline between Lomond and the CATS riser platform at Everest. The Erskine partnership supported the Lomond operator's proposal to lay a new section of pipeline to bypass the affected section of pipe. Soon afterwards, production was suspended due to a blocked condensate export line. In April after remedial measures to clear the blockage had not succeeded, the Lomond operator Chrysaor made the decision to cease clearance operations and concentrate on accelerating the bypass programme.
The pipeline bypass was completed at the end of September 2018 and production resumed in October 2018. All Erskine wells were brought back on production and production rates regularly exceeded 3,500 boe/day net to Serica. Erskine production for 2018 was only around 650 boe/d net to Serica due to the extended period of shut-in. A high frequency cleaning regime of the condensate export pipeline has been implemented in order to maintain the availability of the export route and improve overall export reliability.
An updated independent audit of the Erskine field confirmed Serica's share of estimated 2P reserves at 5.7 million boe as of 1 January 2019. This is a significant increase in reserves. It arises from a re-evaluation of well decline rates and facility uptime based upon the more stable rates achieved since the resumption of production which has led to an expected extension in economic field life.
Development
Central North Sea: Columbus Development - Blocks 23/16f and 23/21a, Serica 50%
The Columbus gas condensate development is located in close proximity to the Lomond field and has been designated as part of the Lomond Field Area. However, it has separate and independent development approval. Serica is Columbus field operator with partners Tailwind Mistral 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 development has been appraised with four wells and is to be developed with a single production well. Serica submitted a Field Development Plan ("FDP) to the OGA in June 2018 and was granted development and production consent in October 2018. Development work started as soon as FDP approval was received. First gas is targeted for 2021.
The Columbus development plan involves tying a single horizontal subsea well into the pipeline planned to be laid between Arran field (which received development approval at a similar time to Columbus) and the Shearwater platform, both operated by Shell. Arran and Columbus fluids will combine in the new pipeline and be produced together through the Shearwater processing facilities, making use of an existing riser which will be available from Q4 2020. Under agreements which have been entered into, the Columbus partners will pay for the tie-in and compensate the Arran owners for some re-routing of the pipeline but will not bear the capital cost of laying a new pipeline to Shearwater. Costs will be recovered by Arran by way of a tariff on production through the pipeline.
Now that the development is proceeding, Columbus resources have been re-classified as reserves. The latest reserves report written by independent reserves auditors Netherland & Sewell Associates Incorporated ("NSAI") ascribed to Serica net 2P reserves of 6.2 million boe within the Columbus development area as of 1 January 2019.
Exploration
Central North Sea: Rowallan Prospect - Block 22/19c, Serica 15%
Block 22/19c is located in the Central North Sea, around 20km west of Columbus. Well 22/19c-7 was spudded on 30 December 2018 by the Ensco 121 drilling rig. The well was targeting high pressure high temperature reservoirs and so managed pressure drilling and continuous circulating technology were used to drill the well.
22/19c-7 was drilled to target the Rowallan Prospect comprising potential condensate targets in the Triassic Skagerrak and the Middle Jurassic Pentland formations. Partners comprise ENI UK Limited (operator - 32%), JX Nippon Exploration and Production (U.K.) Limited (25%), Mitsui E&P UK Limited (20%) and Equinor (8%).
On 3 April 2019 the partnership made the decision to plug and abandon the well after drilling to a total depth of 4,641 metres. The well encountered 182 metres of high pressure high temperature sandstones and shales but did not contain hydrocarbons. The data acquired during the drilling operation will be used to review the remaining prospects on block 22/19c.
Serica was fully carried on all cost associated with this licence and so did not incur any costs in the planning and drilling of the Rowallan exploration well.
Licence Awards in the UK's 30th Offshore Licensing Round
The Company was awarded four licences on the UK Continental Shelf in the UK's 30th Offshore Licensing Round:
• Rowallan South P.2385 - Blocks 22/24g and 22/25f (Serica UK: 20% interest);
• Columbus West P.2388 - Block 23/21b (Serica UK: 50% interest);
• Skerryvore P.2400 - Blocks 30/12c, 30/13c, 30/17h and 30/18c, and Ruuval P.2402 - Block 30/19c (both Serica UK: 20% interest).
P.2358 was acquired as protection acreage in the event of a Rowallan discovery, as the prospect may have extended onto this block. The results of the 22/19c-7 well will be used to revise the interpretation of the prospectivity of this licence before making a drill or drop decision within two years.
Seismic reprocessing is being carried out on Columbus West to identify prospectivity. There is a drill or drop clause on this licence after two years.
The Skerryvore and Ruuval licences are operated by Parkmead. Seismic acquisition is planned to review the prospects in more detail and make a drill or drop decision within three years.
Ireland
Rockall Basin: Frontier Exploration Licences 1/09 and 4/13, Serica 100%
Serica is in talks with the Irish authorities over an acceptable work programme for extending the licences which were due to expire in November 2018 and January 2019. The 4/13 licence contains structural prospects Aghla Beg and Aghla More and the overlying stratigraphic prospect Derryveagh. Studies into the likely lithologies of the prospects showed signs of sedimentary geometries within the Aghla More prospect, but more fractured basement like features in Aghla Beg.
Serica estimates P50 prospective resources for these stacked prospects to be in the order of 4tcf of gas and 250 million barrels of condensate.
Licence 1/09 contains the Muckish prospect, which is a large, structural prospect, analogous to the Dooish discovery. Technical work carried out in 2018 investigated similarities of the geology to the prospects in 4/13 through seismic attribute analysis. The results were inconclusive on the geological characteristics of Muckish, due to seismic noise and volcanic interference, but it did highlight a Cretaceous fan system in the area.
An exploration well that can penetrate Derryveagh and Aghla More is the highest ranked opportunity and Serica is seeking a farm-in partner to join in drilling.
Slyne Basin: Frontier Exploration Licence 01/06, Serica 100%
Serica is in talks with the Irish authorities over an acceptable work programme for extending the licence which was due to expire in December 2018. The licence contains three prospects, Boyne, Achill and Liffey, with oil and gas potential in both the Jurassic and Triassic reservoirs. There is the Bandon oil discovery on block, which was encountered in the Jurassic sands. In the event of a gas discovery, the licence is ideally positioned for a tie-back to the Corrib subsea manifold.
Serica is seeking to identify a farm-in partner to drill an exploration well on the licence.
Namibia
Luderitz Basin: Blocks 2512A, 2513A, 2513B and 2612A (part), Serica 85%
Serica has extended the first renewal period of the licence to continue until the end of 2019. This licence period does not include a commitment to drill a well. The excellent 3D seismic data has identified giant carbonate prospects as well as large, more conventional Cretaceous fan prospects supported by seismic anomalies.
Serica has engaged specialist help to market the opportunity more widely. A technical review following recent drilling results offshore Namibia has uncovered the potential for a regional seal deposited during the Aptian geological time period. This could explain the absence of hydrocarbons in the recent wells drilled in nearby blocks. This would also benefit the Serica prospects as they are located deeper beneath the Aptian seal, which could form a trap and in prime location for source and migration. Serica hopes to attract a partner to join in drilling an exploration well.
Group Proved plus Probable Reserves - Unaudited
|
|
|
United Kingdom |
Total |
Total |
Total |
|
|
|
Oil |
Gas |
Oil |
Gas |
Oil & gas |
|
|
|
mmbbl |
bcf |
mmbbl |
bcf |
mmboe |
|
|
|
|
|
|
|
|
|
|
At 1 January 2017 |
2.1 |
10.4 |
2.1 |
10.4 |
3.8 |
|
|
|
|
|
|
|
|
|
|
Revisions |
(0.1) |
0.6 |
(0.1) |
0.6 |
- |
|
|
Production |
(0.4) |
(2.2) |
(0.4) |
(2.2) |
(0.7) |
|
|
|
|
|
|
|
|
|
|
At 31 December 2017 |
1.6 |
8.8 |
1.6 |
8.8 |
3.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions |
8.7 |
293.5 |
8.7 |
293.5 |
57.5 |
|
|
Re-classification |
2.6 |
21.4 |
2.6 |
21.4 |
6.2 |
|
|
Revisions |
1.6 |
8.2 |
1.6 |
8.2 |
3.0 |
|
|
Production |
(0.1) |
(5.1) |
(0.1) |
(5.1) |
(1.0) |
|
|
|
|
|
|
|
|
|
|
At 31 December 2018 |
14.4 |
326.8 |
14.4 |
326.8 |
68.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed |
9.3 |
212.0 |
9.3 |
212.0 |
44.6 |
|
|
Probable developed |
5.1 |
114.8 |
5.1 |
114.8 |
24.2 |
|
|
|
|
|
|
|
|
|
|
At 31 December 2018 |
14.4 |
326.8 |
14.4 |
326.8 |
68.8 |
|
|
|
|
|
|
|
|
|
Proved and Probable reserves are based on independent reports prepared by consultants Netherland, Sewell & Associates (Erskine and Columbus) and Ryder Scott (Bruce, Keith and Rhum) in accordance with the reserve definitions of the Canadian Oil and Gas Evaluation Handbook.
Gas reserves at 31 December 2017 and 2018 have been converted to barrels of oil equivalent using a factor of 6.0 bcf per mmboe for reporting and comparison purposes; actual calorific value of produced gas may result in a different conversion factor for individual fields.
The resources of the Columbus development in the UK North Sea were classified as Contingent Resources as at 31 December 2016 and 2017.
LICENCE HOLDINGS
The following table summarises the Group's licences as at 31 December 2018.
|
Licence |
Block(s) |
Description |
Role |
% |
Location |
|
UK |
|
|
|
|
|
|
P.090 |
9/9a BRUCE |
Bruce Field Production |
Operator |
99% |
Northern North Sea |
|
P.090 |
9/9a Rest of Block Excluding Bruce (REST) |
Development |
Operator |
98% |
Northern North Sea |
|
P.198 |
3/29a (ALL) |
Rhum Field Production |
Operator |
50% |
Northern North Sea |
|
P.209 |
9/8a BRUCE |
Bruce Field Production |
Operator |
98% |
Northern North Sea |
|
P.209 |
9/8a KEITH |
Keith Field Production |
Operator |
100% |
Northern North Sea |
|
P.209 |
9/8a Rest of Block Excluding Bruce and Keith (REST) |
Development |
Operator |
98% |
Northern North Sea |
|
P.276 |
9/9b BRUCE |
Bruce Field Production |
Operator |
98% |
Northern North Sea |
|
P.276 |
9/9c (ALL) |
Bruce Field Production |
Operator |
98% |
Northern North Sea |
|
P.276 |
9/9b Rest of Block Excluding Bruce Unit (REST) |
Development |
Operator |
98% |
Northern North Sea |
|
P.566 |
3/29b (ALL) |
Rhum Field non-unitised production |
Operator |
100% |
Northern North Sea |
|
P.975 |
3/24b (ALL) |
Rhum non-unitised production |
Operator |
100% |
Northern North Sea |
|
P.975 |
3/29d (ALL) |
Rhum non-unitised production |
Operator |
100% |
Northern North Sea |
|
P101 |
23/21a Columbus |
Columbus Development Area |
Operator |
50% |
Central North Sea |
|
P1314 |
23/16f |
Columbus Development Area |
Operator |
50% |
Central North Sea |
|
P57 |
23/26a |
Erskine Field - Production |
Non-operator |
18% |
Central North Sea |
|
P264 |
23/26b |
Erskine Field - Production |
Non-operator |
18% |
Central North Sea |
|
P1620 |
22/19c |
Exploration |
Non-operator |
15% |
Central North Sea |
|
P2385 |
22/24g, 22/25f |
Exploration |
Non-operator |
20% |
Central North Sea |
|
P2388 |
23/21b |
Exploration |
Non-operator |
50% |
Central North Sea |
|
P2400 |
30/12c, 30/13c, 30/17h, 30/18c |
Exploration |
Non-operator |
20% |
Central North Sea |
|
P2402 |
30/19c |
Exploration |
Non-operator |
20% |
Central North Sea |
|
Ireland |
|
|
|
|
|
|
1/06 |
27/4 (part), 27/5 (part), 27/9 (part) |
Exploration |
Operator |
100% |
Slyne Basin |
|
1/09 |
5/17 (part), 5/18, 5/22 (part), 5/23 (part), 5/27 (part), 5/28 (part) |
Exploration |
Operator |
100% |
Rockall Basin |
|
4/13 |
11/10, 11/15, 12/1 (part), 12/6, 12/11 (part) |
Exploration |
Operator |
100% |
Rockall Basin |
|
Namibia |
|
|
|
|
|
|
0047 |
2512A, 2513A, 2513B, 2612A (part) |
Exploration |
Operator |
85% |
Luderitz Basin |
FINANCIAL REVIEW
2018 RESULTS
Serica generated a profit for the year of US$74.7 million for 2018 compared to US$17.1 million for 2017. Comparison with the prior year is significantly influenced by two key factors; the shut-in of the Erskine field for most of 2018 to carry out a bypass of the condensate export pipeline; and, the impact of the BKR acquisitions completed on 30 November 2018.
In addition to Erskine operations and normal administrative and corporate costs, Serica's 2018 results include net income from the BKR fields from the completion date of 30 November 2018 plus a bargain purchase gain of US$52.9 million in respect of the acquisition partially offset by expensed BKR transaction and transition costs totalling US$14.4 million. Serica's share of net income from the BKR fields from the effective date of the BKR acquisitions, 1 January 2018, until 30 November is offset against the consideration paid rather than included within operating profit in the income statement. Details of the accounting for the BKR acquisitions are provided in note 26.
Sales revenues
Although the Erskine field, Serica's only producing interest pre-BKR, was shut in for more than nine months of 2018, the impact of one month of production from the BKR assets acquired was still sufficient, in conjunction with strong sales prices, to boost revenues by over 40% compared to 2017. Total product sales volumes for the year comprised approximately 47.1 million therms of gas, 96,000 lifted barrels of oil and 11,400 MT of NGLs. These generated 2018 product sales revenue of US$45.7 million consisting of BKR revenues of US$33.9 million and Erskine revenues of US$11.8 million (2017: US$32.0 million recorded net of a charge of US$1.2 million from movement in liquids overlift/underlift).
BKR revenues for the one month of production comprised gas sales of US$30.9 million at average realised prices of approximately 60.1 pence/therm and NGL sales of US$3.0 million at average realised prices of approximately US$303/MT. Oil sales are booked as revenue when barrels are lifted and title is transferred. As no liftings were recorded in December for Serica's net BKR interests, Serica's net oil allocation of 95,000 barrels from December BKR production increased its oil underlift position as at 31 December 2018 with the corresponding income statement credit classified within cost of sales.
Erskine revenues from approximately two and a half months of production in 2018 comprised gas sales of US$5.2 million (2017: US$12.5 million) at an average realised price of approximately 59.6p/therm (2017: 41.5p/therm), oil sales of US$6.2 million (2017: US$17.2 million) from 95,852 lifted barrels at an average realised price of US$65.2/bbl (2017: US$53.2/bbl) and NGL sales of US$0.4 million (2017: US$3.5 million) at average realised prices of $284/MT.
Gross profit
Gross profit for 2018 was US$25.2 million compared to US$19.3 million for 2017. Overall cost of sales of US$20.5 million compared to US$12.7 million for 2017. This comprised US$17.0 million of operating costs (2017- US$11.0 million) and US$7.8 million of non-cash depletion charges (2017 - US$1.7 million) offset by a US$4.3 million credit for the movement during the year from an opening liquids overlift position to a closing underlift position, (2017 - US$1.2 million debit included within sales revenues). Operating costs include costs of production, processing, transportation and insurance. Depletion charges are based upon the booked acquisition value for the BKR and Erskine transactions allocated on a unit of production basis for the relevant period. The prior year calculation was based upon Erskine costs and production alone. Operating costs of US$7.6 million (2017 - US$11.0 million) and depletion of US$0.4 million (2017 - US$1.7 million) related to the Erskine field whilst operating costs of US$9.4 million and depletion charges of US$7.4 million related to the BKR fields.
Operating profit before net finance revenue, tax and transaction costs
Operating profit for 2018 was US$9.1 million compared to US$14.1 million for 2017. This included BKR transition costs of US$11.7 million (2017 - nil) which comprise the set-up of operations systems and processes prior to taking on operatorship of the BKR assets, the transfer of operations contracts and documentation and the obtaining of necessary approvals from the Oil and Gas Authority. Administrative expenses of US$4.8 million, up from US$2.2 million for 2017, reflected the significant increase in personnel and activity following the signing of the BKR Acquisition agreement in late 2017. Other expense of US$2.1 million for 2018 increased from US$1.4 million for 2017 and principally comprised gas price hedging costs expensed during the respective years plus unrealised losses on hedging instruments still in place at year-end. These costs were offset by a net credit of US$3.1 million comprising a reversal of US$12.5 million of impairment charges previously made against the Columbus development now that development is underway, net of US$9.4 million of write-offs related to the Group's Irish licences for which the Group has no significant ongoing expenditure plans. This compares to write-offs of US$1.6 million in 2017 related to the relinquishment of UK licence P1482 and other minor exploration expenditures.
Pre-licence costs, foreign exchange gains and share-based payment provisions generated 2018 net charges of US$0.6 million compared to a net gain of US$0.1 million in 2017. A reduction in exchange gains reflected general GB£/US$ currency movements whilst an increase in share-based payments largely arose from awards made late in 2017 upon signature of the BKR deal with BP.
Profit before taxation and profit for the year
Profit before taxation was US$59.2 million (2017 - US$10.8 million) after taking into account a bargain purchase gain of US$52.9 million (2017 - nil), BKR transaction costs of US$2.7 million (2017 - US$3.4 million) and net finance charges of US$0.1 million (2017 - US$0.1 million credit).
The bargain purchase gain represents the difference between provisional fair valuations of assets acquired and consideration paid or potentially payable calculated in accordance with applicable accounting standards. Such calculations are complex and involve a range of projections and assumptions related to future costs, production volumes, sales prices, discount rates and tax. The calculations for the BKR acquisitions are further complicated by the structuring of most of the consideration as either contingent upon future asset performance or deferred. The accounting for the acquisition of the transaction assets has only been provisionally determined at this stage, as the accounting standards provide for potential further adjustments to fair value assessments up to twelve months after completion of the acquisitions.
The BKR transaction costs comprise work on documentation related to the re-admission of Serica to AIM upon completion of the acquisitions and other fees associated with the acquisitions. Prior year costs comprised work on the structuring and negotiation of the acquisitions and preparation of the original AIM admission document.
Finance revenue and costs represent interest earned on cash deposits less interest payable mainly on the prepayment facility drawings.
The net deferred tax credit of US$15.5 million largely reflects the accelerated recognition of the Group's historic UK ring fenced tax losses based upon the significant increase in projected income arising from completion of the BKR acquisitions. The prior year credit of US$6.3 million represented a partial release based solely upon utilisation of losses against near-term Erskine production.
Overall, this generated a profit for the year of US$74.7 million increased from US$17.1 million for 2017.
BALANCE SHEET
The balance sheet at 31 December 2018 incorporates a series of adjustments related to the BKR acquisitions. These include accounting for the acquisitions themselves and also significant increases to current and non-current assets and liabilities reflecting higher overall levels of business activity. In addition, receipt of Columbus FDP approval in October 2018 has led to a reclassification of costs from exploration and evaluation to property, plant and equipment.
The reduction of exploration and evaluation assets from US$53.4 million in 2017 to US$4.1 million in 2018 principally reflects the reversal of a Columbus asset impairment provision followed by the reclassification of total pre-development costs to-date to property, plant and equipment. The Columbus impairment provision of US$12.6 million made in prior periods was reversed in 2018 following the receipt of development approval and other operational developments in the year. Development approval also means that total Columbus costs of US$54.3 million were reclassified to property, plant and equipment. In addition, costs of US$1.9 million were incurred during 2018 on general exploration activities whilst US$9.4 million relating to the Group's Irish licences was written off as the Group has no plans to commit further significant expenditures on these licences.
Property, plant and equipment increased from US$7.6 million to US$475.9 million during 2018. In addition to the reclassification of US$54.3 million of Columbus costs from exploration and evaluation assets, the increase includes a fair value attributed to the BKR assets calculated as US$416.5 million. The BKR transactions are classified as business combinations and calculations of fair value are carried out in accordance with applicable accounting standards. As described above, such valuations involve a series of judgements and assumptions on all key components of the calculations and are provisional until twelve months following acquisition. The structuring of the BKR acquisitions, with most of the consideration being either contingent upon future asset performance or deferred, creates an ongoing link between the value generated from the assets acquired and consideration ultimately paid.
An inventories balance of US$7.1 million at 31 December 2018 (2017 - US$0.5 million) includes materials and spare parts transferred with the BKR assets. Trade and other receivables increased from US$2.3 million in 2017 to US$66.4 million in 2018 with the new balance including trade receivables of US$39.4 million (2017 - US$1.2 million), other BKR receivables of US$7.8 million (2017 - US$nil), US$7.5 million of recoverables from JV partners (2017 - US$0.1 million) and US$8.6 million of liquids underlifted at year end (2017 - nil). The increase in trade receivables, which mainly comprise sales revenues due, reflected the general increase in Group production and sales levels. Other receivables comprise sunk costs recoverable through joint venture arrangements and BKR consideration outstanding after final calculations of net cash flow due to Serica arising during the pre-completion period. Liquids underlifted comprise volumes of oil and NGLs awaiting lifting by product buyers at year end.
The derivative financial asset of US$2.7 million in 2017 represented the fair value of gas price put options covering the period from 1 January 2018 to 30 June 2020. After taking account of the expiry of 2018 puts and revaluation of remaining puts at end 2018 pricing, the book value has been reduced to US$0.2 million. The year-end cash and cash equivalent balances plus term deposits totalled US$54.9 million (2017 - US$34.0 million).
The increase in current trade and other payables to US$49.2 million at 31 December 2018 from US$7.8 million in 2017 represents significant accruals and creditors following completion of the BKR acquisitions. It also includes Erskine operating expenditures due and remaining pipeline bypass costs at the end of 2018. Current provisions of US$2.4 million (2017 - US$2.2 million) represent certain contingent liabilities related to savings in field operating costs that may fall due under the Erskine acquisition agreement.
Financial liabilities of US$115.0 million (2017 - nil) within current liabilities and US$209.5 million (2017 - US$3.8 million) within non-current liabilities comprise amounts projected to be paid under the BKR agreements. The current element comprises US$20.2 million (2017 - US$3.8 million in non-current financial liabilities) of total drawings under the prepayment facility with BP plus amounts of US$94.8 million estimated to fall due under the net cash flow sharing arrangements over the course of 2019. Amounts identified as currently due under both the prepayment facility and the net cash flow sharing arrangements, are directly related to production volumes and sales prices actually achieved over the year. The non-current element comprises further contingent and deferred amounts the bulk of which are also directly related to future asset volume and price performance.
Non-current financial liabilities of US$3.8 million in 2017 represented drawings under the gas prepayment facility with BP to cover gas price puts which increased to US$20.2 million in 2018 following further drawings under the facility of GB£12.8 million at BKR completion and are now recognised as current liabilities.
Non-current provisions of US$28.8 million have been made in respect of decommissioning liabilities for the Bruce and Keith interests acquired from Marubeni. These were not subject to the same contingent and deferred consideration arrangements as those field interests acquired from BP, Total E&P and BHP respectively under which decommissioning liabilities were retained by the vendors with Serica liable to pay deferred consideration equivalent to 30% of the actual costs of decommissioning net of tax recovered by them. No provision is included for decommissioning liabilities related to Erskine as these are retained by BP up to a cap which is not projected to be exceeded.
Overall net assets have increased from US$102.3 million in 2017 to US$177.8 million in 2018.
The increase in share capital from US$229.3 million to US$229.6 million arose from shares issued following the exercise of share options whilst the increase in other reserve from US$20.8 million to US$21.3 million arose from share-based payments.
CASH BALANCES AND FUTURE COMMITMENTS
Current cash position and price hedging
At 31 December 2018 the Group held cash and cash equivalents of US$53.6 million (2017 - US$28.3 million) plus term deposits of US$1.3 million (2017 - US$5.7 million). The main element of the net increase arose upon BKR completion when Serica received US$50.0 million of net revenues and working capital adjustments less US$21.6 million of upfront consideration and also drew GB£12.8 million (US$16.3 million) under a gas prepayment facility with BP. Serica also settled the outstanding US$2.8 million tranche of Erskine consideration on 29 June 2018.
Other significant cash movements during the year included BKR transition and transaction costs of US$17.1 million (2017 - US$1.9 million), US$1.8 million of exploration asset expenditure (2017 - US$1.9 million) and US$5.2 million of Erskine capital costs (2017 - US$0.1 million). Serica's share of BKR post-tax income for the eleven months prior to completion is included within the cash inflow from business combinations. Net cash income from the BKR assets for the remaining month post completion was received after year-end and consequently is not included in the closing cash balances.
At 31 December 2018 Serica held gas price puts covering volumes of 240,000 therms per day for 2019 and 160,000 therms per day for 1H 2020 all at a floor price of 35 p/therm with no upside price restrictions.
Field and other capital commitments
Following completion of the condensate export line bypass there are no further capital commitments on the Erskine producing field and net production revenues are expected to cover all ongoing field expenditures.
There are no significant current capital commitments on the BKR producing fields though plans to carry out work on the Rhum R3 well are in hand with work expected to be carried out in early 2020. Net revenues from Serica's share of income from the fields, after net cashflow sharing payments, is expected to cover Serica's retained share of ongoing field expenditures and contingent or deferred consideration due under the respective acquisition agreements. These include GB£16 million due to BP upon a successful outcome from the Rhum R3 workover and amounts of up to GB£7.7 million also due to BP in respect of each of 2019, 2020 and 2021 dependent upon achievement of certain Rhum field production and gas price levels., In addition, amounts of US$5 million are due to Total E&P on each of 31 July 2019, 31 March 2020 and 30 November 2020. Further deferred contingent consideration amounts will fall due to each of BP, Total E&P and BHP representing 30% of their respective shares of the actual costs of decommissioning the BKR field facilities in existence on 30 November 2018 at completion, net of tax relief.
OTHER
Asset values and impairment
At 31 December 2018, Serica's market capitalisation stood at US$423.1 million based upon a share price of 125.5 pence which exceeded the net asset value of US$177.8 million. By 15 April the Company's market capitalisation was US$409.5 million. Management has carried out a thorough review of the carrying value of the Group's assets and determined that no significant write-downs are required.
BKR asset acquisitions
On 30 November 2018 Serica completed the four BKR acquisitions. These comprised:
· 36% in Bruce, 34.83333% in Keith and 50% in Rhum plus operatorship of each field from BP Exploration Operating Company Limited ("BP"). Initial consideration, paid at completion, was GB£12.8 million with contingent payments of GB£16 million due in relation to the outcome of future work on the Rhum R3 well and up to a total GB£23.1 million, split equally over the years 2019, 2020 and 2021, due in relation to Rhum field performance and sales prices in respect of the three years. In addition, Serica will pay contingent consideration related to net cash flows from the assets acquired from BP as set out below. As part of the gas sales arrangements, BP Gas Marketing Limited provided a gas prepayment facility of up to GB£16 million that was fully drawn to cover the cost of gas price puts and the initial consideration. Amounts due to BP are secured over the interests in the assets acquired from them.
· 42.25% in Bruce and 25% in Keith from Total E&P UK Limited ("Total E&P"). Initial consideration was US$5 million with three further instalments of deferred consideration of US$5 million each, due on 31 July 2019, 31 March 2020 and 30 November 2020. In addition, Serica will pay contingent consideration related to net cash flows from the assets acquired from Total E&P as set out below.
· 16% in Bruce and 31.83333% in Keith from BHP Billiton Petroleum Great Britain Limited ("BHP"). Initial consideration was GB£1 million. In addition, Serica will pay contingent consideration related to net cash flows from the assets acquired from BHP as set out below.
· 3.75% in Bruce and 8.33334% in Keith from Marubeni Oil and Gas (UK) Limited ("Marubeni"). Initial consideration was US$1 million payable to Serica with no contingent or deferred consideration.
In addition, Serica will pay contingent cash consideration to BP, Total E&P and BHP calculated as a percentage (60% in 2018, 50% in 2019 and 40% in each of 2020 and 2021) of net cash flows resulting from the respective field interests acquired. Amounts arising up to completion were adjusted for notional tax at prevailing rates and offset against initial consideration. Amounts arising after completion will be paid by Serica pre-tax with such amounts to be offset by Serica against its own tax liabilities.
Each of BP, Total E&P and BHP will retain liability, in respect of the field interests Serica acquired from each of them, for all the costs of decommissioning those facilities that existed at the date of completion. Serica will pay deferred contingent consideration equal to 30% of actual future decommissioning costs, reduced by the tax relief that each of BP, Total E&P and BHP receives on such costs.
In the case of the Marubeni Transaction, Serica took on responsibility for decommissioning liabilities for these interests but without any contingent or deferred cash consideration.
Net cash flow sharing with BP, Total E&P and BHP is being settled on a monthly basis starting in January 2019 and no other contingent or deferred consideration payments have yet fallen due.
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, to carry insurance, where both available and cost effective, and to retain adequate working capital.
Prior to the BKR acquisitions, Serica carried significant exposure to a single production stream and held limited cash resources. The main response was to look for additional revenue streams whilst, in the meantime, working with the operators of the Erskine field and Lomond offtake facilities to identify production risks and mitigate where possible. In parallel, the Company minimised non-core expenditures and utilised oil and gas hedging instruments, setting price floors to protect cash flow margins from severe price falls.
In addition to the diversification of revenue streams delivered by the four BKR acquisitions and associated cash receipts upon completion, the continuing net cash flows from its greatly increased production levels are enabling Serica to build a strong working capital reserve. This is available to respond to a range of risks including production interruptions, severe commodity price falls and unexpected costs. To supplement this the Company carries business interruption insurance to meet estimated field operating costs over sustained periods of production shut-in, where caused by events covered under such policies. The Company will also seek cost effective opportunities to add to its existing 35 pence per therm gas price puts which currently cover an estimated 37% of the Company's retained share of projected 2019 gas production.
The principal risks currently recognised and the mitigating actions taken by the management are as follows:
|
Investment Returns: Management seeks to invest in a portfolio of exploration, development and producing acreage delivering returns to shareholders through acquisitions of producing assets to which it can add further value and through the discovery and exploitation of commercial reserves. Delivery of this business model carries a number of key risks. |
|
|
Risk |
Mitigation |
|
Market support may be eroded lowering investor support and obstructing fundraising |
· Management regularly communicates its strategy to shareholders · Focus is placed on building a diverse and resilient asset portfolio capable of offering prospectivity throughout the business cycle |
|
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, to identify the associated risks objectively and mitigate where practical |
|
Operations: Operations may not go according to plan leading to damage, pollution, cost overruns or poor outcomes. |
|
|
Production may be interrupted generating significant revenue loss whilst costs continue to be incurred |
· Business interruption cover is carried when cost effective · The Company seeks to diversify its sources of income |
|
Equipment may fail and wells may experience a loss of control causing delays and/or environmental damage |
· The Group retains fully trained and experienced personnel and contractors · The planning process involves risk identification and establishment of mitigation measures · Equipment is subject to regular inspection and monitoring · Appropriate insurances are retained |
|
Third party offtake routes may experience restrictions or interruptions and full availability may depend upon sustained production from other fields in the system |
· The Group aims to diversify its exposure to offtake routes where possible though all of its oil production currently uses the FPS system · The Group carries business interruption cover |
|
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 conduct its operations and execute successful investment strategies |
|
|
Risks |
Mitigation |
|
Key personnel may be lost to other companies |
· The Remuneration Committee regularly evaluates incentivisation schemes to ensure they remain 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 |
|
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 |
|
Political and commercial environment: World share and commodity markets and political environments continue to be volatile |
|
|
Risk |
Mitigation |
|
Sanctions imposed by the U.S. government may threaten continuing production from the Rhum field |
· An OFAC Licence has been obtained which has enabled continuing production from Rhum |
|
The OFAC Licence must be renewed annually |
· Serica intends to initiate the renewal process well in advance of the specified date |
|
Volatile commodity prices mean that the Group cannot be certain of the future sales value of its products |
· Planning and forecasting considers downside price scenarios · Oil and gas floor price hedging may be utilised where deemed cost effective · Price mitigation strategies may be employed at the point of major capital commitment |
|
Funding to support investment and field development programmes may not be available at reasonable cost |
· Serica seeks to apply a flexible approach to funding and maintain a range of financing options |
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, the development of production facilities and delivery of hydrocarbons. 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
|
|
16 April 2019
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
|
|
|
|
|
|
|
|
2018 |
2017 |
|
|
Note |
US$000 |
US$000 |
|
Continuing operations |
|
|
|
|
Sales revenue |
4 |
45,747 |
31,966 |
|
|
|
|
|
|
Cost of sales
|
5 |
(20,543) |
(12,668) |
|
|
|
|
|
|
Gross profit |
|
25,204 |
19,298 |
|
|
|
|
|
|
Other expense |
|
(2,120) |
(1,426) |
|
Pre-licence costs |
|
(283) |
(303) |
|
Impairment and write-offs of E&E assets |
14 |
3,121 |
(1,612) |
|
Administrative expenses |
|
(4,802) |
(2,244) |
|
Foreign exchange gain |
|
150 |
511 |
|
Share-based payments |
27 |
(483) |
(98) |
|
BKR transition costs |
26 |
(11,690) |
- |
|
|
|
|
|
|
Operating profit before net finance revenue, tax |
9,097 |
14,126 |
|
|
and transaction costs |
|
|
|
|
|
|
|
|
|
Bargain purchase gain on BKR acquisitions |
26 |
52,938 |
- |
|
BKR transaction costs |
26 |
(2,720) |
(3,386) |
|
Finance revenue |
10 |
271 |
246 |
|
Finance costs |
11 |
(373) |
(138) |
|
|
|
|
|
|
Profit before taxation |
|
59,213 |
10,848 |
|
|
|
|
|
|
Taxation credit for the year |
12a) |
15,504 |
6,255 |
|
|
|
|
|
|
Profit for the year |
|
74,717 |
17,103 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per ordinary share - EPS |
|
|
|
|
Basic EPS on profit for the year (US$) |
13 |
0.28 |
0.06 |
|
Diluted EPS on profit for the year (US$) |
13 |
0.27 |
0.06 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
2018 |
2017 |
2018 |
2017 |
|
|
Note |
US$000 |
US$000 |
US$000 |
US$000 |
|
Non-current assets |
|
|
|
|
|
|
Exploration & evaluation assets |
14 |
4,054 |
53,413 |
- |
- |
|
Property, plant and equipment |
15 |
475,896 |
7,640 |
- |
- |
|
Investments in subsidiaries |
16 |
- |
- |
134,034 |
1,350 |
|
Deferred tax asset |
12d) |
- |
16,209 |
|
- |
|
|
|
479,950 |
77,262 |
134,034 |
1,350 |
|
Current assets |
|
|
|
|
|
|
Inventories |
17 |
7,071 |
453 |
- |
- |
|
Trade and other receivables |
18 |
66,376 |
2,274 |
109,811 |
83,269 |
|
Derivative financial asset |
19 |
176 |
2,670 |
- |
- |
|
Term deposits |
20 |
1,273 |
5,698 |
1,273 |
1,350 |
|
Cash and cash equivalents |
20 |
53,614 |
28,279 |
25,099 |
18,712 |
|
|
|
128,510 |
39,374 |
136,183 |
103,331 |
|
|
|
|
|
|
|
|
TOTAL ASSETS |
|
608,460 |
116,636 |
270,217 |
104,681 |
|
|
|
|
|
|
|
|
Current liabilities |
|
|
|
|
|
|
Trade and other payables |
21 |
(49,174) |
(7,825) |
(4,099) |
(2,385) |
|
Financial liabilities |
22 |
(114,997) |
- |
- |
- |
|
Provisions |
23 |
(2,353) |
(2,234) |
- |
- |
|
Non-current liabilities |
|
|
|
|
|
|
Financial liabilities |
22 |
(209,459)) |
(3,825) |
- |
- |
|
Provisions |
23 |
(28,839) |
(456) |
- |
- |
|
Deferred tax liability |
12d) |
(25,864) |
- |
- |
- |
|
TOTAL LIABILITIES |
|
(430,686) |
(14,340) |
(4,099) |
(2,385) |
|
|
|
|
|
|
|
|
NET ASSETS |
|
177,774 |
102,296 |
266,118 |
102,296 |
|
|
|
|
|
|
|
|
Share capital |
25 |
229,586 |
229,308 |
194,314 |
194,036 |
|
Merger reserve |
16 |
- |
- |
112,174 |
- |
|
Other reserve |
|
21,296 |
20,813 |
21,296 |
20,813 |
|
Accumulated deficit |
|
(73,108) |
(147,825) |
(61,666) |
(112,553) |
|
|
|
|
|
|
|
|
TOTAL EQUITY |
|
177,774 |
102,296 |
266,118 |
102,296 |
|
|
|
|
|
|
|
The profit for the Company was US$163,061,000 for the year ended 31 December 2018 (2017: profit of US$17,103,000). 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 16 April 2019
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 2017 |
|
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 |
28 |
- |
98 |
- |
98 |
|
|
|
|
|
|
|
|
At 31 December 2017 |
|
229,308 |
20,813 |
(147,825) |
102,296 |
|
|
|
|
|
|
|
|
Profit for the year |
|
- |
- |
74,717 |
74,717 |
|
Total comprehensive income |
|
- |
- |
74,717 |
74,717 |
|
Share-based payments |
28 |
- |
483 |
- |
483 |
|
Issue of share capital |
25 |
278 |
- |
- |
278 |
|
|
|
|
|
|
|
|
At 31 December 2018 |
|
229,586 |
21,296 |
(73,108) |
177,774 |
|
|
|
|
|
|
|
|
Company |
Share capital |
Merger reserve |
Other reserve |
Accum'd deficit |
Total |
|
|
US$000 |
US$000 |
US$000 |
US$000 |
US$000 |
|
|
|
|
|
|
|
|
At 1 January 2017 |
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 (note 28) |
- |
- |
98 |
- |
98 |
|
|
|
|
|
|
|
|
At 31 December 2017 |
194,036 |
- |
20,813 |
(112,553) |
102,296 |
|
|
|
|
|
|
|
|
Profit for the year |
- |
- |
- |
163,061 |
163,061 |
|
Total comprehensive income |
- |
- |
- |
163,061 |
163,061 |
|
Share-based payments (note 28) |
- |
- |
483 |
- |
483 |
|
Issue of share capital (note 25) |
278 |
- |
- |
- |
278 |
|
Transfers |
- |
112,174 |
- |
(112,174) |
- |
|
|
|
|
|
|
|
|
At 31 December 2018 |
194,314 |
112,174 |
21,296 |
(61,666) |
266,118 |
|
|
|
|
|
|
|
Serica Energy plc
Cash Flow Statement
For the year ended 31 December
|
Note |
Group 2018 US$000 |
2017 US$000 |
Company 2018 US$000 |
2017 US$000 |
|
|
Operating activities: |
|
|
*restated |
|
*restated |
|
Profit for the year |
|
74,717 |
17,103 |
163,061 |
17,103 |
|
Adjustments to reconcile profit for the year |
|
|
|
|
|
|
to net cash flow from operating activities: |
|
|
|
|
|
|
Taxation credit |
|
(15,504) |
(6,255) |
- |
- |
|
BKR transition and transaction costs |
|
14,410 |
3,386 |
- |
- |
|
Bargain purchase gain on BKR acquisitions |
|
(52,938) |
- |
- |
- |
|
Net finance costs/(income) |
|
102 |
(108) |
(271) |
(246) |
|
Depreciation and depletion |
|
7,803 |
1,710 |
- |
- |
|
Oil and NGL over/underlift |
|
(4,306) |
1,163 |
- |
- |
|
Impairment and write-offs of E&E assets |
|
(3,121) |
1,612 |
- |
- |
|
Unrealised and realised hedging losses |
|
2,494 |
1,133 |
- |
- |
|
Write-back of loans and investments |
|
- |
- |
(164,961) |
(17,909) |
|
Share-based payments |
|
483 |
98 |
483 |
98 |
|
Other non-cash movements |
|
(150) |
(406) |
105 |
(302) |
|
Cash outflow on BKR transition/transaction |
|
(17,083) |
(1,867) |
- |
- |
|
Increase in financial assets |
|
- |
(3,803) |
- |
- |
|
(Increase)/decrease in trade and other |
|
(46,477) |
4,110 |
(862) |
(671) |
|
receivables |
|
|
|
|
|
|
Decrease/(increase) in inventories |
|
35 |
(52) |
- |
- |
|
Increase/(decrease) in trade and other |
|
25,784 |
(291) |
1,683 |
1,905 |
|
payables |
|
|
|
|
|
|
Net cash (out)/inflow from operations |
|
(13,751) |
17,533 |
(762) |
(22) |
|
|
|
|
|
|
|
|
Investing activities: |
|
|
|
|
|
|
Interest received |
|
271 |
246 |
271 |
246 |
|
Purchase of E&E assets |
|
(1,803) |
(1,855) |
- |
- |
|
Purchase of property, plant and equipment |
|
(5,570) |
(72) |
- |
- |
|
Cash inflow from business combination |
26 |
28,384 |
- |
- |
- |
|
Cash outflow arising on asset acquisitions |
21 |
(2,775) |
(2,775) |
- |
- |
|
Changes in term deposits |
|
4,425 |
(5,698) |
77 |
(1,350) |
|
Receipts from Group subsidiaries |
|
- |
- |
6,584 |
5,358 |
|
Net cash flow from investing activities |
|
22,932 |
(10,154) |
6,932 |
4,254 |
|
Financing activities: |
|
|
|
|
|
|
Proceeds from borrowings |
22 |
16,338 |
3,803 |
- |
- |
|
Proceeds from issue of shares |
25 |
278 |
- |
278 |
- |
|
Finance costs paid |
|
(258) |
(135) |
- |
- |
|
Net cash flow from financing activities |
|
16,358 |
3,668 |
278 |
- |
|
|
|
|
|
|
|
|
Net increase/(decrease) in cash and cash equivalents |
26 |
25,539 |
11,047 |
6,448 |
4,232 |
|
Effect of exchange rates on cash and cash |
|
|
|
|
|
|
equivalents |
26 |
(204) |
639 |
(61) |
414 |
|
Cash and cash equivalents at 1 January |
26 |
28,279 |
16,593 |
18,712 |
14,066 |
|
Cash and cash equivalents at 31 December |
26 |
53,614 |
28,279 |
25,099 |
18,712 |
* changes in term deposits have been reclassified from financing to investing activities
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 2018 were authorised for issue by the Board of Directors on 16 April 2019 and the balance sheets were signed on the Board's behalf by Antony Craven Walker and Mitch Flegg. Serica Energy plc is a public limited company incorporated and domiciled in England & Wales with its registered office at 48 George Street, London, W1U 7DY. The principal activity of the Company and the Group is to identify, acquire and subsequently exploit oil and gas reserves. Its current activities are located in the United Kingdom, 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 2018. 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 2018 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$163,061,000 (2017: profit US$17,103,000).
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 2018.
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 2018 the Company held cash and term deposits of US$54.9 million which had increased to approximately US$92 million by the end of March 2019. The bulk of contingent and deferred consideration due under the BKR acquisition agreements is related to future successful field performance and consequently will be either reduced or deferred in the event of production interruptions or lower net cash generation.
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: determining the fair value of property, plant and equipment on a business combination, determining the fair value of contingent consideration, decommissioning provisions, 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.
Determining the fair value of property, plant and equipment on business combination
The Group determines the fair value of oil and gas assets acquired in a business combination based on the discounted cash flows at the time of acquisition based on management's assessment of proven and probable reserves reflecting risks applicable to the assets acquired. The estimated future cash flows attributable to the asset are discounted to their present value using a discount rate that reflects the market assessments of the time value of money and the risks specific to the asset at the time of acquisition. In calculating the asset fair value, the Group will apply oil and gas price assumptions representing management's view of the medium and long-term pricing (see note 26).
Determining the fair value of contingent consideration on BKR acquisitions
The Group determines the fair value of contingent consideration payable based on discounted cash flows at the time of the acquisition calculated for each separate component of the contingent consideration. The same models and assumptions are used in the calculation of the fair value of property, plant and equipment arising on the business combination. Any cash flows specific to the contingent consideration also reflect applicable commercial terms and risks (see note 22).
Decommissioning provision
Amounts used in recording a provision for decommissioning are estimates based on current legal and constructive requirements and current technology and price levels for the removal of facilities and plugging and abandoning of wells. Due to changes in relation to these items, the future actual cash outflows in relation to decommissioning are likely to differ in practice. To reflect the effects due to changes in legislation, requirements and technology and price levels, the carrying amounts of decommissioning provisions are reviewed on a regular basis. The effects of changes in estimates do not give rise to prior year adjustments and are dealt with prospectively. While the Group uses its best estimates and judgement, actual results could differ from these estimates (see note 23).
Assessment of commercial 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. In estimating the fair values associated with the BKR business combination, including the contingent consideration payable, and the depletion charge for 2018, management has applied its own assessment of proven and probable reserves reflecting risks applicable to the assets required.
Assessment of the recoverable amount of intangible and tangible assets
The Group monitors internal and external indicators of impairment relating to its intangible and tangible assets, which may indicate that the carrying value of the assets may not be recoverable. The assessment of the existence of indicators of impairment in E&E assets involves judgement, which includes whether licence performance obligations can be met within the required regulatory timeframe, whether management expects to fund significant further expenditure in respect of a licence, and whether the recoverable amount may not cover the carrying value of the assets. For development and production assets judgement is involved when determining whether there have been any significant changes in the Group's oil and gas reserves.
The Group determines whether E&E assets are impaired at an asset level and in regional cash generating units ('CGUs') when facts and circumstances suggest that the carrying amount of a regional CGU may exceed its recoverable amount. As recoverable amounts are determined based upon risked potential, or where relevant, discovered oil and gas reserves, this involves estimations and the selection of a suitable pre-tax discount rate relevant to the asset in question. The calculation of the recoverable amount of oil and gas development and production properties involves estimating the net present value of cash flows expected to be generated from the asset in question. Future cash flows are based on assumptions on matters such as estimated 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 2018 from 2017 is the acquisition of the further producing oil and gas assets in November 2018 which have generated a significant increase in management's estimate of future cash flows and taxable income expected to be sheltered by available tax losses. To the extent that actual events differ significantly from estimates, the ability of the Group to realise deferred tax assets could be impacted.
Basis of Consolidation
The consolidated financial statements include the accounts of Serica Energy plc (the "Company") and its wholly owned subsidiaries Serica Holdings UK Limited, Serica Energy Holdings B.V., Serica Energy (UK) Limited, Serica Glagah Kambuna B.V., Serica Sidi Moussa B.V., Serica Energy Slyne B.V., Serica Energy Rockall B.V., Serica Energy Namibia B.V., Serica Energy Corporation, Asia Petroleum Development Limited, Petroleum Development Associates (Asia) Limited and Petroleum Development Associates (Lematang) Limited. Together these comprise the "Group".
All inter-company balances and transactions have been eliminated upon consolidation.
Foreign Currency Translation
The functional and presentational currency of Serica Energy plc and 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.
When the Group acquires a business, it assesses the financial assets and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. Any contingent consideration to be transferred to the acquirer will be recognized at fair value at the acquisition date. Contingent consideration classified as an asset or liability that is a financial instrument and within the scope of IFRS 9 Financial Instruments, is measured at fair value with the changes in fair value recognized in the statement of profit or loss in accordance with IFRS 9. Other contingent consideration that is not within the scope of IFRS 9 is measured at fair value at each reporting date with changes in fair value recognized in profit or loss.
Goodwill on acquisition is initially measured at cost being the excess of purchase price over the fair market value of identifiable assets, liabilities and contingent liabilities acquired. Following initial acquisition it is measured at cost less any accumulated impairment losses. Goodwill is not amortised but is subject to an impairment test at least annually and more frequently if events or changes in circumstances indicate that the carrying value may be impaired. If the fair value of the net assets acquired is in excess of the aggregate consideration transferred, the Group re-assesses whether it has correctly identified all of the assets acquired and all of the liabilities assumed and reviews the procedures used to measure the amounts to be recognized at the acquisition date. If the reassessment still results in an excess of fair value of net assets acquired over the aggregate consideration transferred, then the gain is recognized in profit or loss.
At the acquisition date, any goodwill acquired is allocated to each of the cash-generating units, or groups of cash generating units expected to benefit from the combination's synergies. Impairment is determined by assessing the recoverable amount of the cash-generating unit, or groups of cash generating units to which the goodwill relates. Where the recoverable amount of the cash-generating unit is less than the carrying amount, an impairment loss is recognised.
Joint Arrangements
A joint operation is a type of joint arrangement whereby the parties that have joint control of the arrangement have the rights to the assets and obligations for the liabilities, relating to the arrangement.
The Group conducts petroleum and natural gas exploration and production activities jointly with other venturers who each have direct ownership in and jointly control the operations of the ventures. These are classified as jointly controlled operations and the financial statements reflect the Group's share of assets and liabilities in such activities. Income from the sale or use of the Group's share of the output of jointly controlled operations, and its share of joint venture expenses, are recognised when it is probable that the economic benefits associated with the transaction will flow to/from the Group and their amount can be measured reliably.
Full details of Serica's working interests in those petroleum and natural gas exploration and production activities classified as joint operations are included in the Review of Operations.
Exploration and Evaluation Assets
As allowed under IFRS 6 and in accordance with clarification issued by the International Financial Reporting Interpretations Committee, the Group has continued to apply its existing accounting policy to exploration and evaluation activity, subject to the specific requirements of IFRS 6. The Group will continue to monitor the application of these policies in light of expected future guidance on accounting for oil and gas activities.
Pre-licence Award Costs
Costs incurred prior to the award of oil and gas licences, concessions and other exploration rights are expensed in the income statement.
Exploration and Evaluation (E&E)
The costs of exploring for and evaluating oil and gas properties, including the costs of acquiring rights to explore, geological and geophysical studies, exploratory drilling and directly related overheads, are capitalised and classified as intangible E&E assets. These costs are directly attributed to regional CGUs for the purposes of impairment testing; UK & Ireland and Africa.
E&E assets are not amortised prior to the conclusion of appraisal activities but are assessed for impairment at an asset level and in regional CGUs when facts and circumstances suggest that the carrying amount of a regional cost centre may exceed its recoverable amount. Recoverable amounts are determined based upon risked potential, and where relevant, discovered oil and gas reserves. When an impairment test indicates an excess of carrying value compared to the recoverable amount, the carrying value of the regional CGU is written down to the recoverable amount in accordance with IAS 36. Such excess is expensed in the income statement. Where conditions giving rise to impairment subsequently reverse, the effect of the impairment charge is reversed as a credit to the income statement.
Costs of licences and associated E&E expenditure are expensed in the income statement if licences are relinquished, or if management do not expect to fund significant future expenditure in relation to the licence.
The E&E phase is completed when either the technical feasibility and commercial viability of extracting a mineral resource are demonstrable or no further prospectivity is recognised. At that point, if commercial reserves have been discovered, the carrying value of the relevant assets, net of any impairment write-down, is classified as an oil and gas property within property, plant and equipment, and tested for impairment. If commercial reserves have not been discovered then the costs of such assets will be written off.
Asset Purchases and Disposals
When a commercial transaction involves the exchange of E&E assets of similar size and characteristics, no fair value calculation is performed. The capitalised costs of the asset being sold are transferred to the asset being acquired. Proceeds from a part disposal of an E&E asset, including back-cost contributions are credited against the capitalised cost of the asset, with any excess being taken to the income statement as a gain on disposal.
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 management's assessment of proved and probable reserves, reflecting risks applicable to the specific assets. Changes in reserve quantities and cost estimates are recognised prospectively from the last reporting date.
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'). Following the adoption of IFRS 15 'Revenue from Contracts with Customers', movement in liquids over/underlift is classified in cost of sales with effect from 1 January 2018. Movements during an accounting period had previously been adjusted through revenue, such that gross profit was 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 and financial liabilities are recognised when the Group becomes a party to the contractual provisions of the financial instrument.
Financial assets
Financial assets are classified, at initial recognition, as subsequently measured at amortised cost, fair value through profit or loss, and fair value through other comprehensive income (OCI).
The classification of financial assets at initial recognition depends on the financial asset's contractual cash flow characteristics and the Group's business model for managing them.
With the exception of trade receivables that do not contain a significant financing component or for which the Group has applied the practical expedient, the Group initially measures a financial asset at its fair value plus transaction costs (in the case of a financial asset not at fair value through profit or loss). Trade receivables that do not contain a significant financing component or for which the Group has applied the practical expedient are measured at the transaction price determined under IFRS 15.
The Group determines the classification of its financial assets at initial recognition and, where allowed and appropriate, re-evaluates this designation at each financial year end.
Financial assets at fair value through profit or loss include financial assets held for trading and derivatives. Financial assets are classified as held for trading if they are acquired for the purpose of selling in the near term.
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 are classified, at initial recognition, as financial liabilities at fair value through profit or loss, loans and borrowings, payables, or as derivatives designated as hedging instruments in an effective hedge, as appropriate. The Group's financial liabilities currently include interest bearing loans and borrowings, and trade and other payables. All financial liabilities are recognised initially at fair value. Obligations for loans and borrowings are recognised when the Group becomes party to the related contracts and are measured initially at the fair value of consideration received less directly attributable transaction costs.
After initial recognition, interest-bearing loans and borrowings are subsequently measured at amortised cost using the effective interest method.
Gains and losses are recognised in the income statement when the liabilities are derecognised as well as through the amortisation process.
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 from contracts with customers
Revenue from contracts with customers is recognised when control of the goods or services are transferred to the customer at an amount that reflects the consideration to which the Group expects to be entitled to in exchange for those goods or services. Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for goods provided in the normal course of business, net of discounts, customs duties and sales taxes. The Group has concluded that is is the principal in its revenue arrangements because it typically controls the goods or services before transferring them to the customer.
The sale of crude oil, gas or condensate represents a single performance obligation, being the sale of barrels equivalent on collection of a cargo or on delivery of commodity into an infrastructure. Revenue is accordingly recognised for this performance obligation when control over the corresponding commodity is transferred to the customer. The normal credit term is 15 to 45 days upon collection or delivery.
Finance Revenue
Finance revenue chiefly comprises interest income from cash deposits on the basis of the effective interest rate method and is disclosed separately on the face of the income statement.
Finance Costs
Finance costs of debt are allocated to periods over the term of the related debt using the effective interest method. Arrangement fees and issue costs are amortised and charged to the income statement as finance costs over the term of the debt.
Share-Based Payment Transactions
Employees (including 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 2018:
- IFRS 9 - Financial Instruments; and
- IFRS 15 - Revenue from Contracts with Customers
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 has adopted the new standard on the required effective date and applied the modified approach which has resulted in no required adjustment to retained earnings.
For trade receivables and contract assets, the Group applies a simplified approach in calculating ECLs. Therefore, the Group does not track changes in credit risk but instead recognises a loss allowance, if applicable, based on lifetime ECLs at each reporting date. The Group has established a provision matrix that is based on its historical credit loss experience, adjusted for forward looking factors specific to the debtors and the economic environment.
The Group has performed an impact assessment for the application of IFRS 9 based on currently available information. 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 has a material impact on the valuation of financial assets. The Group's impact assessment has indicated no changes to amounts previously recognised and therefore there are no adjustments to opening retained earnings.
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 superseded the previous revenue recognition guidance including IAS 18 Revenue and related interpretations when it became 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, the accounting for certain contracts, such as those for underlifts and overlifts, was identified as an area of change. Movements in liquids overlift/underlift previously disclosed in sales revenue (see note 4) has been classified in cost of sales with effect from 1 January 2018.
There are no other new or amended standards or interpretations effective for the first time for periods beginning on or after 1 January 2018 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 16 - Leases |
1 January 2019 |
|
|
|
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.
IFRS 16 introduces a single, on-balance sheet lease accounting model for lessees. A lessee recognises a right-of-use asset, representing its right to use the underlying asset, and a lease liability, representing its obligation to make lease payments. Lessees will be required to recognise separately the interest expense on the lease liability and the depreciation expense on the right-of-use asset. There are recognition exemptions for short-term leases and leases of low-value items. Lessor accounting remains similar to the current accounting under IAS 17 i.e. lessors continue to classify leases as finance or operating leases.
During 2018, the Group has performed an impact assessment for the application of IFRS 16. This assessment is based on currently available information and will be subject to changes arising from further reasonable and supportable information being made available to the Group in 2019. Serica does not currently have material lease contracts and therefore the impact of the adoption of the new standard at 1 January 2019 is not expected to be material. The Group continues to assess its accounting processes, controls and policies on an ongoing basis.
The Group will adopt the new standard on the required effective date using the modified retrospective method. The Group will apply the practical expedient to grandfather the definition of a lease on transition. It will therefore apply IFRS 16 to all contracts entered into before 1 January 2019 and identified as leases in accordance with IAS 17. Contracts which have not been considered or identified as a lease will continue to be accounted for in line with their historical treatment. The Group will also elect to use the exemptions proposed by the standard on lease contracts for which the lease terms ends within 12 months as of the date of initial application and lease contracts for which the underlying asset is of low value.
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 |
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