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| Share Name | Share Symbol | Market | Type | Share ISIN | Share Description |
|---|---|---|---|---|---|
| Serica Energy Plc | LSE:SQZ | London | Ordinary Share | GB00B0CY5V57 | ORD USD0.10 |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 4.90 | 2.72% | 185.20 | 184.00 | 185.00 | 186.90 | 180.00 | 181.60 | 2,981,012 | 16:35:11 |
| Industry Sector | Turnover | Profit | EPS - Basic | PE Ratio | Market Cap |
|---|---|---|---|---|---|
| Crude Petroleum & Natural Gs | 632.64M | 102.98M | 0.2652 | 6.95 | 715.72M |
From May 2019 to May 2024
TIDMSQZ
RNS Number : 7337B
Serica Energy plc
06 April 2017
Serica Energy plc
("Serica" or the "Company")
Results for the year ended 31 December 2016
London, 6 April 2017 - Serica Energy plc (AIM: SQZ) today announces its financial results for the year ended 31 December 2016. The results are included below and copies are available at www.serica-energy.com and www.sedar.com.
Results Highlights
Financial
-- Gross profit for 2016 of US$6.6 million (2015: US$16.1 million) notwithstanding a six-month production shut-in earlier in the year.
-- Strong Erskine well performance, improved off-take facility uptime, allied to rising commodity prices and lower opex per barrel costs, delivered a particularly strong Q4 2016.
-- Group profit after tax of US$10.8 million (2015: US$6.5 million) boosted by deferred tax credits arising from tax losses brought forward.
-- Cash balances of US$16.6 million at 31 December 2016, increasing to US$25.7 million by end March 2017 before receipt of estimated March net sales income of US$3.5 million.
-- No borrowings or material commitments at year-end, minimal corporate overheads and with cash balances growing significantly through Q1 2017.
Operational
Erskine Field (Serica 18%)
The Erskine field has performed well since production was restarted on 29 August 2016 and is benefitting from more favourable commodity prices. Since restart:
-- Production averaged over 3,150 boe per day net to Serica to end March 2017. -- Production efficiencies averaging as much as 90% in recent months. -- Serica's operating and transportation costs averaging below US$14 per boe. -- Cash generation from production continues to benefit from significant tax efficiencies.
-- An updated independent audit by Netherland, Sewell & Associates ("NSAI") of the Erskine field confirmed Serica's share of estimated proven plus probable reserves at 3.8 million boe as of 1 January 2017.
Columbus Field (Serica 50%)
Serica, as field operator, is pushing forward to realising Columbus development potential:
-- Two potential development options are under review in collaboration with nearby operators:
o An extended reach development well drilled from the Lomond platform delivering capital cost efficiencies and easier maintenance access; or,
o A subsea well completion tied into a proposed third-party pipeline to the Shearwater platform.
-- Serica is working towards selection of the best alternative and a full Field Development Plan by the end of 2017 with a view to commencing development work in 2018. First gas is targeted for late 2019.
-- Columbus contingent resources net to Serica estimated by NSAI at 6.2 mmboe.
Exploration
Serica's exploration portfolio offers material upside for minimal near-term expenditure:
-- North Sea: Well planning for the Rowallan prospect advanced. Site survey and long-lead items approved by partners for 2017 with drilling planned for 2018. Serica fully carried on costs to completion of first well. Serica estimates potential net P(50) resources at 20 mmboe.
-- Ireland, Rockall Basin: Two-year extension on licence 4/13 secured in order to bring in a partner to join in drilling an exploration well.
-- Ireland, Slyne Basin: Equity position increased from 50% to 100% on licence 01/06. Two-year extension granted to enable further evaluation of the potential for commercial oil first identified by the 2009 Bandon oil discovery.
-- Namibia: Luderitz licence 47 renewed and extended to enable review work to continue and partners to be secured.
Outlook for 2017
Serica's strong financial position leaves it well placed to add further value for shareholders:
-- Strong start to the year with Serica's net production averaging over 3,200 boe in Q1 at average prices of $54 per barrel for oil and 48 pence per therm for gas.
-- Production guidance for the year reiterated at 2,500-3,000 boe per day net to Serica.
-- Oil hedges at US$50/bbl (Q2 2017) and gas hedges at 40p per therm (Q2 2017)/38p per therm (Q3 2017) covering approximately 50% of forecast production over those periods.
-- Working with partners to extract full value from producing and development assets. -- Further growth opportunities are available and under consideration.
Tony Craven Walker, Serica's Chairman commented:
"Serica has continued to strengthen its financial position after a particularly strong fourth quarter. Following an especially good performance in terms of production rates and efficiencies, lower opex and improved sales prices since the restart of Erskine field production in late August, we enter 2017 with a strong balance sheet, no borrowings, growing cash resources and increasing opportunities to add value from our existing oil and gas resources.
We are looking to build on this strong financial base. Our immediate focus is to broaden and expand our producing asset base through progressing the Columbus field to development and by acquiring additional production where we believe Serica can add value. The UK North Sea, where there are strategic benefits, tax efficiencies and opportunities on offer and where we feel we have an edge, remains a prime area of focus.
On the exploration front, we are delighted that operations have now commenced in preparation for drilling a well on the Rowallan prospect on which we have a 15% carried interest. A successful outcome of this well would have a material impact on Serica. In Ireland and Namibia we have received licence extensions from the authorities and continue to progress our holdings where we see real future potential."
Technical Information
The technical information contained in the announcement has been reviewed and approved by Clara Altobell, Head of Operations at Serica Energy plc. Clara Altobell (MSc in Petroleum Engineering from Imperial College, London) has over 20 years of experience in oil & gas exploration, production and development and is a member of the Society of Petroleum Engineers (SPE) and the Petroleum Exploration Society of Great Britain (PESGB).
Regulatory
This announcement is inside information for the purposes of Article 7 of Regulation 596/2014.
Enquiries:
Hot Features
Premium
Serica Energy plc
+44 (0) 20 7487
Tony Craven Walker tony.cravenwalker@serica-energy.com 7300
Peel Hunt
+44 (0) 20 7418
Richard Crichton richard.crichton@peelhunt.com 8900
+44 (0) 20 7418
Ross Allister ross.allister@peelhunt.com 8900
Instinctif Partners
+44 (0) 20 7457
2020
+44 (0) 7831 347
David Simonson david.simonson@instinctif.com 222
+44 (0) 20 7457
2020
+44 (0) 7493 867
George Yeomans george.yeomans@instinctif.com 436
NOTES TO EDITORS
Serica Energy is an oil and gas exploration and production Company with exploration, development and production assets in the UK offshore and exploration interests in the Atlantic margins offshore Ireland, Morocco and Namibia. Further information on the Company can be found at www.serica-energy.com.
The Company is listed on the AIM market of the London Stock Exchange under the ticker SQZ and is a designated foreign issuer on the TSX. To receive Company news releases via email, please contact serica@instinctif.com and specify "Serica press releases" in the subject line.
FORWARD LOOKING STATEMENTS
This disclosure contains certain forward looking statements that involve substantial known and unknown risks and uncertainties, some of which are beyond Serica Energy plc's control, including: geological, geophysical and technical risk, the impact of general economic conditions where Serica Energy plc operates, industry conditions, changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced, increased competition, the lack of availability of qualified personnel or management, fluctuations in foreign exchange or interest rates, stock market volatility and market valuations of companies with respect to announced transactions and the final valuations thereof, and obtaining required approvals of regulatory authorities. Serica Energy plc's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward looking statements and, accordingly, no assurances can be given that any of the events anticipated by the forward looking statements will transpire or occur or, if any of them do so, what benefits, including the amount of proceeds, that Serica Energy plc will derive therefrom.
EXECUTIVE CHAIRMAN'S STATEMENT
Dear Shareholder
I am pleased to report strong underlying performance from Serica's assets. Gross profit for 2016 of US$6.6 million was achieved in spite of a six-month production shut-in earlier in the year to resolve pipeline issues and during a difficult period for oil and gas prices. This robust performance puts Serica in a very strong position within the sector. We ended the year with no borrowings or material commitments and with cash balances growing significantly. This performance has continued post the year-end.
This strong financial position enables us to look for new opportunities to add further value for shareholders and we are reviewing a number of such opportunities. These will be aimed at increasing and diversifying our production streams as well as balancing risk. We are also looking at utilising our tax loss position to the full and acquiring assets where we have some degree of control and believe we can add value through applying our expertise.
The Erskine field has performed well since production was restarted on 29 August 2016, averaging over 3,150 boe per day net to Serica to end March 2017. This was despite a ten-day shut-in in late February 2017 for maintenance and installation of a back-up export pump, and we have achieved production efficiencies averaging as much as 90% in recent months. Serica's operating and transportation costs have also been maintained at low levels below US$14 per boe at current production rates. The combined effect of this performance has been a significant increase in cash balances, from US$16.6 million at the year end, to US$25.7 million by end March 2017, an increase of US$9.1 million during the three month period. With administration costs for the year standing at US$2.1 million, we continue to contain corporate overhead at minimal levels.
Production resumption has also taken place against a backdrop of improved commodity prices. Oil sales prices rose to an average US$49 per barrel during the second half of 2016 whilst gas sales prices showed an even stronger rise, averaging over 40 pence per therm during the same period. A gas sales contract, under which Serica supplied approximately one quarter of its Erskine gas production at relatively low contract prices (approximately 30 pence per therm in the 2015/6 contract year), was terminated by Serica on 30 September 2016 coinciding with the upsurge in gas prices and allowing Serica the full benefit since then. Since the turn of the year oil prices have averaged US$54 per barrel with UK gas prices averaging 48 pence per therm.
Serica's current operating and transportation cost of below US$14 per boe reflects overall cost reductions, sustained production rates and also the impact of the lower sterling to dollar exchange rate. In addition to maintaining focus on cost control and improved production uptime, future costs per barrel can also be reduced through the introduction of new third party throughput to Lomond including production from the Columbus field whose progress is described in more detail in the Operations Review. With the sale by Shell of the Lomond platform to Chrysaor as part of a bigger package and Chrysaor committed to extending production life and maximising economic recovery, we believe that the incentives are now in place for all parties to find a solution to Columbus's export needs.
We are looking at various solutions for the development of Columbus, including the option of drilling into the field directly from the Lomond platform as well as the possibility of connecting a subsea well to an Arran-to-Shearwater pipeline, planned by the operator of the Arran field located to the north. The potential advantages of an extended-reach well from Lomond include no pipeline or associated subsea equipment, faster hook up time, easier well maintenance access and lower-cost abandonment. It would also reduce unit operating costs for the hub users overall, including Erskine, and help to attract further third party business and defer Lomond platform abandonment, thus increasing overall reserves recovery in the area. It is our objective to compare the costs and risks of the different solutions, as well as potential benefits such as these, in order to reach a decision on Columbus development with our partners and infrastructure owners and finalise a field development plan during 2017.
We continue to seek ways to unlock the value in our exploration assets. We hold significant interests in acreage offering a balance of lower risk, mature basins and high risk, high reward frontier areas. We have mitigated drilling expenditure during the industry downturn through farm-outs and have constrained costs in our more frontier acreage but will be looking to expand this programme as our financial position strengthens.
Offshore Namibia and Ireland we have been granted two-year extensions with low cost exploration commitments and we are receiving expressions of interest from third parties for possible joint ventures as the exploration market slowly recovers buoyancy. In the UK we have a fully carried 15% interest in the Rowallan prospect in Central North Sea block 22/19c and, in East Irish Sea block 113/27c, we have a 20% carried interest in the Doyle prospect. Rowallan has a P50 potential resource estimate of 20 million boe net to Serica. It is one of three large, high pressure, high temperature prospects located on block 22/19c which lies close to our Columbus and Erskine interests. Plans to drill a well were delayed last year pending greater clarity on the outlook for oil and gas prices but partners have now agreed to place advance orders for long-lead items and proceed with site surveying this year in preparation for drilling of the Rowallan exploration well in 2018. A successful well would be material to Serica and highlight further potential on the block.
In the Doyle block we await the outcome of decisions from our operator Zennor Petroleum who have an 80% interest in the block following the withdrawal of Centrica, our previous operator, in 2016. Zennor have been seeking a partner to share in their 80% interest. In the absence of securing such a partner they may elect to relinquish the block. The licence authority, OGA, have granted an extension until 30 April 2017.
Outlook
With our strong balance sheet, growing cash resources and opportunities to add value from our existing oil and gas resources, Serica is extremely well positioned to execute its growth strategy. We recognise our dependence upon Erskine as our only current source of income. Whilst this is generating material cash flows for the Company and we are expecting this to continue, we are looking to see how we can use our financial strength to diversify and enhance our cash generative capacity through the acquisition of additional production where we believe we can also add value. We see this as an essential part of our risk management strategy but a successful outcome would also increase the scale and spread of the Company's operations and create greater visibility, financial capacity and liquidity for the Company to the benefit of shareholders.
In view of the strategic benefits, synergies and tax efficiencies our immediate focus remains on the UK North Sea where there are opportunities on offer as the oil majors restructure their asset portfolios and make way for smaller, more cost efficient operators. The market is, as ever, competitive, particularly from new sources of private equity, and the vibrancy of the market has been demonstrated by a number of recently announced transactions. We are cautious in our approach and remain fully cognisant of the need to high grade the number of opportunities available but believe that such a strategy will also help us in bringing forward the clear potential of our existing portfolio.
In summary, we are extremely positive on the opportunities open to Serica and on our ability to execute them. We are looking forward to an interesting and potentially exciting year ahead.
Antony Craven Walker
Executive Chairman
5 April 2017
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 2016.
References to the "Company" include Serica and its subsidiaries where relevant. All figures are reported in US dollars ("US$") unless otherwise stated. The Company is subject to the regulatory requirements of the AIM market ("AIM") 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 licence interests in the UK Continental Shelf and exploration interests in Ireland, Morocco and Namibia.
REVIEW OF OPERATIONS
Production
Central North Sea: Erskine Field - Blocks 23/26a (Area B) and 23/26b (Area B), Serica 18%
All of Serica's production comes from its 18% interest in Erskine, a gas and condensate producing field located in the UK Central North Sea and acquired from BP in June 2015. Serica's co-venturers are Chevron 50% (operator) and Shell 32%. Erskine fluids are processed and exported via the Lomond platform, which is 100% owned and operated by Shell, who acquired Lomond and a share in Erskine through the acquisition of BG in February 2016. Serica's condensate allocation is delivered and sold as Forties crude oil at the Cruden Bay terminal and gas is sold at the CATS terminal on Teeside. Shell has recently announced a sale of its interests in Erskine and Lomond, subject to certain consents, to Chrysaor Holdings Limited, a private equity-backed oil and gas company.
An updated independent audit of the Erskine field confirmed Serica's share of estimated proven plus probable reserves at 3.8 million boe as of 1 January 2017, in line with previous estimates.
Following a strong January and February 2016 when production averaged over 3,200 boe per day net to Serica, the field was subject to an extended shut-in. On 27 February 2016 a cleaning device known as a pig became stuck in the condensate export pipeline that runs between Lomond and the Everest platform, causing a blockage. The blockage was caused by the pig encountering a build-up of wax in the line that had been deposited over time by the export fluids. The operation to clear the line took ten weeks due to the engineering requirements to gain access to the blockage with wax solvent and then to allow for optimal time to soak and dissolve the wax. Rather than restarting in mid-May, the planned June shut-in for maintenance work on the Lomond platform was brought forward with the eventual full restart of Erskine occurring on 29 August 2016.
Erskine field production since the 29 August restart has delivered strong and consistent volumes, averaging approximately 3,150 boe per day net to Serica to year-end despite a series of capacity restrictions on the Forties Pipeline, through which Erskine liquids are exported, and some minor system trips on the Lomond offtake facilities. This performance has continued into 2017, averaging over 3,200 boe per day net to Serica over the first three months despite a ten-day shut-in for further treatment of wax build-up in the condensate export line and installation of a back-up pump. The strong performance of the Erskine wells over the last 21 months, when unconstrained by offtake restrictions, fully supports current estimates of ultimate reserves recovery and may leave scope for further upside.
Improved planning and communication between the Erskine and Lomond facility operators, supported by Serica, has resulted in reducing production interruptions. This has been achieved by identifying system vulnerabilities and planning more efficient maintenance programmes. Production efficiency exceeded 80% from the end of August 2016 to the end of the year and has averaged around 90% in recent months, demonstrating continued performance improvement.
Having assessed the lessons from the blockage of the Lomond to Everest condensate export pipeline last year, the Lomond facilities operator is implementing a number of changes to reduce the chance of a reoccurrence. These include improved pipeline monitoring, more regular pigging programmes and intermittent shut-ins for the injection of wax solvents when required.
Ongoing reductions to the Erskine/Lomond cost-base have combined with increased throughput volumes to lower Erskine operating costs per boe. Though Serica's average operating cost for 2016 was US$23 per boe including transportation costs, this falls below US$14 per boe after excluding the effects of the export line blockage, illustrating that maintaining production volumes is as important as cutting costs in the drive to minimise costs per barrel.
This also drives the strategy to bring other fields, such as Columbus, through the Lomond hub as soon as practicable to the benefit of all hub owners. Recent analysis by Oil & Gas UK suggests that average operating costs of US$15 per barrel are now being achieved through the UK North Sea as a whole, setting a benchmark for all operators which should sustain profitable North Sea operations even during future periods of low commodity prices.
No significant capital investment is planned for Erskine in 2017.
Development
Central North Sea: Columbus Field - Blocks 23/16f and 23/21a, Serica 50%
The Columbus gas condensate field is located in close proximity to the Lomond platform, which is the offtake route for production from Serica's Erskine producing interest. Serica as Columbus field operator is working towards a full Field Development Plan by the end of 2017 with a view to commencing development work in 2018. First gas is targeted for late 2019 or 2020.
The Columbus field has been fully appraised with four wells and will be developed with a single production well. Serica is progressing two potential development options for Columbus. The first option is an extended-reach development well drilled into Columbus from the Lomond platform, located 5 kilometres away. This technology has been extensively used in the North Sea, especially in Norway. Alternatively a well could be drilled as a subsea completion and tied into a proposed third-party pipeline to the Shearwater platform, with either option delivering similar levels of reserves recovery.
The Lomond platform has spare well slots and a jack-up rig can be utilised to drill a well into Columbus from the platform. The advantage of this route is that there is no pipeline or associated subsea equipment required and consequently time to hook up the well and bring it on production should be much shorter than would be required for a subsea well. A platform well also has the advantages of easy access for future well maintenance interventions and lower-cost abandonment. Columbus production into the Lomond platform is likely to benefit the Erskine and Lomond fields by reducing unit operating costs whilst improving the product mix and could result in deferring the date of platform abandonment thus increasing reserves recovery. Deferment of Lomond platform abandonment would also increase its attraction for other potential third party business to mutual benefit.
In parallel, Serica is working with the Arran field operator to appraise the option of tying Columbus into a proposed new pipeline into the Shearwater platform. This would be a longer offtake route and the Columbus development well would be drilled as a subsea completion. The advantages of this option are shorter drilling time and the potential for lower unit operating costs. However, there would be an overall increase in development costs and there would be greater complexity involved in coordinating with a separate field development, which is expected to result in a longer development timeline.
Whichever option is selected, Serica plans to take full advantage of current market conditions and latest drilling and subsea technology to ensure a low cost, efficient and reliable plan for development. Serica is undertaking studies on both options in order to make an informed decision, based on risks and economics, during the course of 2017, following which a field development plan will be submitted to the Oil and Gas Authority.
Exploration
Central North Sea: Rowallan Prospect - Block 22/19c, Serica 15%
Detailed well planning for the Rowallan prospect is underway, with spending on a site survey and long-lead items approved by partners for 2017. A vessel will be deployed in the summer to perform a site survey and drill geotechnical boreholes in preparation for drilling in 2018. The prospect is located within Serica's core Central North Sea area, close to Erskine and Columbus. Serica is fully carried on all costs for a well on this high pressure high temperature prospect. There are similarities to the nearby Culzean field, with the well targeting the same age Jurassic/Triassic reservoir sands and a fault-and-dip closed trap.
A discovery could deliver 20 million boe net to Serica (P50 resource estimate), with further upside in the form of two similar prospects, Dundonald and Sundrum, also identified on the block.
East Irish Sea: Doyle Prospect - Blocks 113/22a, 113/26b and 113/27c, Serica 20%
The Doyle gas prospect lies in close proximity, and is analogous, to the producing Rhyl field. Serica is carried for costs on an exploration well on the prospect up to a gross cap of GBP11 million. The operator has been seeking a partner to share in its drilling costs following the withdrawal of Centrica, our previous operator, in 2016. In the absence of securing such a partner the block may be relinquished. The licence authority, OGA, have granted an extension until 30 April 2017.
Ireland
Offshore Ireland is currently experiencing renewed interest including the entry of a number of oil and gas majors. This is demonstrated through significantly increased licence applications, farm-ins and seismic data acquisition programmes expected to lead to renewed drilling in the region.
Rockall Basin: Frontier Exploration Licences 1/09 and 4/13, Serica 100%
Serica has secured a two-year extension on licence 4/13 in order to bring in a partner to join in drilling an exploration well. The well is designed to test two prospects, the shallower prospect being a Cretaceous fan defined by seismic anomaly and analogous to prospects identified in the Porcupine basin. This overlies a deeper target, a structural fault block of Permian/Triassic age, analogous to the nearby Dooish discovery. Serica estimates P50 resources for these stacked prospects to be in the order of 4tcf of gas and 250 million barrels of condensate, which would result in a major development.
Licence 1/09 contains a large structural prospect, also a Dooish analogue, and Serica is seeking a partner to drill a well to prove the concept, ideally as part of the same drilling programme as 4/13.
In 2017, further work is planned on the licences to investigate the potential for productive fractured basement. The recent well test on the Lancaster discovery by Hurricane in the West of Shetlands area has proved the production capability of fractured basement.
Slyne Basin: Frontier Exploration Licence 01/06, Serica 100%
Serica has increased its equity from 50% to 100% following the withdrawal of DEA from the licence and has secured a two-year extension to further explore the potential first identified through the Bandon oil discovery drilled in 2009. In that time, Serica plans to further de-risk the Boyne prospect, down-dip of the Bandon discovery, by detailed analysis to better predict the oil type likely to be found in the deeper Jurassic and Triassic sandstone formations.
Serica is seeking to identify a farm-in partner to take advantage of low drilling and development costs and, in the event of a commercial discovery, to follow with a swift development to get to first oil/gas. The P50 resource estimate of 115 million barrels of oil is expected to result in an attractive economic development at current oil prices.
Namibia
Luderitz Basin: Blocks 2512A, 2513A, 2513B and 2612A (part), Serica 85%
Serica has progressed to the first renewal period of the licence, running until the end of 2018. This licence period does not include a commitment to drill a well. However, the prospectivity, identified by a major seismic programme operated by Serica, is such that Serica would wish to drill a well within this time-frame, subject to the introduction of a new partner. The excellent 3D seismic data has identified giant carbonate prospects as well as large, more conventional Cretaceous fan prospects supported by seismic anomalies. Serica plans to work on identifying more prospects supported by the latest seismic visualisation techniques as well as seeking a partner to drill the main carbonate prospect (gross P90 to P10 range of 138 million to 2.8 billion barrels of oil).
Morocco
Sidi Moussa Licence: Serica 5%
The Sidi Moussa licence has been extended until August 2017 to allow the operator, Genel, time to consider further exploration activity. Serica has elected not to participate in any further drilling but has an option to buy back in should a well be drilled.
Norway
The operator of the Vette field, in which Serica held an economic interest dependent upon the level of oil prices prevailing at first production, determined that the potential development was uncommercial at current oil and gas prices and the licence has been relinquished.
LICENCE HOLDINGS
The following table summarises the Group's licences as at 31 December 2016.
Block(s) Description Role % at Location
31/12/16
--------------------- ------------- --------- -------------
UK
--------------------- ------------- --------- -------------
Central
22/19c Exploration Non-operator 15% North Sea
--------------------- ------------- --------- -------------
23/16f, 23/21a Columbus Field Operator 50% Central
(part) - North Sea
Development planned
--------------------- ------------- --------- -------------
Erskine Field Central
23/26a, 23/26b - Production Non-operator 18% North Sea
--------------------- ------------- --------- -------------
East Irish
113/26b Exploration Non-operator 20% Sea
--------------------- ------------- --------- -------------
East Irish
113/27c Exploration Non-operator 20% Sea
--------------------- ------------- --------- -------------
East Irish
113/22a Exploration Non-operator 20% Sea
--------------------- ------------- --------- -------------
Ireland
--------------------- ------------- --------- -------------
27/4 (part) Exploration Operator (1) 100% Slyne Basin
--------------------- ------------- --------- -------------
27/5 (part) Exploration Operator (1) 100% Slyne Basin
--------------------- ------------- --------- -------------
27/9 (part) Exploration Operator (1) 100% Slyne Basin
--------------------- ------------- --------- -------------
Rockall
5/17 Exploration Operator 100% Basin
--------------------- ------------- --------- -------------
Rockall
5/18 Exploration Operator 100% Basin
--------------------- ------------- --------- -------------
Rockall
5/22 Exploration Operator 100% Basin
--------------------- ------------- --------- -------------
Rockall
5/23 Exploration Operator 100% Basin
--------------------- ------------- --------- -------------
Rockall
5/27 Exploration Operator 100% Basin
--------------------- ------------- --------- -------------
Rockall
5/28 Exploration Operator 100% Basin
--------------------- ------------- --------- -------------
Rockall
11/10 Exploration Operator 100% Basin
--------------------- ------------- --------- -------------
Rockall
11/15 Exploration Operator 100% Basin
--------------------- ------------- --------- -------------
12/1 (part) Exploration Operator 100% Rockall
Basin
--------------------- ------------- --------- -------------
Rockall
12/6 Exploration Operator 100% Basin
--------------------- ------------- --------- -------------
12/11 (part) Exploration Operator 100% Rockall
Basin
--------------------- ------------- --------- -------------
Namibia
--------------------- ------------- --------- -------------
Luderitz
2512A Exploration Operator 85% Basin
--------------------- ------------- --------- -------------
Luderitz
2513A Exploration Operator 85% Basin
--------------------- ------------- --------- -------------
Luderitz
2513B Exploration Operator 85% Basin
--------------------- ------------- --------- -------------
2612A (part) Exploration Operator 85% Luderitz
Basin
--------------------- ------------- --------- -------------
Morocco
--------------------- ------------- --------- -------------
Sidi Moussa Exploration Non-operator 5% Tarfaya-Ifni
Basin
--------------------- ------------- --------- -------------
(1) Interest increased from 50% to 100% effective 1 December 2016 following confirmation of licence extension in March 2017.
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 a rate of 6,000 standard cubic feet per barrel)
CPR Competent Persons Report
FEED Front End Engineering Design
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
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
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
FINANCIAL REVIEW
The completion of the Erskine acquisition on 4 June 2015 brought significant oil and gas revenue streams, accelerating the utilisation of Serica's past UK tax losses. The Company accounts for its share of field revenues and costs post acquisition, hence the comparative figures for 2015 include Erskine revenues and costs only for the period from 4 June to 31 December 2015.
Group profit after tax of US$10.8 million for 2016 compares to a profit after tax of US$6.5 million for 2015 with the six-month Erskine field shut-in, running to late August 2016, significantly restricting 2016 sales revenues whilst operating costs continued to be incurred. Following the restart, rising commodity prices, allied to strong well performance, improved off-take facility uptime and lower opex per barrel costs, delivered a particularly strong Q4 2016.
Erskine asset overview
Although the impact of the extended Erskine field shut-in on 2016 results was substantial, field production performance during January and February and then from the 29 August restart to year-end demonstrated the true capability of the field with production net to Serica averaging over 3,150 boepd in the latter period, generating good cash flow throughout Q4 2016 as both oil and gas prices rose. All of the oil is sold at monthly average spot prices and from 1 October 2016 all of the gas is sold in the market at monthly average spot prices. NGL's derived from gas production are also sold at monthly average spot prices for the respective products.
Field production has continued at similar levels in 2017 to date, averaging over 3,200 boe per day net to Serica in Q1 2017. The Brent oil benchmark has averaged over US$54 per barrel in Q1 2017 (2016 average of US$45 per barrel) whilst UK gas prices rose to over 60 pence per therm in January and have averaged over 48 pence across the Q1 2017 period (2016 average of 35 pence per therm).
Serica's operating costs including transportation and processing were US$23 per boe during 2016 reflecting the six-month shut-in, but are now averaging well below these levels and, assuming steady ongoing production, we expect operating costs to be below US$14 per boe in 2017.
Strong net income from Erskine since the re-start of production in late August has allowed Serica to continue to rebuild cash resources. As at 31 March 2017, cash balances had increased from the year-end balance of US$16.6 million to US$25.7 million, before receipt of March sales which are expected to add approximately US$3.5 million net of operating costs.
Serica's significant tax losses brought forward from prior periods have been applied to fully shelter Erskine 2016 net income from tax payments and are expected to be sufficient to cover future income from the field leaving a surplus available to cover new United Kingdom Continental Shelf sources of income.
Results from operations
Income statement - continuing operations
Serica generated a gross profit of US$6.6 million in 2016 from its Erskine field operations after the effect of the six-month field shut-in. The reported 2015 comparative gross profit of US$16.1 million reflected performance from the date of completion, 4 June 2015, to the year end, 31 December 2015. Serica's 18% field interest generated net combined oil and gas production of 597,000 boe in 2016 compared to 606,000 boe for the reported 2015 period.
Sales revenues
The Company currently generates all its sales revenue from the Erskine field in the UK North Sea. Revenue is earned from oil, gas and NGL product streams. Serica's condensate allocation is sold as Forties crude oil.
Net Erskine field gas production averaged 5.0 mmscf per day during 2016, whilst condensate production averaged 800 barrels per day reflecting the six-month shut-in. In the 2015 seven month comparative period, net Erskine field gas production averaged 8.6 mmscf per day together with average condensate production of 1,462 barrels per day.
Sales revenues in 2016 from lifted barrels of oil were US$11.1 million (2015: US$10.4 million) at an average realised price of US$42.10/bbl (2015: US$44.50/bbl). Associated NGL products earned additional revenue of US$0.3 million (2015: US$0.3 million).
Sales revenues in 2016 also include US$0.5 million (2015: US$3.4 million) reflecting the movement from a combined liquids overlift position at 31 December 2015 to an underlift position at 31 December 2016.
The 2016 gas production was sold at prices averaging US$4.6 per mscf (2015: US$5.1 per mscf) and generated US$8.4 million (2015: US$9.1 million) of revenue net to Serica. A gas sales contract, under which Serica supplied approximately one quarter of its Erskine gas production at relatively low contract prices (approximately 30 pence per therm in the 2015/6 contract year), terminated on 30 September 2016.
Three NGL products (Propane, Butane and Naphtha) are derived from associated gas production and contributed revenue of US$1.2 million (2015: US$0.8 million) net to Serica.
Cost of sales and depletion charges
Cost of sales is driven by production from the Erskine field and comprises field operating costs and a depletion charge against the asset's net book amount.
The overall 2016 charge of US$14.9 million (2015: US$7.9 million) comprised direct field operating costs of US$13.6 million (2015: US$6.6 million) and non-cash depletion of US$1.3 million (2015: US$1.3 million). The most significant elements of the field operating costs are as follows: Erskine's contribution to the running costs of the Lomond facilities, standalone Erskine field operating costs, other transportation costs for use of the FPS and CATS pipelines, and charges for any necessary surface or sub-surface maintenance work. Significant operational expenditure continues during periods of field shut-in when no revenue is earned.
The US$7.0 million increase in field operating costs from 2015 to 2016 is largely due to the full year 2016 reporting period compared to seven months of post-acquisition Erskine operations in 2015. The 2016 expense also includes an agreed level of contribution from the Erskine partners to the exceptional costs incurred by the Lomond operator to resolve the Lomond/Everest pipeline blockage. Operating costs are billed in GBGBP and, following the decline in the strength of GBGBP against the US$ in June 2016, the reported US$ equivalent figures have reduced during 2H 2016 compared to US$ oil revenue streams.
Depletion charges principally represent the costs of Erskine acquisition spread over the estimated remaining commercial life of the field on a unit of production basis.
Other expenses and income
The Company generated a profit before tax from continuing operations of US$3.3 million for 2016 compared to a profit before tax of US$4.3 million for 2015.
Other expenditure of US$0.1 million in 2016 represented hedging premium net of gains.
Pre-licence expenditure of US$0.2 million for 2016 has increased from the 2015 charge of US$0.1 million due to an increased level of activity on new business in the second half of the year as the Company has increased its focus on adding to its existing UK North Sea asset portfolio. Pre-licence costs included direct costs and allocated general administrative costs incurred on oil and gas activities prior to the award of licences, concessions or exploration rights.
The Exploration and Evaluation ('E&E') asset impairment charge of US$0.1 million in 2016 comprised minor asset write-offs from licences in Morocco and the UK. The aggregate 2015 impairment charge of US$8.2 million comprised US$13.1 million of asset write-offs from relinquished licences and historic wells not considered to hold remaining economic potential, offset by a US$4.9 million pre-tax impairment reversal recorded against the Columbus field asset.
Administrative expenses of US$2.1 million for 2016 decreased from US$2.7 million in 2015 as the Company's cost-cutting efforts continued and the largely GBGBP-based overheads benefitted from the weaker average GBGBP exchange rate compared to US$.
Foreign exchange
Serica retains certain non-US$ cash holdings and other financial instruments relating to its operations. The US$ value of these may fluctuate from time to time causing reported foreign exchange gains and losses. Serica maintains a broad strategy of matching the currency of funds held on deposit to the expected expenditures in those currencies. Management believes that this mitigates most of any actual potential currency risk from financial instruments.
Foreign exchange charges of US$0.6 million for 2016 (2015: US$0.4 million) largely reflect a reduction in the reported US$ equivalent of GBGBP cash balances caused by the weakening of GBGBP against the US$ after the EU referendum result. Unrealised losses on the revaluation of GBGBP cash balances have been partially offset by realised gains on settlement of significant GBGBP creditors.
Finance costs of US$0.2 million were incurred in 2016 (2015: US$0.2 million) largely comprising the interest accruing on the liability payable to BP relating to the Erskine acquisition.
The deferred taxation credit of US$7.5 million (2015: US$2.4 million) arose from the recognition of a corresponding deferred tax asset on the Erskine field interest.
Income statement - discontinued operations
Following the cessation of production and the decommissioning of the Kambuna field facilities in Indonesia in the second half of 2013, the financial results of the Kambuna field business segment are disclosed within 'discontinued operations' in the financial statements and separate from the results of the retained core business segments.
This discontinued operation loss of US$0.3 million in 2015 comprised a final assessment for asset write-offs and minor operator expense as residual matters were closed out with one final charge of US$8,000 recorded in 2016.
Balance Sheet
During 2016, the total carrying value of investments in E&E assets increased by US$1.4 million from US$51.8 million to US$53.2 million. This increase consisted of additions in the year on the following assets. In Africa, US$0.4 million was incurred in respect of the Luderitz basin licence interests in Namibia. In the UK, US$0.4 million was incurred on the Columbus development and other exploration licences. In Ireland, US$0.4 million was incurred on exploration work on the Rockall licences and US$0.2 million on the Slyne interest.
The property, plant and equipment balance of US$9.1 million as at 31 December 2016 comprises the net book amount of the Erskine asset acquisition costs capitalised on completion of the transaction net of depletion charges to-date.
Trade and other receivables at 31 December 2016 totalled US$6.8 million, an increase of US$2.6 million from the 2015 balance of US$4.2 million. The 2016 balance includes US$4.3 million (2015: US$3.2 million) from December oil, gas and NGL sales earned from the Erskine field, and a US$0.4 million non-cash underlift asset reflecting the combined year end liquids underlift position (2015: US$0.2 million overlift classified as a liability within trade and other payables.
Cash and cash equivalents decreased from US$21.6 million to US$16.6 million during the year. Operating cash inflows from net Erskine field sales were adversely impacted by the six-month field shut-in during which operating expenditure continued to be incurred. The Company also paid the second US$2.8 million tranche of Erskine consideration to BP and has significantly reduced other Erskine field liabilities in the year. Other cash outflows were incurred on E&E assets across the portfolio in the UK, Ireland and Namibia, ongoing administrative costs and corporate activity.
Short-term trade and other payables totalled US$5.9 million at 31 December 2016 (2015: US$9.6 million). This balance comprises capital and operational liabilities for the Erskine interest, which have been significantly reduced, the US$2.9 million (including accrued interest) third tranche of Erskine consideration payable to BP on 1 July 2017, and other creditors and accruals for E&E asset, corporate and administrative expenditure.
Provisions of US$2.2 million relate to an estimate for certain contingent payments related to savings in field operating costs that may be made to BP under the terms of the Erskine acquisition.
Long-term liabilities of US$2.9 million as at 31 December 2016 comprise the final tranche of Erskine consideration payable to BP on 1 July 2018.
Serica's share of estimated decommissioning costs relating to its 18% Erskine field interest will be met by BP up to a level of GBGBP31.3 million, adjusted for inflation, with Serica being responsible for any costs beyond that. No provision for decommissioning liabilities for the Erskine field is recorded at 31 December 2016 as the Company's current estimate for such costs is under the level to be funded by BP.
Cash balances and future commitments
Current cash position, capital expenditure commitments and other obligations
At 31 December 2016, the Group held cash and cash equivalents of US$16.6 million growing to US$25.7 million by 31 March 2017.
At 31 December 2016, the Group held put options covering Q1 2017 daily volumes of 750 barrels of oil and 40,000 therms per day (4,000 mscf/day) of gas at average floor prices of US$35 per barrel and 38 pence per therm.
In January 2017, the Group acquired gas put options covering Q2 and Q3 2017, and oil put options covering Q2 2017. Gas is covered for 40,000 therms a day at a 40p per therm floor throughout Q2 2017, and 38p per therm for an average of 31,000 therms a day for Q3. Q2 2017 oil cover is in place for 750 barrels a day at a US$50 per barrel floor.
Erskine field commitments
Net revenues from the Erskine field are expected to cover ongoing field expenditures as well as the two remaining tranches of US$2.8 million (before interest) cash consideration payable to BP on 1 July 2017 and 2018 respectively.
Management believe there are sufficient resources to meet the current committed programme for 2017 but remains conscious that a single field income stream exposes it to operational and infrastructure risks and the consequent need for adequate working capital to cover associated fluctuations in revenue. The field has a history of intermittent production performance prior to the remedial work undertaken and operational expenditure continues during periods of field shut-down when no revenue is earned.
Non-Erskine commitments
The Group has no significant exploration commitments.
Progress towards the Columbus development continues with a target to compile a Field Development Plan before the end of the year. Financing plans for the project will be worked in conjunction with the FDP submission.
Other
Asset values and Impairment
At 31 December 2016, Serica's market capitalisation stood at US$47.2 million (GBP38.2 million), based upon a share price of GBP0.145, which was exceeded by the net asset value at that date of US$85.1 million. By 4 April 2017 the Company's market capitalisation had increased to US$87.8 million (GBP70.5 million). Management has conducted a thorough review of the carrying value of the Group's assets and determined that no significant write-downs were required.
Business Risk and Uncertainties
Serica, like all companies in the oil and gas industry, operates in an environment subject to inherent risks and uncertainties. The Board regularly considers the principal risks to which the Group is exposed and monitors any agreed mitigating actions. The overall strategy for the protection of shareholder value against these risks is to retain a broad portfolio of assets with varied risk/reward profiles, to apply prudent industry practice in all operations, to carry insurance where available and cost effective, and to retain adequate working capital.
The principal risks currently recognised and the mitigating actions taken by the management are as follows:
Investment Returns: Management seeks to raise funds and then
to generate shareholder returns though investment in a portfolio
of exploration, development and producing acreage leading to
the discovery and exploitation of commercial reserves. Delivery
of this business model carries a number of key risks.
Risk Mitigation
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Market support may be eroded
obstructing fundraising and lowering * Management regularly communicates its strategy to
the share price shareholders
* Focus is placed on building an asset portfolio
capable of delivering regular news flow and offering
continuing prospectivity
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Management's decisions on capital
allocation may not deliver the * Rigorous analysis is conducted of all investment
expected successful outcomes proposals
* Operations are spread over a range of areas and risk
profiles
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Each asset carries its own risk
profile and no outcome can be * Management aims to avoid over-exposure to individual
certain assets and to identify the associated risks
objectively
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Operations: Operations may not go according to plan leading
to damage, pollution, cost overruns or poor outcomes.
Risk Mitigation
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The Group's income is currently
derived from a single producing * Efforts are underway to add to producing assets
field
* Management places a priority on building and
retaining sufficient working capital
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Individual wells may not deliver
recoverable oil and gas reserves * Thorough pre-drill evaluations are conducted to
identify the risk/reward balance
* Exposure is selectively mitigated through farm-out
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Wells may blow out or equipment
may fail causing environmental * The Group retains fully trained and experienced
damage and delays personnel
* The planning process involves risk identification and
establishment of mitigation measures
* Emphasis is placed on engaging experienced
contractors
* Appropriate insurances are retained
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Operations may take far longer
or cost more than expected * Management applies rigorous budget control
* Adequate working capital is retained to cover
reasonable eventualities
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Production may be interrupted
generating significant revenue * Business interruption cover will be considered when
loss appropriate
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Offtake routes may depend upon
a series of facilities and pipelines * The Group aims to diversify its sources of income
requiring a balance of throughput when suitable opportunities can be identified
from a number of different fields
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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
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Personnel: The Group relies upon a pool of experienced and
motivated personnel to identify and execute successful investment
strategies
Risks Mitigation
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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
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Personal safety may be at risk
in demanding operating environments, * A culture of safety is encouraged throughout the
typically offshore organisation
* Responsible personnel are designated at all
appropriate levels
* The Group maintains up-to-date emergency response
resources and procedures
* Insurance cover is carried in accordance with
industry best practice
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Staff and representatives may
find themselves exposed to bribery * Group policies and procedures are communicated to
and corrupt practices personnel regularly
* Management reviews all significant contracts and
relationships with agents and governments
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Commercial environment: World and regional markets continue
to be volatile with fluctuations and infrastructure access
issues that might hinder the Group's business success
Risk Mitigation
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Volatile commodity prices mean
that the Group cannot be certain * Budget planning considers a range of commodity prices
of the future sales value of
its products
* Price mitigation strategies may be employed at the
point of major capital commitment
* Gas may be sold under long-term contracts reducing
exposure to short term fluctuations
* Oil and gas price hedging contracts may be utilised
where viable
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The Group may not be able to
get access, at reasonable cost, * A range of different off-take options are pursued
to infrastructure and product wherever possible
markets when required
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Credit to support field development
programmes may not be available * Serica seeks to build and maintain strong banking
at reasonable cost relationships and initiates funding discussions at as
early a stage as practicable
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Fiscal regimes may vary, increasing
effective tax rates and reducing * Operations are currently spread over a range of
the expected value of reserves different fiscal regimes in Western Europe and Africa
* Before committing to a significant investment the
likelihood of fiscal term changes is considered when
evaluating the risk/reward balance
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In addition to the principal risks and uncertainties described herein, the Group is subject to a number of other risk factors generally, a description of which is set out in our latest annual information form available on www.sedar.com.
Key Performance Indicators ("KPIs")
The Company's main business is the acquisition of interests in prospective exploration acreage, the discovery of hydrocarbons in commercial quantities and the crystallisation of value whether through production or disposal of reserves. The Company tracks its non-financial performance through the accumulation of licence interests in proven and prospective hydrocarbon producing regions, the level of success in encountering hydrocarbons and the development of production facilities. In parallel, the Company tracks its financial performance through management of expenditures within resources available, the cost-effective exploitation of reserves and the crystallisation of value at the optimum point. A review of the Company's progress against these KPIs is covered in the operations and financial review within this Strategic Report.
Additional Information
Additional information relating to Serica, can be found on the Company's website at www.serica-energy.com and on SEDAR at www.sedar.com
The Strategic Report has been approved by the Board of Directors.
On behalf of the Board
Antony Craven Walker
Executive Chairman
5 April 2017
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
2016 2015
Note US$000 US$000
Continuing operations
Sales revenue 4 21,432 24,017
Cost of sales 5 (14,860) (7,934)
Gross profit 6,572 16,083
Other expense (113) -
Pre-licence costs (240) (117)
Impairment and write-offs of E&E assets 15 (62) (8,186)
Other asset write-offs 15 - (170)
Administrative expenses (2,062) (2,705)
Foreign exchange loss (556) (430)
Share-based payments 27 (90) 9
Operating profit before net finance revenue and tax 3,449 4,484
Finance revenue 11 61 38
Finance costs 12 (185) (202)
Profit before taxation 3,325 4,320
Taxation credit for the year 13a) 7,521 2,433
Profit for the year from continuing operations 10,846 6,753
--------- --------
Discontinued operations
Loss for the year from discontinued operations 7 (8) (264)
Profit for the year 10,838 6,489
========= ========
Earnings per ordinary share - EPS
Basic and diluted EPS on continuing operations (US$) 14 0.04 0.03
Basic and diluted EPS on profit for the year (US$) 14 0.04 0.03
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
2016 2015 2016 2015
Note US$000 US$000 US$000 US$000
Non-current assets
Exploration & evaluation assets 15 53,170 51,814 - -
Property, plant and equipment 16 9,078 8,894 - -
Investments in subsidiaries 17 - - 1,350 1,350
Deferred tax asset 13d) 9,954 2,433 - -
72,202 63,141 1,350 1,350
---------- ---------- ---------- ----------
Current assets
Inventories 18 401 453 - -
Trade and other receivables 19 6,849 4,165 70,141 59,635
Cash and cash equivalents 20 16,593 21,602 14,066 13,730
---------- ---------- ---------- ----------
23,843 26,220 84,207 73,365
---------- ---------- ---------- ----------
TOTAL ASSETS 96,045 89,361 85,557 74,715
---------- ---------- ---------- ----------
Current liabilities
Trade and other payables 21 (5,877) (9,573) (462) (548)
Non-current liabilities
Trade and other payables 22 (2,883) (5,621) - -
Provisions 23 (2,190) - - -
TOTAL LIABILITIES (10,950) (15,194) (462) (548)
---------- ---------- ---------- ----------
NET ASSETS 85,095 74,167 85,095 74,167
========== ========== ========== ==========
Share capital 25 229,308 229,308 194,036 194,036
Merger reserve 17 - - - -
Other reserve 20,715 20,625 20,715 20,625
Accumulated deficit (164,928) (175,766) (129,656) (140,494)
TOTAL EQUITY 85,095 74,167 85,095 74,167
========== ========== ========== ==========
The profit for the Company is US$10,838,000 for the year ended 31 December 2016 (2015: profit of US$6,489,000). 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 5 April 2017
Antony Craven Walker Neil Pike Executive Chairman Non-Executive Director ________________________________ _____________________________________
Serica Energy plc
Statement of Changes in Equity
For the year ended 31 December
Group Other Accum'd
Note Share capital reserve deficit Total
US$000 US$000 US$000 US$000
At 1 January 2015 227,958 20,634 (182,255) 66,337
Profit for the year - - 6,489 6,489
-------------- --------- ---------- -------
Total comprehensive income - - 6,489 6,489
Share-based payments 27 - (9) - (9)
Issue of ordinary shares 25 1,350 - - 1,350
At 31 December 2015 229,308 20,625 (175,766) 74,167
Profit for the year - - 10,838 10,838
-------
Total comprehensive income - - 10,838 10,838
Share-based payments 27 - 90 - 90
At 31 December 2016 229,308 20,715 (164,928) 85,095
============== ========= ========== =======
Other Accum'd
Company Share capital reserve deficit Total
US$000 US$000 US$000 US$000
At 1 January 2015 192,686 20,634 (146,983) 66,337
Profit for the year - - 6,489 6,489
-------------- --------- ---------- -------
Total comprehensive income - - 6,489 6,489
Share-based payments 27 - (9) - (9)
Issue of ordinary shares 25 1,350 - - 1,350
At 31 December 2015 194,036 20,625 (140,494) 74,167
Profit for the year - - 10,838 10,838
-------------- --------- ---------- -------
Total comprehensive income - - 10,838 10,838
Share-based payments 27 - 90 - 90
At 31 December 2016 194,036 20,715 (129,656) 85,095
============== ========= ========== =======
Serica Energy plc
Cash Flow Statement
For the year ended 31 December
Group Company
2016 2015 2016 2015
Note US$000 US$000 US$000 US$000
Operating activities:
Profit for the year 10,838 6,489 10,838 6,489
Adjustments to reconcile profit
for the year
to net cash flow from operating
activities:
Taxation credit (7,521) (2,433) - -
Net finance costs/(income) 124 164 (56) 53
Depreciation and depletion 1,274 1,341 - -
Oil and NGL overlift reduction (516) (3,407) - -
Other asset write-offs - 170 - -
Impairment and write-offs of E&E
assets 62 8,186 - -
Impairment of loans and investments - - (12,954) (8,043)
Share-based payments 90 (9) 90 (9)
Other non-cash movements 866 431 1,100 443
(Increase)/decrease in trade and
other (1,862) (2,137) (197) 273
receivables
Decrease/(increase) in inventories 52 (369) - -
Decrease in trade and other payables (3,270) (865) (109) (586)
Net cash in/(out)flow from operations 137 7,561 (1,288) (1,380)
-------- -------- --------- --------
Investing activities:
Interest received 61 11 61 10
Purchase of E&E assets (1,418) (3,957) - -
Cash (out)/inflow arising on asset
acquisition 16 (2,775) 8,874 - -
Funding provided from/(to) Group
subsidiaries - - 2,336 6,345
Net cash flow from investing activities (4,132) 4,928 2,397 6,355
-------- -------- --------- --------
Financing activities:
Gross proceeds from issue of shares 25 - - - -
Finance costs paid (77) (254) (5) (249)
Net cash flow from financing activities (77) (254) (5) (249)
-------- -------- --------- ----------
Net (decrease)/increase in cash
and cash equivalents 26 (4,072) 12,235 1,104 4,726
Effect of exchange rates on cash
and cash
equivalents 26 (937) (526) (768) (443)
Cash and cash equivalents at 1
January 26 21,602 9,893 13,730 9,447
Cash and cash equivalents at 31
December 26 16,593 21,602 14,066 13,730
======== ======== ========= ==========
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 2016 were authorised for issue by the Board of Directors on 5 April 2017 and the balance sheets were signed on the Board's behalf by Antony Craven Walker and Neil Pike. Serica Energy plc is a public limited company incorporated and domiciled in England & Wales with its registered office at 52 George Street, London, W1U 7EA. The principal activity of the Company and the Group is to identify, acquire and subsequently exploit oil and gas reserves. Its current activities are located in the United Kingdom, Ireland, Namibia and Morocco. 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 2016. 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 2016 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$10,838,000 (2015: profit US$6,489,000).
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 2016.
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 2016 the Company held net current assets of US$18.0 million including cash resources of US$16.6 million with no borrowings outstanding. The Erskine asset acquisition, completed in early June 2015 brought to Serica a producing interest capable of generating robust continuing cash flow at current oil and gas prices. Existing resources plus Erskine revenues are expected to be sufficient to cover ongoing Erskine costs and the outstanding instalments of the acquisition price plus other operational, technical and administrative costs in the short-to-medium term.
Mindful of the risks of reliance on revenues from a single field, which are underlined by the shutdown in 2016 caused by wax build-up, management will seek to continue building Group cash reserves so as to improve its financial resilience. The strategy is to restrict near-term spend on administrative costs and exploration licences, only committing to exploration drilling where the costs are substantially carried by third parties.
Management continues to seek new business opportunities to add shareholder value and, where these can offer attractive returns, appropriate financing structures will be investigated. When the final decision to proceed with the Columbus development is made, the Group would consider a range of alternative means of finance to fund its share of development costs.
After making enquiries and having taken into consideration the above factors, the Directors have reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future. Accordingly they continue to adopt the going concern basis in preparing the financial statements.
Use of judgement and estimates and key sources of estimation uncertainty
The preparation of financial statements in conformity with IFRS requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities as well as the disclosure of contingent assets and liabilities at the balance sheet date and the reported amounts of revenues and expenses during the reporting period. Estimates and judgements are continuously evaluated and are based on management's experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. Actual outcomes could differ from these estimates.
The key sources of estimation uncertainty that have a significant risk of causing material adjustment to the amounts recognised in the financial statements are: the assessment of commercial reserves, the impairment of the Group and Company's assets (including oil & gas development assets and Exploration and Evaluation "E&E" assets), and the recoverability of deferred tax assets.
Assessment of commercial reserves
Management is required to assess the level of the Group's commercial reserves together with the future expenditures to access those reserves, which are utilised in determining the amortisation and depletion charge for the period and assessing whether any impairment charge is required. The Group employs independent reserves specialists who periodically assess the Group's level of commercial reserves by reference to data sets including geological, geophysical and engineering data together with reports, presentation and financial information pertaining to the contractual and fiscal terms applicable to the Group's assets. In addition the Group undertakes its own assessment of commercial reserves and related future capital expenditure by reference to the same data sets using its own internal expertise. There has been no significant change to the management estimates and assumptions during the year that may impact the assessment of commercial reserves.
Assessment of the recoverable amount of intangible and tangible assets
The Group monitors internal and external indicators of impairment relating to its intangible and tangible assets, which may indicate that the carrying value of the assets may not be recoverable. The assessment of the existence of indicators of impairment in E&E assets involves judgement, which includes 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 17).
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 variables behind the increased deferred tax asset recognised in 2016 from 2015 are the increase in management's estimate of short-term forward commodity prices and production volumes from prior year. To the extent that future cash flows and taxable income differ significantly from estimates, the ability of the Group to realise deferred tax assets could be impacted.
Basis of Consolidation
The consolidated financial statements include the accounts of Serica Energy plc (the "Company") and its wholly owned subsidiaries Serica Holdings UK Limited, Serica Energy Holdings B.V., Serica Energy (UK) Limited, Serica Glagah Kambuna B.V., Serica Sidi Moussa B.V., Serica Foum Draa B.V., Serica Energy Slyne B.V., Serica Energy Rockall B.V., Serica Energy Namibia B.V., Serica Energy Corporation, Asia Petroleum Development Limited, Petroleum Development Associates (Asia) Limited and Petroleum Development Associates (Lematang) Limited. Together these comprise the "Group".
All inter-company balances and transactions have been eliminated upon consolidation.
Foreign Currency Translation
The functional and presentational currency of Serica Energy plc and all its subsidiaries is US dollars.
Transactions in foreign currencies are initially recorded at the functional currency rate ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated at the foreign currency rate of exchange ruling at the balance sheet date and differences are taken to the income statement. Non-monetary items that are measured in terms of historical cost in a foreign currency are translated using the exchange rate as at the date of initial transaction. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rate at the date when the fair value was determined. Exchange gains and losses arising from translation are charged to the income statement as an operating item.
Business Combinations and Goodwill
Business combinations from 1 January 2010
Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of consideration transferred, measured at acquisition date fair value and the amount of any non-controlling interest in the acquiree. Acquisition costs incurred are expensed and included in administrative expenses.
Goodwill on acquisition is initially measured at cost being the excess of purchase price over the fair market value of identifiable assets, liabilities and contingent liabilities acquired. Following initial acquisition it is measured at cost less any accumulated impairment losses. Goodwill is not amortised but is subject to an impairment test at least annually and more frequently if events or changes in circumstances indicate that the carrying value may be impaired.
At the acquisition date, any goodwill acquired is allocated to each of the cash-generating units, or groups of cash generating units expected to benefit from the combination's synergies. Impairment is determined by assessing the recoverable amount of the cash-generating unit, or groups of cash generating units to which the goodwill relates. Where the recoverable amount of the cash-generating unit is less than the carrying amount, an impairment loss is recognised.
Joint Arrangements
A joint operation is a type of joint arrangement whereby the parties that have joint control of the arrangement have the rights to the assets and obligations for the liabilities, relating to the arrangement.
The Group conducts petroleum and natural gas exploration and production activities jointly with other venturers who each have direct ownership in and jointly control the operations of the ventures. These are classified as jointly controlled operations and the financial statements reflect the Group's share of assets and liabilities in such activities. Income from the sale or use of the Group's share of the output of jointly controlled operations, and its share of joint venture expenses, are recognised when it is probable that the economic benefits associated with the transaction will flow to/from the Group and their amount can be measured reliably.
Full details of Serica's working interests in those petroleum and natural gas exploration and production activities classified as joint operations are included in the Review of Operations.
Exploration and Evaluation Assets
As allowed under IFRS 6 and in accordance with clarification issued by the International Financial Reporting Interpretations Committee, the Group has continued to apply its existing accounting policy to exploration and evaluation activity, subject to the specific requirements of IFRS 6. The Group will continue to monitor the application of these policies in light of expected future guidance on accounting for oil and gas activities.
Pre-licence Award Costs
Costs incurred prior to the award of oil and gas licences, concessions and other exploration rights are expensed in the income statement.
Exploration and Evaluation (E&E)
The costs of exploring for and evaluating oil and gas properties, including the costs of acquiring rights to explore, geological and geophysical studies, exploratory drilling and directly related overheads, are capitalised and classified as intangible E&E assets. These costs are directly attributed to regional CGUs for the purposes of impairment testing; UK & Ireland and Africa.
E&E assets are not amortised prior to the conclusion of appraisal activities but are assessed for impairment at an asset level and in regional CGUs when facts and circumstances suggest that the carrying amount of a regional cost centre may exceed its recoverable amount. Recoverable amounts are determined based upon risked potential, and where relevant, discovered oil and gas reserves. When an impairment test indicates an excess of carrying value compared to the recoverable amount, the carrying value of the regional CGU is written down to the recoverable amount in accordance with IAS 36. Such excess is expensed in the income statement. Where conditions giving rise to impairment subsequently reverse, the effect of the impairment charge is reversed as a credit to the income statement.
Costs of licences and associated E&E expenditure are expensed in the income statement if licences are relinquished, or if management do not expect to fund significant future expenditure in relation to the licence.
The E&E phase is completed when either the technical feasibility and commercial viability of extracting a mineral resource are demonstrable or no further prospectivity is recognised. At that point, if commercial reserves have been discovered, the carrying value of the relevant assets, net of any impairment write-down, is classified as an oil and gas property within property, plant and equipment, and tested for impairment. If commercial reserves have not been discovered then the costs of such assets will be written off.
Asset Purchases and Disposals
When a commercial transaction involves the exchange of E&E assets of similar size and characteristics, no fair value calculation is performed. The capitalised costs of the asset being sold are transferred to the asset being acquired. Proceeds from a part disposal of an E&E asset, including back-cost contributions are credited against the capitalised cost of the asset, with any excess being taken to the income statement as a gain on disposal.
Farm-ins
In accordance with industry practice, the Group does not record its share of costs that are 'carried' by third parties in relation to its farm-in agreements in the E&E phase. Similarly, while the Group has agreed to carry the costs of another party to a Joint Operating Agreement ("JOA") in order to earn additional equity, it records its paying interest that incorporates the additional contribution over its equity share.
Property, Plant and Equipment - Oil and gas properties
Capitalisation
Oil and gas properties are stated at cost, less any accumulated depreciation and accumulated impairment losses. Oil and gas properties are accumulated into single field cost centres and represent the cost of developing the commercial reserves and bringing them into production together with the E&E expenditures incurred in finding commercial reserves previously transferred from E&E assets as outlined in the policy above. The cost will include, for qualifying assets, borrowing costs.
Depletion
Oil and gas properties are not depleted until production commences. Costs relating to each single field cost centre are depleted on a unit of production method based on the commercial proved and probable reserves for that cost centre. The depletion calculation takes account of the estimated future costs of development of recognised proved and probable reserves. Changes in reserve quantities and cost estimates are recognised prospectively from the last reporting date.
Impairment
A review is performed for any indication that the value of the Group's development and production assets may be impaired.
For oil and gas properties when there are such indications, an impairment test is carried out on the cash generating unit. Each cash generating unit is identified in accordance with IAS 36. Serica's cash generating units are those assets which generate largely independent cash flows and are normally, but not always, single development or production areas. If necessary, impairment is charged through the income statement if the capitalised costs of the cash generating unit exceed the recoverable amount of the related commercial oil and gas reserves.
Acquisitions, Asset Purchases and Disposals
Acquisitions of oil and gas properties are accounted for under the acquisition method when the assets acquired and liabilities assumed constitute a business.
Transactions involving the purchase of an individual field interest, or a group of field interests, that do not constitute a business, are treated as asset purchases. Accordingly, no goodwill and no deferred tax gross up arises, and the consideration is allocated to the assets and liabilities purchased on an appropriate basis. Proceeds from the entire disposal of a development and production asset, or any part thereof, are taken to the income statement together with the requisite proportional net book value of the asset, or part thereof, being sold.
Decommissioning
Liabilities for decommissioning costs are recognised when the Group has an obligation to dismantle and remove a production, transportation or processing facility and to restore the site on which it is located. Liabilities may arise upon construction of such facilities, upon acquisition or through a subsequent change in legislation or regulations. The amount recognised is the estimated present value of future expenditure determined in accordance with local conditions and requirements. A corresponding tangible item of property, plant and equipment equivalent to the provision is also created.
Any changes in the present value of the estimated expenditure is added to or deducted from the cost of the assets to which it relates. The adjusted depreciable amount of the asset is then depreciated prospectively over its remaining useful life. The unwinding of the discount on the decommissioning provision is included as a finance cost.
Underlift/Overlift
Lifting arrangements for oil and gas produced in certain fields are such that each participant may not receive its share of the overall production in each period. The difference between cumulative entitlement and cumulative production less stock is 'underlift' or 'overlift'. Underlift and overlift are valued at market value and included within debtors ('underlift') or creditors ('overlift'). Movements during an accounting period are adjusted through revenue, such that gross profit is recognised on an entitlement basis.
Property, Plant and Equipment - Other
Computer equipment and fixtures, fittings and equipment are recorded at cost as tangible assets. The straight-line method of depreciation is used to depreciate the cost of these assets over their estimated useful lives. Computer equipment is depreciated over three years and fixtures, fittings and equipment over four years.
Inventories
Inventories are valued at the lower of cost and net realisable value. Cost is determined by the first-in first-out method and comprises direct purchase costs and transportation expenses.
Investments
In its separate financial statements the Company recognises its investments in subsidiaries at cost less any provision for impairment.
Financial Instruments
Financial instruments comprise financial assets, cash and cash equivalents, financial liabilities and equity instruments.
Financial assets
Financial assets within the scope of IAS 39 are classified as either financial assets at fair value through profit or loss, or loans and receivables, as appropriate. When financial assets are recognised initially, they are measured at fair value. Transaction costs that are directly attributable to the acquisition or issue of the financial asset are capitalised unless they relate to a financial asset classified at fair value through profit and loss in which case transaction costs are expensed in the income statement.
The Group determines the classification of its financial assets at initial recognition and, where allowed and appropriate, re-evaluates this designation at each financial year end.
Financial assets at fair value through profit or loss include financial assets held for trading and derivatives. Financial assets are classified as held for trading if they are acquired for the purpose of selling in the near term.
Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. After initial measurement loans and receivables are subsequently carried at amortised cost, using the effective interest rate method, less any allowance for impairment. Amortised cost is calculated by taking into account any discount or premium on acquisition over the period to maturity. Gains and losses are recognised in the income statement when the loans and receivables are de-recognised or impaired, as well as through the amortisation process.
Cash and cash equivalents
Cash and cash equivalents include balances with banks and short-term investments with original maturities of three months or less at the date acquired.
Financial liabilities
Financial liabilities include interest bearing loans and borrowings, and trade and other payables.
Obligations for loans and borrowings are recognised when the Group becomes party to the related contracts and are measured initially at the fair value of consideration received less directly attributable transaction costs.
After initial recognition, interest-bearing loans and borrowings are subsequently measured at amortised cost using the effective interest method.
Gains and losses are recognised in the income statement when the liabilities are derecognised as well as through the amortisation process.
Equity
Equity instruments issued by the Company are recorded in equity at the proceeds received, net of direct issue costs.
Provisions
Provisions are recognised when the Group has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.
The Group's fair value estimate in respect of contingent consideration that may be payable following the acquisition of its interest in the Erskine Field is capitalised as an asset acquisition cost. In determining fair value it is necessary to make a series of assumptions to estimate future operating costs and other variables. Accordingly, the fair value is categorised as Level 3 in the fair value hierarchy.
Leases
Operating lease payments are recognised as an operating expense in the income statement on a straight line basis over the lease term.
Revenue Recognition
Revenue is recognised to the extent that it is probable that the economic benefits will flow to the Group and the revenue can be reliably measured. Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for goods provided in the normal course of business, net of discounts, customs duties and sales taxes. Revenue from oil and natural gas production is recognised on an entitlement basis for the Group's net working interest.
Finance Revenue
Finance revenue chiefly comprises interest income from cash deposits on the basis of the effective interest rate method and is disclosed separately on the face of the income statement.
Finance Costs
Finance costs of debt are allocated to periods over the term of the related debt using the effective interest method. Arrangement fees and issue costs are amortised and charged to the income statement as finance costs over the term of the debt.
Share-Based Payment Transactions
Employees (including directors) of the Group receive remuneration in the form of share-based payment transactions, whereby employees render services in exchange for shares or rights over shares ('equity-settled transactions').
Equity-settled transactions
The cost of equity-settled transactions with employees is measured by reference to the fair value at the date on which they are granted. In valuing equity-settled transactions, no account is taken of any service or performance conditions, other than conditions linked to the price of the shares of Serica Energy plc ('market conditions'), if applicable.
The cost of equity-settled transactions is recognised, together with a corresponding increase in equity, over the period in which the relevant employees become fully entitled to the award (the 'vesting period'). The cumulative expense recognised for equity-settled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and the Group's best estimate of the number of equity instruments that will ultimately vest. The income statement charge or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period.
No expense is recognised for awards that do not ultimately vest, except for awards where vesting is conditional upon a market or non-vesting condition, which are treated as vesting irrespective of whether or not the market or non-vesting condition is satisfied, provided that all other performance conditions are satisfied. For equity awards cancelled by forfeiture when vesting conditions are not met, any expense previously recognised is reversed and recognised as a credit in the income statement. Equity awards cancelled are treated as vesting immediately on the date of cancellation, and any expense not recognised for the award at that date is recognised in the income statement. Estimated associated national insurance charges are expensed in the income statement on an accruals basis.
Where the terms of an equity-settled award are modified or a new award is designated as replacing a cancelled or settled award, the cost based on the original award terms continues to be recognised over the original vesting period. In addition, an expense is recognised over the remainder of the new vesting period for the incremental fair value of any modification, based on the difference between the fair value of the original award and the fair value of the modified award, both as measured on the date of the modification. No reduction is recognised if this difference is negative.
Income Taxes
Current tax, including UK corporation tax and overseas corporation tax, is provided at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted by the balance sheet date.
Deferred tax is provided using the liability method and tax rates and laws that have been enacted or substantively enacted at the balance sheet date. Provision is made for temporary differences at the balance sheet date between the tax bases of the assets and liabilities and their carrying amounts for financial reporting purposes. Deferred tax is provided on all temporary differences except for:
-- temporary differences associated with investments in subsidiaries, where the timing of the reversal of the temporary differences can be controlled by the Group and it is probable that the temporary differences will not reverse in the foreseeable future; and
-- temporary differences arising from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the income statement nor taxable profit or loss.
Deferred tax assets are recognised for all deductible temporary differences, to the extent that it is probable that taxable profits will be available against which the deductible temporary differences can be utilised. Deferred tax assets and liabilities are presented net only if there is a legally enforceable right to set off current tax assets against current tax liabilities and if the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority.
Earnings Per Share
Earnings per share is calculated using the weighted average number of ordinary shares outstanding during the period. Diluted earnings per share is calculated based on the weighted average number of ordinary shares outstanding during the period plus the weighted average number of shares that would be issued on the conversion of all relevant potentially dilutive shares to ordinary shares. It is assumed that any proceeds obtained on the exercise of any options and warrants would be used to purchase ordinary shares at the average price during the period. Where the impact of converted shares would be anti-dilutive, these are excluded from the calculation of diluted earnings.
New and amended standards and interpretations
The accounting policies adopted are consistent with those of the previous financial year, there are no new or amended standards or interpretations adopted during the year that have a significant impact on the financial statements.
Standards issued but not yet effective
Certain standards or interpretations issued but not yet effective up to the date of issuance of the Group's financial statements are listed below. This listing of standards and interpretations issued are those that the Group reasonably expects to have an impact on disclosures, financial position or performance when applied at a future date. The Group is currently assessing the impact of these standards and intends to adopt them when they become effective.
Standard Effective year commencing
on or after
IFRS 9 - Financial Instruments 1 January 2018
--------------------------
IFRS 15 - Revenue from Contracts with Customers 1 January 2018
--------------------------
IFRS 16 - Leases 1 January 2019 *
--------------------------
*Not yet endorsed by the EU
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR IAMMTMBIMTIR
(END) Dow Jones Newswires
April 06, 2017 02:00 ET (06:00 GMT)
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