Final Results

RNS Number : 4843E

Serica Energy plc

10 April 2014

 



Serica Energy plc

("Serica" or the "Company")

Results for the year ended 31 December 2013

London, 10 April 2014 - Serica Energy plc (TSX & AIM: SQZ) today announces its financial results for the year ended 31 December 2013.  The results are included below and copies are available at www.serica-energy.com and www.sedar.com.

Operations Highlights

•   Progress continues on all four of Serica's UK gas-centric projects

o   Centrica to carry Serica for 20% on Doyle well in Block 113/27c - Serica also received award of adjacent block 113/22a into which prospect likely extends

o   ENI joins as operator in block 22/19c where large HPHT prospects evident - Serica (15%) carried by JX Nippon through first well

o   3D Seismic acquired and processed in Greater York area - interpretation underway - Serica 37.5% interest

o   Export route for Columbus field under negotiation - commercial discussions continue with BG and others - infrastructure support from Wood Report and DECC

•   Atlantic Margin and Africa exploration moving forward on programme

o   Namibia - partnering process underway - huge benefit from BP's involvement in Luderitz Basin - c. US$50 million of high quality data at nil cost to Serica

o   Morocco - first Foum Draa well drilled, results non-commercial - first well in Sidi Moussa spuds early 2H2014 - Serica largely carried on both wells

o   Ireland - Ministry awards full Frontier Licence in Rockall Basin and extends Serica's existing licence - partnering process underway in Slyne Basin blocks

•   Competent Person's Report flags major potential in all of Serica's licences - highlights in Operations Review

•   Operator of Bream has indicated end year development decision - would provide a large uplift in value to Serica

Financial Highlights:

•   Funded to meet planned expenditure through end 2015

•   End year cash balance of US$26.1 million, nil debt

•   Successful fundraise of US$19.5 million - well supported by new and existing shareholders

•   Reduced loss for the year from continuing operations of US$5.1 million (2012: US$16.4 million)

•   Efficiencies improved - costs strictly controlled - all major commitments farmed-out

Tony Craven Walker, Serica's Chairman commented:

"The Company is rich in prospects, as is clear from the results of the Competent Person's independent Report of prospective resources, and we have secured our position in these prospects at minimal cost due to the success of our farm-out programme.

In the UK, we are pleased to welcome ENI into our block 22/19c where we are also carried and where we see very material, high impact potential.  ENI brings world class expertise in HPHT projects which have also received encouragement in the Chancellor's recent budget.  In Namibia, we benefitted from over US$50 million spent by BP and are engaged in a farm-out process to deliver an exploration well.  In Morocco, we look forward to drilling our second well where we are carried by Genel for the bulk of our drilling costs.

The Company's share price, in common with many small resource companies, has continued to decline.  Although 2013 produced unexpected challenges, particularly with BG's cancellation of the Bridge Linked Platform, we have actually been able to move the bulk of our projects forward and ended the year in a strong position.  Our main challenge remains to resolve the conundrum of an export route for Columbus but we have options and are receiving support.  We successfully strengthened our financial position with a US$19.5 million fundraising in November and I am confident that we have the skills and resources to capitalise on the wide variety of opportunities open to us."     

Enquiries:

Serica Energy plc
Tony Craven Walker, Chairman & CEO	[e-mail]	[phone]
Mitch Flegg, COO Chris Hearne, CFO	[e-mail] [e-mail]	[phone] [phone]
Peel Hunt
Richard Crichton	[e-mail]	[phone]
Charles Batten	[e-mail]	[phone]
RBC Capital Markets
Matthew Coakes	[e-mail]	[phone]
Daniel Conti Instinctif Partners	[e-mail]	[phone]
David Simonson	[e-mail]	[phone]
Catherine Wickman	[e-mail]	[phone]

NOTES TO EDITORS

Serica Energy was formed in 2004 and, since then, has drilled 20 wells in locations as diverse as the UK Offshore, the Atlantic margin offshore Ireland, offshore Indonesia (North West Sumatra, East Kalimantan and Java) and offshore Vietnam.  Seventeen of these wells were drilled by the Company as Operator, fourteen of the wells encountered oil or gas and six of these were commercial.  The first of the commercial discoveries, the Kambuna field in North West Sumatra, was developed by the Company.  The second, the Columbus field in the UK North Sea, is now in the pre-development stage with final project sanction pending. The Company also has a residual economic interest in the Bream oil field offshore Norway, which will be crystallised when the field is developed, and licence interests offshore Ireland, Morocco and Namibia.  Further information on the Company can be found at www.serica-energy.com.

The technical information contained in the announcement has been reviewed and approved by Mitch Flegg, Chief Operating Officer of Serica Energy plc. Mitch Flegg (BSc in Physics from Birmingham University) has 31 years of experience in oil & gas exploration and development and is a member of the Society of Petroleum Engineers (SPE) and the Petroleum Exploration Society of Great Britain (PESGB).

The Company is listed on both the Toronto Stock Exchange and the London AIM under the ticker SQZ. 

To receive Company news releases via email, please contact [e-mail] and specify "Serica press releases" in the subject line.

FORWARD LOOKING STATEMENTS

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

CHAIRMAN'S STATEMENT

Dear Shareholder

I am pleased to report that the Company made good progress during 2013 to advance its exploration programme, both in the UK and overseas.  We now have an enviable portfolio of rapidly maturing and ready to drill prospects, some of which are already farmed-out, providing shareholders with exposure to material upside, both near and longer term, at very little cost.   An independent report undertaken by Netherland Sewell and Associates has confirmed the range and potential of the Company's prospect inventory and more details are provided in the Chief Operating Officer's Review.  The report also includes the year-end audit of reserves and confirms the Columbus reserves at 15.5 mmboe, 5.2 mmboe net to Serica's interest. Work has continued in our efforts to find alternative arrangements for Columbus production.

Towards the year end, we were able to complete a capital financing in difficult market conditions to place us in a healthy financial position to take us forward.  I am pleased with the result and am delighted with the support that we received from shareholders to make this financing so successful.

The Company's main challenge going forward is to secure an export route for Columbus and no effort is being spared by the Board to this end.  We have striven hard to achieve this objective and have been in continual discussions with the Lomond field operator throughout the past few months but we have yet to reach a satisfactory conclusion.  As I have said previously there are no technical impediments to connecting Columbus to the adjacent Lomond platform.  We have, nevertheless, extended discussions to other operators who can also take the gas and liquids.  I give further commentary below but we will report back to shareholders as soon as we have demonstrable progress.

UK Exploration and Norway

Our UK exploration programme has seen material progress.  During the year we reached agreement with Centrica which will see a well drilled on our Doyle prospect in the East Irish Sea at limited cost to Serica.  Centrica are meeting the costs of our retained 20% interest up to a gross well expenditure of £11 million and they have confirmed that the well will be drilled as part of their forward programme with spud now likely early next year.  With the prospect lying close to the Morecambe Bay production facilities, also operated by Centrica, it is expected that any discovery would see early development.

Progress towards drilling on Block 22/19c, located just to the west of Columbus, is encouraging.  Our partner, JX Nippon, has confirmed that it has reached agreement under which ENI will be joining the group. The block contains two large high-pressure, high-temperature ("HPHT") prospects. The prospective resources independently attributed to these two prospects are considerable.  Under an earlier farm-out agreement with JX Nippon, Serica will be fully carried for its 15% share of the cost of drilling a well, providing shareholders with exposure to significant potential at no cost.  In addition, the Government has announced that it will introduce specific tax changes to encourage development of HPHT fields.  Serica is well placed to benefit from these changes.

In the Southern gas basin, our work programme to shoot a 3D seismic survey in the blocks adjacent to the producing York field has been completed and the data has now been fully processed and is being interpreted.  Serica has a 37.5% interest in these blocks and we are expecting results to show additional gas accumulations and support a drilling programme.

In short, in addition to Columbus, Serica is involved in three active gas-focussed exploration projects in the UK, each of which has clearly defined potential and in two of which it is carried by third parties.  With the current tight gas supply and security uncertainties we believe that gas prices will continue to be strong for the foreseeable future and encourage development of new reserves.

In Norway, we await the announcement of an investment decision for Bream.  This has been stated recently by the operator to be around the end of 2014/early 2015.  At the time of such an announcement the Company would expect to see a material increase in the value of its indirect holding in the field and we look forward to this project finally moving ahead.

Atlantic Margin Exploration

We also continue to make progress in our Atlantic Margin blocks.  In Namibia, we have benefitted from BP's participation in the acquisition and interpretation of the large 3D seismic survey which we undertook in 2012 and completed during 2013.  Although, following the conclusion of a portfolio review, BP decided not to build on its foothold in Namibia and is pulling back to other areas in which it has a larger presence, its valuable contribution has enabled Serica to prove the presence of very large structures with clear characteristics of potentially prolific carbonate deposits as well as highlighting shallower clastic accumulations likely to have been exposed to regionally present mature oil source rocks.  This has all been achieved at no cost to Serica, and has not only accelerated exploration, but has put us in a stronger position than at the time of the licence award just over two years ago.  We are now in the partnering process to take the licence to the next stage and are very positive about the blocks' potential.

In Morocco, we drilled our first well towards the end of the year, operated by Cairn Energy who also paid the bulk of the drilling costs related to our retained 8.33% working interest.  The well, drilled in the Foum Draa licence, did not encounter commercial hydrocarbons, but the cost to Serica was minimised as the result of our farm-out and does not write off the block's potential.  Our Moroccan activities continue with the drilling of our second well in which our costs are largely met, in this case by Genel in the Sidi Moussa block where we have a retained 5% working interest.  The well is expected to be drilled in the third quarter 2014 and would have a material impact on Serica, at minimal exposure, if successful.

Our activities in Ireland continue to be focussed on partnering efforts.  Our blocks offer well-defined prospects close to existing oil and gas discoveries, one of which, the Bandon oil discovery, was drilled by Serica.   We are seeing signs of increasing industry interest, but there has been only limited farm-out activity in the area to date.  We believe that this will change as the strategic benefits of discoveries which can improve energy security in Western Europe become more apparent.

Columbus

Returning to Columbus, Serica is not alone in facing problems gaining access to infrastructure.  The fact that it has taken us and our partners eight years of investment and endeavour to gain access to infrastructure, and we still have not been able to reach agreement with the major companies who operate the platform and pipeline systems, has sent a strong message to the UK Government that regulatory and oversight processes have got to be strengthened if the North Sea's potential is going to be fully exploited.  The Wood Report, which was commissioned by the Government to investigate the problem and published in February 2014, supports the case for change.  It is hard-hitting in its findings and requires existing infrastructure operators to collaborate fully to make infrastructure available to smaller companies.

We welcome and fully support the findings of the Wood Report.  The mature, developed areas offshore UK still hold significant undeveloped reserves and reserves remaining in existing fields and it will be the smaller companies who will play a pivotal role in finding and developing these reserves.  Preventing these companies from accessing existing infrastructure damages investor confidence, prevents new, emerging companies from flourishing, holds back entrepreneurial and technical expertise and, ultimately, results in a loss to the nation of the long term value of its reserves and their strategic value.  We are, therefore, starting to press the findings of the Wood Report as well as continuing discussions with other operators.  We are committed to seeing the development of Columbus take place.  With renewed Government emphasis to tackle the industry needs we believe these problems of infrastructure access and appropriate taxation policies will be resolved.

Finances

In November 2013 the Board took steps to strengthen the Company's financial position.  The Company completed a capital financing in difficult market conditions, raising a gross US$19.5 million. The Board recognises and is grateful for the support received from both existing and new shareholders who participated in the financing. The funds raised will underpin the growth of the business in 2014 and beyond and help to secure the full potential of the Group's assets and to ultimately maximise value for shareholders.

Our finances are also strengthened by our zero debt position.  The Group is debt free and the year-end net cash balance of US$26.1 million, coupled with the benefits of the Group's farm-out efforts in recent years, and control of overhead costs, is sufficient to meet the Group's contractual commitments and current projected cash requirements to the end of 2015.

Forward prospects

Although regulatory processes, increasing costs, overly complex taxation and maturing infrastructure have conspired to make it difficult to operate efficiently in the North Sea it is believed that the Government has recognised the need to alleviate the problem.  The Wood report is a major step in this direction and comes at a time when the UK needs to encourage development of its remaining gas reserves and extend the life of its offshore infrastructure.  We therefore expect matters to improve.  At the same time we are seeing the larger oil companies refocussing their business strategies which provides new opportunities for the smaller E&P companies to expand and diversify through increased M&A activity.

It is our firm belief that Serica has the skills and resources to pursue such opportunities.  We believe that 2014 will see progress across the Company's areas of operations as well as the pursuit of new opportunities both in the UK and overseas.  The November financing has put Serica in a good position to achieve these objectives and, with our portfolio of prospects rich with potential and a lean but strong and experienced management team, we are continually looking to opportunities and synergies both to expand and to unlock the value of our business.

Although we have made good progress on the exploration front, 2013 has been challenging and I would like to thank all of our employees for their continued hard work during the year and shareholders for their patience.  We shall be providing shareholders with an update of the Company's activities at the forthcoming Annual General Meeting to be held on 26 June 2014 when I would hope to be able to report on further progress. 

Tony Craven Walker

Chairman

9 April 2014

STRATEGIC REPORT

The following Strategic Report of the operations and financial results of Serica Energy plc and its subsidiaries (the "Group") should be read in conjunction with Serica's consolidated financial statements for the year ended 31 December 2013. 

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 a "designated foreign issuer" as that term is defined under National Instrument 71-102 - Continuous Disclosure and Other Exemptions Relating to Foreign Issuers. The Company is subject to the foreign regulatory requirements of the Alternative Investment Market of the London Stock Exchange in the United Kingdom.

Serica is an oil and gas company with exploration and development activities based in the UK, Ireland, Namibia and Morocco, and an economic interest in an oilfield offshore Norway. The Company's interest in the Kambuna field in Indonesia was formally terminated on 31 December 2013.

CHIEF OPERATING OFFICER'S REVIEW

UK Operations

Columbus Development

BG's unexpected decision to cancel the Lomond Bridge Linked Platform ("BLP") project in early 2013 was a major setback for the Columbus project.  The focus of the technical work for the rest of the year was switched to identifying and securing a new offtake route for Columbus.  The preferred technical solution is for a direct subsea tie-back to the existing Lomond facilities which are less than 8km away from Columbus.  Technical work has shown that this solution is feasible and that the capital expenditure required is appropriate for a development of this size.  The obstacle has been to agree commercial terms for the transportation and processing of Columbus production on the Lomond platform.  Progress has been slow although dialogue is continuing with BG International Limited (the operator of the Lomond infrastructure), the Department of Energy and Climate Change ("DECC") and other stakeholders in the area.

If access to the Lomond offtake route cannot be secured on acceptable terms then there are other realistic alternative offtake routes that are currently under consideration.  Technical work has commenced on these alternatives and approaches have been made to the relevant operators.

Against this background, continuing cost rises in the North Sea are also eroding development economics and both we and the other operators in the area are conscious of the need for close co-operation, highlighted by the DECC sponsored Wood Report, to reduce cost and maintain efficiencies.  The Government has recognised the need to assist in these objectives as well as to ensure that there are no taxation impediments holding back development

In December 2013, DECC granted a two year extension to the licence which includes the 23/16f portion of the Columbus field.  This extension shows the understanding and commitment of DECC to support our efforts and allows time for the Columbus partners to secure a commercially viable offtake route for the field.

Exploration

In the East Irish Sea, a site survey in Block 113/27c was completed during the year in preparation for drilling the Doyle Triassic gas prospect.  Under an agreement with Centrica's subsidiary Hydrocarbon Resources Limited ("HRL") for the farm-out of Blocks 113/26b and 27c, HRL are paying Serica's share of costs associated with the drilling of an exploration well to test Doyle up to a gross cap of £11 million in return for a 45% interest in the licence.  The site survey was therefore performed at no cost to Serica.  HRL, as designated operator, has confirmed that the well will be spudded early in their next drilling campaign and that they are about to go to tender for a suitable rig.

In November 2013, we were delighted to be awarded a 35% operated interest in Block 113/22a which is adjacent to Block 113/27c and is believed to contain an extension to the Doyle prospect.  The award was made as part of the delayed UK 27^th Offshore Licensing Round.  Work commitments include obtaining 150 kilometres of 2D seismic data and a drill or drop decision on a well within 3 years.

The farm-out agreement with HRL covers all of Blocks 113/26b, 113/27c and 113/22a.  Upon completion of the farm-out HRL will take over formally as operator with Serica retaining a 20% interest.

In the Central North Sea, Serica has a 15% interest in Block 22/19c, located two blocks to the west of Columbus.  As the result of a farm-out to JX Nippon, who took over as operator, Serica has a full carry on this licence up to and including the drilling of an exploration well.  The decision to drill this well lies with JX Nippon.  However, JX Nippon have recently advised us that they have reached agreement with ENI to join the block and we expect this will lead to an accelerated programme.  The group has identified significant deep High Pressure High Temperature ("HPHT") potential in the Jurassic and Triassic. A Competent Person's Report ("CPR") conducted by Netherland, Sewell & Associates, Inc ("NSAI") and commissioned by Serica, has assessed the highest ranked prospect to contain between a P₉₀ of 40mmboe and a P₁₀ of 243mmboe of unrisked prospective gross resources.   A site survey is expected to be acquired in 2014 in preparation for drilling an exploration well.

In the Southern North Sea a new 3D seismic survey was acquired over part of the Greater York area blocks operated by Centrica in which Serica has a 37.5% interest.  This survey was acquired on schedule and under budget and has now been fully processed.  Interpretation of the newly acquired data is ongoing with the aim of selecting the location for an exploration well.

Namibia

In Namibia the main focus during 2013 was the processing and interpretation of the 3D seismic survey that was acquired by Serica over our Luderitz blocks in 2012. The interpretation of the seismic, which covered approximately 25% of the licence area and focussed on Prospect B, is now complete and has confirmed that our primary prospect (Prospect B) exhibits the characteristics of a very large carbonate platform.

An independent assessment of the unrisked prospective resources contained in our Namibian licence has been performed by NSAI and covers prospects which have been mapped from early 2D seismic as well as the highly detailed 3D.  This CPR recognises the multi-prospect nature of the licence and states that Prospect B at the primary Barremian level alone contains P₅₀ unrisked prospective recoverable oil resources of 623 million barrels (with a P₉₀ to P₁₀ range of 138 million to 2.81 billion barrels). The report gives a geological risk factor of 16%.

In addition to the large Lower Cretaceous carbonate prospects evident on the licence the seismic also confirms the presence of large turbidite channel sand formations.  These sands are likely to have been sourced by regionally present mature oil source rocks and therefore present valid and attractive targets.

The costs associated with the acquisition and processing of the 3D seismic survey were fully paid by BP as part of their 2012 farm in agreement.  At the end of 2013 BP decided to refocus its international portfolio and elected to withdraw from the licence.  Serica now holds 85% of the equity in the licence but retains the 3D seismic data which cost almost US$50million to acquire and process.  We have now commenced a process to attract one or more new partners to enter into a Joint Venture arrangement with us with the aim of drilling the first exploration well in 2015.  The initial level of industry interest in this opportunity has been strong and discussions continue.

Morocco

In April, a site survey was carried out by Cairn Energy in preparation for drilling the FD-1 well on our Foum Draa licence in Morocco.  The well was spudded in October using the fifth generation semi-submersible drilling rig Cajun Express.  This was a deepwater well drilled in over 1,500m of water and to a total depth of 5,255m.  Drilling operations finished in early January 2014.  The well failed to find commercial hydrocarbons but did encounter gas shows indicating an active thermogenic petroleum system.  In line with our ongoing strategy of limiting our cost exposure, the first US$60million of the gross drilling costs for this well were paid by Cairn, our farm-in partner, minimising the net cost to Serica's retained 8.33% working interest.  The group is now evaluating the valuable data recovered from the well and will soon agree on a forward plan for the licence.

The next Moroccan well in which we have an involvement will be in the Sidi Moussa licence which is now operated by Genel Energy.  Once again our cost exposure is limited under a farm-out agreement and Genel will carry Serica's retained 5% working interest for the first US$50million of gross well costs, therefore considerably limiting our cost exposure.  The site survey has been completed and the rig Noble Paul Romano has been contracted to drill the well which is expected to spud in Q3 2014.  This prospect is a carbonate draped tilted fault block structure that the operator Genel estimates to hold prospective resources of 200 million barrels with a 20% chance of success.

Ireland

Serica holds 100% interests in two large swathes of blocks in the Atlantic Margin Rockall Basin and has undertaken considerable work reprocessing 2D and 3D seismic data to delineate fully the prospectivity of these blocks.  This work has identified large prospects of pre-Cretaceous age close to an existing discovery drilled off block.

In July 2013 we were pleased to be informed that the Minister of State at the Department of Communications, Energy and Natural Resources ("DCENR") had consented to extend the original four year duration of Serica's Rockall Basin Frontier Exploration Licence 01/09 by two years to enable further work to be done on the licence, including a possible site survey.

This was followed in December 2013, when we were advised that we had been successful in our application to convert adjacent Licence Option 11/1 to a full Frontier Exploration Licence and that the Minister of State at the DCENR has granted Frontier Exploration Licence number 04/13 with effect from 1 December 2013.

This places us in a stronger position to attract industry partners as the attractiveness of the technical potential and the licence terms become better understood.  Given the size of the prospects and their position in a proven gas-condensate bearing basin, holding two licences with significant acreage (over 1,900 square kilometres) greatly expands the options open to Serica to deliver an active drilling campaign in the area.  The NSAI CPR attributes P₅₀ unrisked prospective resources of 677bcf (with a range from a P₉₀ of 155bcf to a P₁₀ of 3.4tcf) to the Muckish prospect with a geological risk factor of 26%.

In addition to the clearly mapped prospects, recent in-house analysis of the extensive seismic database has also indicated the presence of an alternative play type, not previously considered and it is evident that the blocks contain the potential for deepwater fans.  Evaluation of this play has commenced and will be completed in Q2 2014.   

Further south in the Slyne Basin, we have two significant drill-ready prospects in Licence 01/06, the Boyne and the Liffey prospects.  The blocks are located 40 kilometres south of the Corrib gas field in water depths of 180 to 280 metres.  Boyne and Liffey are two Lower Jurassic prospects mapped as a result of the discovery of oil in shallower Jurassic sediments in the Bandon well drilled by Serica in 2009.  NSAI in their CPR attribute P₅₀ gross unrisked prospective resources (for the combined Jurassic and Triassic objectives in Boyne and Liffey) of 215mmboe (with a range from a P₉₀ of 56mmboe to a P₁₀ of 824mmboe).   Together with our partner (RWE), we are looking for a further partner to invest in an exploration well to drill the Boyne Prospect in return for significant equity in the licence. This is a high value farm-in opportunity with moderate risk and significant upside.

Indonesia

Finally, during 2013 the Kambuna Field in Indonesia reached the end of its economic life. The field has been abandoned in accordance with local regulations and the Technical Assistance Contract (TAC) with Pertamina was terminated in December 2013. The abandonment and handover operations were completed smoothly and within budget.

Mitch Flegg

Chief Operating Officer

9 April 2014

REVIEW OF LICENCE HOLDINGS

The following table summarises the Company's licences as at 31 December 2013.

Block(s)	Description	Role	% at	Location
			31/12/13
UK
15/21g	Exploration	Non-operator	21%	Central North Sea
15/21a (part)	Exploration	Non-operator	21%	Central North Sea
22/19c	Exploration	Non-operator	15%	Central North Sea
23/16f	Columbus Field - Development planned	Operator	50%	Central North Sea
47/2b (split)	Exploration	Non-operator	37.5%	Southern North Sea
47/3g (split)	Exploration	Non-operator	37.5%	Southern North Sea
47/7 (split)	Exploration	Non-operator	37.5%	Southern North Sea
47/8d (part)	Exploration	Non-operator	37.5%	Southern North Sea
110/8b	Exploration	Operator	100%	East Irish Sea
113/26b	Exploration	Operator (1)	65% (1)	East Irish Sea
113/27c	Exploration	Operator (1)	65% (1)	East Irish Sea
113/22a	Exploration	Operator (1)	35% (1)	East Irish Sea
Ireland
27/4	Exploration	Operator	50%	Slyne Basin
27/5 (part)	Exploration	Operator	50%	Slyne Basin
27/9	Exploration	Operator	50%	Slyne Basin
5/17	Exploration	Operator	100%	Rockall Basin
5/18	Exploration	Operator	100%	Rockall Basin
5/22	Exploration	Operator	100%	Rockall Basin
5/23	Exploration	Operator	100%	Rockall Basin
5/27	Exploration	Operator	100%	Rockall Basin
5/28	Exploration	Operator	100%	Rockall Basin
11/10	Exploration	Operator	100%	Rockall Basin
11/15	Exploration	Operator	100%	Rockall Basin
12/1 (part)	Exploration	Operator	100%	Rockall Basin
12/6	Exploration	Operator	100%	Rockall Basin
12/11 (part)	Exploration	Operator	100%	Rockall Basin
Namibia
2512A	Exploration	Operator	85%	Luderitz Basin
2513A	Exploration	Operator	85%	Luderitz Basin
2513B	Exploration	Operator	85%	Luderitz Basin
2612A (part)	Exploration	Operator	85%	Luderitz Basin
Morocco
Foum Draa	Exploration	Non-operator	8.3333%	Tarfaya-Ifni Basin
Sidi Moussa	Exploration	Non-operator	5%	Tarfaya-Ifni Basin
Indonesia
Glagah Kambuna TAC	Kambuna Field Production	Non-operator	25% (2)	Offshore North Sumatra

Notes:

(1)        Interest subject to a farm-out agreement.  Post completion, Serica's interest will be 20% and Hydrocarbon Resources Limited (a wholly owned subsidiary of Centrica) will be appointed operator.

(2)        Glagah Kambuna TAC terminated on 31 December 2013.

The following summary gives further detailed information on Serica's licence interests in which activities took place during, and subsequent to the end of 2013.

United Kingdom

Central North Sea: Block 23/16f - Columbus Field Development

Block 23/16f covers an area of approximately 22 square kilometres in the UK Central North Sea and contains the majority of the Columbus gas field. The Columbus field, containing gas rich in condensate, extends from Block 23/16f into Block 23/21 to the south, operated by BG International Limited ("BG"). Block 23/21 includes the Lomond platform and the producing Lomond field. Serica has a 50% interest as operator in Block 23/16f and will be the operator for Columbus field facilities with an interest of 33.2%.

In early March 2013 Serica, as operator of the Columbus field and on behalf of the Columbus field participants, issued tender documents to pre-qualifying contractors for the fabrication, installation and hook-up of sub-sea facilities and the provision of associated sub-sea equipment and systems. This followed the issuing by BG in December 2012 of tender documents for the construction and installation of a Bridge Linked Platform ("BLP"), through which Columbus field gas and condensate production would be exported.

In late March 2013, BG informed Serica that it had decided not to proceed with the construction of the BLP. This cancellation was a setback to the Columbus project but since then, progress has been made towards a revised development plan under which the Columbus field would be tied back directly to the Lomond platform without need for a BLP. Preliminary engineering studies showed that this solution is technically feasible and could be delivered within the time frame envisaged under the previous BLP-based plan.

The outstanding issue to be addressed before detailed technical work can proceed is for (non-binding) commercial terms to be agreed between the Columbus owners and the Lomond owner. Negotiations are continuing with BG, DECC and other interested parties with all parties working to secure a positive outcome following which clearances will be required from DECC enabling the project to proceed.  Serica is aiming to reach an understanding acceptable to all parties during the first half of 2014. The original field development plan, as submitted to DECC, was designed to evaluate the potential for additional reserves which may exist as an extension to Columbus and this would remain the intention in any revised plan designed to take account of a modified export route.

The partners in Block 23/16f recently obtained a two year extension from DECC for the second phase of the licence (P1314), which now expires in December 2015. This cooperation from DECC is indicative of their support to help reach a positive conclusion and extends the timeframe to achieve agreement for an export route. As part of this process, the part of the block east of the Columbus accumulation has been relinquished such that the portion retained, which contains the Columbus field, has an area of 22 square kilometres.

Lomond is the nearest and easiest platform for Columbus to link into and remains the prime choice for cost and simplicity reasons.  However, in addition to negotiations with BG discussions have also been opened up with other infrastructure operators who can provide alternatives in the event that negotiations with BG fail to reach a commercial conclusion.

Independent consultant NSAI carried out a reserves report on the Columbus field for the end of 2013.  This report estimated that the gross Proved plus Probable Reserves of the field are 66.0 bcf of gas and 4.5 mmbbl of liquids, a total of 15.5 mmboe. Serica holds a 50% interest in those Columbus reserves lying in Block 23/16f. After providing for reserves lying in the adjacent Block, NSAI estimates the Company's share of proved and probable reserves in the field to be 21.9 bcf of sales gas and 1.5 mmbbl of liquids, a net 5.2 mmboe to Serica.

Central North Sea: Block 15/21g and 15/21a (part) - Spaniards Appraisal

Block 15/21g, in which Serica was initially awarded a 30% interest, lies immediately west of the Scott oil field and adjacent to Block 15/21a containing the Jurassic oil discovery well 15/21-38z ("Spaniards"), which flowed 2,660 bpd of 25° API oil from a good quality Jurassic-aged Upper Claymore sand. In January 2012 Block 15/21g was amalgamated with part of Block 15/21a to form a single area which includes the Spaniards discovery. Serica has a 21% interest in the amalgamated area.

In Q4 2012 the Spaniards East well was drilled to appraise the Spaniards discovery but was plugged and abandoned. The analysis of the Spaniards East well data confirms that there is little chance of any remaining oil prospectivity in the east of the field. The focus of the forward work programme is to mature the Spaniards West prospect so that a decision can be made whether to drill another well or withdraw from the licence.

Central North Sea: Block 22/19c

Block 22/19c is located approximately 20 kilometres to the west of Serica's Columbus field. Following the farm-out of an 85% interest to JX Nippon in 2012, Serica has a 15% interest in the block and has a full carry on this licence up to and including the drilling of an exploration well.  The partners have identified significant deep HPHT potential in the Jurassic and Triassic on the block and a site survey is expected to be acquired in 2014 in preparation for drilling an exploration well. 

JX Nippon has recently executed an agreement with ENI for the latter to join the block as operator with a 50% interest. The transaction between JX Nippon and ENI is subject to normal regulatory and partner approvals. Serica expects that the transaction will lead to an accelerated programme.

Southern North Sea: Blocks 47/2b (Split), 47/3g (Split), 47/7 (Split) & 47/8d (Part)

Serica has a 37.5% interest in the blocks which are operated by Centrica.  These blocks are contiguous part blocks immediately adjacent to the producing York field, also operated by Centrica.

A number of gas prospects, including a possible extension to the York field, have been identified on the blocks at Leman (Permian) level with additional leads at Namurian (Carboniferous) level. The work obligation, comprising a 3D seismic acquisition survey and reprocessing of existing seismic data, has been completed. 

East Irish Sea: Block 110/8b

Serica has a 100% interest and operatorship of Block 110/8b.  Recent drilling by Centrica in the adjoining block to the north is likely to have investigated prospectivity for gas in the area of the Darwen North prospect lying in the north of Block 110/8b but results of the drilling have not been released.

East Irish Sea: Blocks 113/26b and 113/27c - Doyle Prospect

In June 2013 the Company announced that it had reached agreement with Centrica, through Centrica's subsidiary HRL, for the farm-out of UK East Irish Sea Blocks 113/26b and 27c, in which Serica presently holds a 65% interest.  Under the agreement, HRL will acquire an operated 45% interest in the licence, with Serica retaining 20%, in consideration for HRL bearing Serica's share of costs associated with the drilling of an exploration well up to a gross cap of £11 million.

The agreement is subject to UK government approval. Completion also requires agreement with the operator of a wind farm planned nearby.  However this is now at an advanced stage with final agreement expected shortly.

A Triassic gas prospect, the Doyle prospect, lies in the north of Block 113/27c.  A fault and dip closed structure, this prospect has been fully matured and is ready to drill.  The site survey has been completed and the well is expected to be drilled in early 2015. 

East Irish Sea: Block 113/22a

In November 2013 Serica was awarded a Traditional Licence in the latest stage of the 27th Offshore Licensing Round, announced by DECC.  Block 113/22a in the East Irish Sea has been awarded to a group in which Serica has a 35% interest and is operator.  The other participants in the new licence award are HRL (a subsidiary of Centrica) 30%, MPX Limited 25% and Agora Limited (a subsidiary of Cairn Energy) 10%.

This block is adjacent to Serica Block 113/27c and the farm-out agreement for Blocks 113/26b and 113/27c with Centrica noted above, extends to the new licence offered. As a result, Serica will have a 20% interest both in the new licence offered and in Blocks 113/26b & 27c on completion of the farm-out. The Doyle prospect in Block 113/27c is believed to extend into Block 113/22a.

Northern North Sea: Blocks 210/19a and 210/20a - South Otter Prospects

Drilling of the South Otter blocks, in which Serica held a 100% interest, remained subject to a farm-out programme.  As sufficiently attractive proposals to enable a well to be drilled in the blocks were not received, Serica made the decision to relinquish the blocks in January 2013 to comply with the terms of the licence.

Ireland

Frontier Exploration Licence 1/09: Blocks 5/17, 5/18, 5/22, 5/23, 5/27, and 5/28 - Muckish Prospects

Serica holds a 100% working interest in six blocks in this licence covering a total area of 993 square kilometres in the north-eastern part of the Rockall Basin off the west coast of Ireland.

A large exploration gas condensate prospect, Muckish, has been fully delineated from 3D seismic data in Blocks 5/22 and 5/23. Muckish is analogous to the nearby Dooish gas condensate discovery and provides material upside in a proven hydrocarbon basin.  The evaluation of 3D seismic data coverage and the nearby Dooish gas-condensate discovery, give confidence in the potential of the prospect which covers an area of approximately 30 square kilometres with over 600 metres of vertical closure in a water depth of 1,450 metres.

Serica has secured a two-year extension to the first phase of the licence covering the blocks and is moving forward with plans to perform a site survey in preparation for securing partners to participate in drilling the Muckish prospect.

Frontier Exploration Licence 4/13 - Blocks 11/10, 11/15, 12/1(part), 12/6 and 12/11(part) - MidletonProspects

In December 2013, following the initial two year period of the licence award, Serica took the option to convert Licence Option 11/01, also located in the Rockall Basin, into a full Frontier Exploration Licence ("FEL"). Following a mandatory 25% relinquishment at the time of the option conversion into FEL 4/13, the three blocks and two part blocks now cover an area of approximately 925 square kilometres.

The area covered by the licence contains two pre-Cretaceous fault block prospects, Midleton and West Midleton which are analogous to the proven gas-condensate bearing Dooish discovery lying immediately to the east. These complement and provide additional diversity to the Muckish prospect lying in Serica's acreage just to the north east and the award will enable a comprehensive exploration programme covering the Muckish and Midleton prospects.

Serica is undertaking 2D and 3D seismic reprocessing work and other geological studies to firm up these two additional prospects. Recent in-house analysis of the extensive seismic database has also indicated the presence of deepwater fans, a play type not previously considered.  This will be fully evaluated during this licence phase.

Frontier Exploration Licence 01/06: Blocks 27/4, 27/5 (west) and 27/9 - Liffey & Boyne Prospects

Licence FEL 1/06 covers an area of approximately 305 square kilometres in the Slyne Basin off the west coast of Ireland. The blocks lie some 40 kilometres south of the Corrib discovery, which has reserves of approximately 800 bcf of gas. The Company holds a 50% interest in the blocks and operates the licence.

The Company, in partnership with RWE, has launched a farm-out campaign to follow up on the 2009 Bandon oil discovery made by Serica. Subject to identifying a suitable partner or partners a well is targeted to be drilled on the Boyne prospect in 2015.

Namibia

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

During 2013, Serica, in partnership with BP, undertook the processing and interpretation of an extensive 4,180 square kilometre 3D seismic survey undertaken by Serica in 2012.  The survey, covering approximately 25% of the licensed area and costing approximately US$50 million, was fully funded by BP under the terms of a farm-out agreement with Serica and was designed to delineate the size and nature of Prospect B, one of three large structures identified on the licence at Lower Cretaceous (Barremian) level, and to examine prospectivity at shallower levels.

The results of this survey are positive.  Processing of the data confirms Prospect B as having the clear characteristics of a large carbonate platform extending over 700 square kilometres with a vertical closure of up to 300 metres. The expectation of a predominantly carbonate structure has been reinforced by third party drilling elsewhere in Namibia which has proven the presence of large structures with associated carbonate build-up at Lower Cretaceous level

The survey also confirmed the presence of large submarine canyon-channel turbidite sand systems at both Lower and Upper Cretaceous levels.  These, together with further leads and other large prospects on the licence, provide considerable additional potential.  This is recognised in the NSAI report which gives a combined best estimate of gross unrisked prospective oil resources associated with 7 prospects and 2 leads identified on licence of 2,297 million barrels and 437 million barrels respectively.

In December 2013, BP decided not to exercise an option to increase its interest in the licence and assigned its 30% interest to Serica under the terms of Serica's farm-out agreement with BP.  Serica now holds an interest of 85% in the licence in partnership with The National Petroleum Corporation of Namibia (Pty) Limited ("NAMCOR") and Indigenous Energy (Pty) Limited.  The withdrawal of BP leaves Serica with a valuable and extensive, fully interpreted data set and provides the Company with an opportunity to attract new partners and to retain a larger percentage interest.

Morocco

Sidi Moussa and Foum Draa Petroleum Agreements

Serica holds licence interests in the Foum Draa and adjacent Sidi Moussa Petroleum Agreements offshore Morocco.  The blocks cover a total area of approximately 8,375 square kilometres in the sparsely explored Tarfaya-Ifni Basin and extend from the Moroccan coastline into water depths reaching a maximum of 2,000 metres. The Tarfaya-Ifni Basin is geologically analogous to the oil producing salt basins of West Africa.

Foum Draa

Following a farm-out to Cairn Energy, Serica has an 8.33% interest in the Foum Draa licence.

In October 2013, drilling operations on the licence commenced with the FD-1 well. In December, Cairn reported that the well had reached a Total Depth of 5,255m MDBRT (measured depth below rotary table). Although commercial hydrocarbons and clastic reservoir rocks were not found, gas shows were encountered indicating an active thermogenic petroleum system. The well was plugged and abandoned. Under the terms of the 2012 farm out agreement Serica was carried by Cairn for its share of drilling costs up to a gross well cost of US$60 million.

Sidi Moussa

Serica has a 5% working interest in the Sidi Moussa licence and is carried by Genel for its share of the cost of drilling the first well on the licence up to a gross well cost of US$50 million. The location for the first exploration well has been agreed and the well will target a prospect with unrisked prospective resources estimated by Genel, the operator, at 200 mmboe. Site survey operations were completed in August/September 2013, a rig contract has been signed for the Noble Paul Romano drilling rig and the well is due to spud in Q3 2014.

Norway

Serica has a significant economic interest in the development of the Bream field and is due a substantial payment on first production.  In their Annual Results Statement (March 2014), the Operator, Premier, stated: "A formal concept selection design will now take place during the first quarter of 2014 and an investment decision is planned for late 2014, or early 2015.  The Bream development concept is planned to be an FPSO with subsea production and water injection wells". 

Indonesia

Glagah Kambuna TAC  - Kambuna Field, Offshore North Sumatra, Indonesia

Serica held a 25% interest in the Glagah Kambuna Technical Assistance Contract ("TAC") offshore North Sumatra, Indonesia for the large part of 2013. The TAC covered an area of approximately 380 square kilometres and contained the producing Kambuna gas field.

Throughout the first half of 2013 the Company benefited from cash flows from field production but the field reached the end of its economic life in July 2013 and was shut-in as planned. Gross Kambuna field production in 2013 was 1,176 mmscf of gas and 100,000 barrels of condensate. Average prices realised during the year for gas and condensate sales respectively were US$6.5 per mcf and US$105.3 per barrel.

The partnership agreed handover arrangements with the Indonesian authorities and the decommissioning process, which involved securing the three wells and wellhead structure, was completed in November 2013. The TAC was formally terminated and facilities handed over to Pertamina in December 2013.

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 4,800 standard cubic feet per barrel for Kambuna, which has a relatively high calorific value, and 6,000 standard cubic feet per barrel for Columbus)
FPSO	Floating, production, storage and offloading unit
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
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

FINANCE DIRECTOR'S REVIEW

Financial summary

The Group entered 2013 aware that Kambuna field revenues would cease in mid year and that it would be more than two years before expected first revenues from the Columbus field. It was therefore recognised that additional funding would need to be secured ready for the Group's exploration programme from 1H 2014 and to support further business growth.

In June 2013 a farm-out on its East Irish Sea licence containing the Doyle prospect was agreed with Centrica. This transaction gives a carry on an exploration well up to a gross cap of £11m, and is another demonstration of the Group's successful approach to risk management limiting its financial exposure whilst maintaining upside potential from exploration drilling.

The most significant exploration expenditure during 2013 was incurred in the UK Southern North Sea on 3D seismic acquisition on the Greater York asset, followed by the drilling of the Foum Draa well in Morocco in Q4 2013. Although the drilling results of the FD-1 well were disappointing, the Group's share of costs was limited due to the capped carry negotiated in the prior year farm-out to the operator Cairn.

The main financial event of the year was the successful capital raise from a placing and open offer which completed in November 2013 raising US$19.5 million before expenses. This transaction is covered in more detail below but enabled the Group to end 2013 with a stronger cash position of US$26.1 million and no debt.

Results from operations

Following the cessation of production and the decommissioning of the Kambuna field facilities in the second half of 2013, the annual 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. 2012 comparative figures have been restated accordingly. A high level summary of the income statement results for continuing and discontinued operations is given below.

Income statement - continuing operations

The Company generated a loss before tax from continuing operations of US$5.1 million for 2013 compared to a loss before tax of US$16.4 million for 2012.

The pre-licence expenditure of US$0.3 million for 2013 was in line with the 2012 charge of US$0.3 million due to a similar level of activity in the year. 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.

Asset write offs of US$0.3 million in 2013 included minor exploration and evaluation ("E&E") asset and obsolete inventory amounts and were significantly lower than the 2012 charge of US$10.5 million. The prior year charge included US$8.8 million attributed to the Spaniards block in the UK North Sea, US$1.1 million of charge from relinquished UK licences and US$0.6 million of obsolete inventory.

Administrative expenses of US$4.5 million for 2013 decreased from US$5.3 million for 2012. The Company has worked to reduce overhead during 2013 and expects these savings to give further benefit in 2014.

The accounting gain of US$1.0 million on disposal in 2012 was recorded following the Company's farm-out to BP in Namibia and related to the recognition of recovery for those past costs incurred that had been expensed as pre-licence costs in previous periods.

Finance costs reduced from US$0.6 million in 2012 to US$0.04 million in 2013 following the expiry of the loan facility in March 2013. No finance costs are currently being incurred.

Income statement - discontinued operations

Serica generated a profit from discontinued operations of US$0.1 million for the year ended 31 December 2013 (2012: loss of US$8.3 million) from its 25% interest in the Kambuna field. Field production ceased in July 2013, the facilities were decommissioned in 2H 2013 and the Glagah Kambuna TAC was formally terminated in December 2013.

The field commenced its anticipated natural decline during 2011 in line with reservoir pressure depletion. In 2013, gross Kambuna field gas production totalled 1,176 mmscf (2012: 5,538 mmscf) together with condensate production of 100,000 barrels (2012: 334,000 barrels). The 2013 gas production was sold at prices averaging US$6.47 per mscf (2012 US$6.53 per mscf) and generated US$1.7 million (2012 US$8.0 million) of revenue net to Serica. Condensate liftings in the year earned US$2.4 million (2012 US$7.4 million) of revenue net to Serica at an average price of US$105.3 per barrel (2012 US$116.1 per barrel).

Cost of sales for 2013 were driven by field production and totalled US$3.9 million (2012 US$19.3 million). The charge comprised direct operating costs of US$2.6 million (2012 US$6.2 million), non cash depletion of US$1.0 million (2012 US$13.1 million) and a decrease in condensate inventory of US$0.3 million (2012 US$0.02 million increase).

In 2012, a US$4.4 million pre-tax impairment relating to the Kambuna field was recorded against oil and gas property, plant and equipment. Taxation charges typically arose from Kambuna field operations, although there is no current taxation or deferred taxation charge in 2012 or 2013 given the cost recovery position of the field at the time.

Balance Sheet

During 2013, total investments in E&E assets increased from US$66.9 million to US$74.6 million, an increase consisting of US$7.8 million of additions less US$0.1 million of exploration asset write-offs. The more significant exploration costs in the year were incurred on the following assets:

In Africa, US$2.3 million was capitalised on the Foum Draa licence in Morocco (largely consisting on the costs of the FD-1 well drilled in Q4 2013) and US$1.1 million was incurred in respect of the Luderitz basin licence interests in Namibia. FD-1 well operations continued into January 2014 and an estimated cost of US$1.2 million of expenditure incurred in the current 2014 period is not recognised in the 2013 financial statements.

In the UK & Ireland, US$2.1 million was incurred on a 3D seismic survey on the Group's Greater York interests in the Southern North Sea, US$0.7 million was incurred on the Columbus development and US$0.7 million on exploration work on the Rockall licences in Ireland.

Property, plant and equipment balances chiefly comprised the net book amount of the expenditure on the Kambuna asset and were fully depleted to US$ nil in the year.

Long-term other receivables of US$1.3 million are represented by value added tax ("VAT") on Indonesian capital spend which continues to be recovered from the Indonesian authorities.

Trade and other receivables at 31 December 2013 totalled US$3.9 million and included US$1.4 million of trade debtors from condensate sales from the Kambuna field. The aggregate total in 2013 showed a decrease of US$5.0 million from the 2012 balance of US$8.9 million. The fall is attributable to the recovery during the period of Indonesian VAT, back costs from 2012 farm-outs and a significant drop in JV partner recoverables in Namibia and Kambuna, reflecting the reduced current activity on those assets.

Cash and cash equivalents increased from US$22.3 million to US$26.1 million in the year The Company received net proceeds of US$18.2 million from the issue of shares in the placing and open offer which completed in November 2013, and also benefitted from cash inflows from Kambuna field revenues. Cash outflows were incurred on the Q4 2012 East Spaniards well (US$6.9 million) and Greater York 3D seismic acquisition (US$2.1 million) in the UK, Kambuna field operating costs in Indonesia and on the Foum Draa exploration well drilling in Morocco. Other costs included seismic work across the portfolio, Columbus Field Development Plan expense together with new venture costs, ongoing administrative costs and corporate activity.

Trade and other payables totalled US$4.4 million at 31 December 2013 and were significantly reduced from the prior year balance of US$11.7 million which included US$6.9 million of liabilities from the East Spaniards well in the UK drilled in Q4 2012 but cash settled in Q1 2013. The current year balance chiefly includes creditors and accruals of US$1.7 million from the Foum Draa well drilling in Morocco and final creditors of US$1.1 million from the Kambuna field decommissioning and operations.

Provisions of US$1.6 million at 31 December 2012 were in respect of obligations to decommission the Kambuna in Indonesia. This process was completed in Q4 2013 and any unpaid liabilities are classified in trade and other payables.

Capital raising, cash and future commitments

Capital raising

The main financial event in the year was a capital raising which completed in November 2013 and raised aggregate gross proceeds of approximately US$19.5 million.

The capital raising comprised three elements: the placing of 56,870,934 new ordinary shares with institutional and other investors; the acceptance of 6,093,351 new ordinary shares in an open offer to qualifying shareholders; and the placing of 4,444,444 new ordinary shares not taken up by qualifying shareholders under the open offer.

All new ordinary shares were issued at a price of 18 pence per share and following the relevant required approvals, the aggregate of 67,408,729 new ordinary shares were listed on AIM and the TSX in November 2013. As at 9 April 2014 the Company has 250,179,040 ordinary shares issued and outstanding.

Whilst the Company was able to meet its 2013 commitments from cash in place as at 31 December 2012, the capital raising was needed for the exploration programme from 1H 2014 and to support further business growth. It has also put the Company onto a stronger footing and improved its ability to fund upcoming expenditure in order to bring projects to maturity whilst enabling the Group to optimise, and ultimately realise, value across its portfolio.

Current cash position, capital expenditure commitments and other obligations

At 31 December 2013, the Group held cash and cash equivalents of US$26.1 million and US$0.4 million of short-term restricted cash. Liabilities of US$2.8 million arising from the Q4 2013 Foum Draa well in Morocco have been settled since the year end, and as at 7 April 2014, cash and restricted cash balances held totaled US$21.5 million. Management believe these are sufficient resources to meet the current committed programme for 2014 and 2015. 

The Group's main near term exploration commitments in 2014 are on the Sidi Moussa licence where an exploration well is expected to be drilled in Q3 2014. The Company is carried for its share of expenditure up to a gross cap of US$50 million and has currently budgeted to pay some US$2.3 million, being its paying share of costs over and above the agreed cap to the farm-in carry.

In the UK East Irish Sea, the exploration well on the Doyle prospect slated for 2015 is also subject to a cap although no overrun is currently forecast. The Group has no significant commitments on its other exploration licences.

The Company will continue to give priority to the careful management of existing financial resources. Although a key objective for the Group is to get the Columbus development back on track when the final decision to proceed with the Columbus development is made, the Group would use alternative means of finance to fund its share of development costs.

Other

Asset values and Impairment

At 31 December 2013 Serica's market capitalisation stood at US$54.7 million (£33.1 million), based upon a share price of £0.1325, which was exceeded by the net asset value at that date of US$102.1 million. By 7 April 2014 the Company's market capitalisation had decreased to US$44.6 million. Management conducted a thorough review of the carrying value of the Group's assets and determined that no significant write-downs were required.

Christopher Hearne

Finance Director

9 April 2014

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 company 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 acreage leading to the drilling of wells and discovery of commercial reserves. Delivery of this business model carries a number of key risks.
Risk	Mitigation
Market support may be eroded  obstructing fundraising and lowering the share price	·      Management regularly communicates its strategy to shareholders ·     Focus is placed on building an asset portfolio capable of delivering regular news flow and offering continuing prospectivity
General market conditions may fluctuate hindering delivery of the company's business plan	·      Management aims to retain adequate working capital to ride out downturns should they arise
Management's decisions on capital allocation may not deliver the expected successful outcomes	·      Rigorous analysis is conducted of all investment proposals ·      Operations are spread over a range of areas and risk profiles
Each asset carries its own risk profile and no outcome can be certain	·      Management aims to avoid over-exposure to individual assets and to identify the associated risks objectively

Operations: Operations may not go according to plan leading to damage, pollution, cost overruns or poor outcomes.
Risk	Mitigation
Individual wells may not deliver recoverable oil and gas reserves	·      Thorough pre-drill evaluations are conducted to identify the risk/reward balance ·      Exposure is selectively mitigated through farm-out
Wells may blow out or equipment may fail causing environmental damage and delays	·      The Group retains fully trained and experienced personnel ·      The planning process involves risk identification and establishment of mitigation measures ·      Emphasis is placed on engaging experienced contractors ·      Appropriate insurances are retained
Operations may take far longer or cost more  than expected	·      Management applies rigorous budget control ·      Adequate working capital is retained to cover reasonable eventualities
Resource estimates may be misleading and exceed actual reserves recovered	·      The Group deploys qualified personnel ·      Regular third-party reports are commissioned ·      A prudent range of possible outcomes are considered within the planning process

Personnel: The company relies upon a pool of experienced and motivated personnel to identify and execute successful investment strategies
Risks	Mitigation
Key personnel may be lost to other companies	·      The Remuneration Committee regularly evaluates incentivisation schemes to ensure they remain competitive
Personal safety may be at risk in demanding operating environments, typically offshore	·      A culture of safety is encouraged throughout the organisation ·      Responsible personnel are designated at all appropriate levels ·      The Group maintains up-to-date emergency response resources and procedures ·      Insurance cover is carried in accordance with industry best practice
Staff and representatives may find themselves exposed to bribery and corrupt practices	·      Company policies and procedures are communicated to personnel regularly ·      Management reviews all significant contracts and relationships with agents and governments

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

In addition to the principal risks and uncertainties described herein, the Company 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

Approved on behalf of the Board

Christopher Hearne

Finance Director

9 April 2014

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

			* restated
		2013	2012
	Notes	US$000	US$000
Continuing operations
Sales revenue		-	-
Cost of sales		-	-
Gross profit		-	-
Pre-licence costs		(330)	(331)
E&E and other asset write-offs		(299)	(10,462)
Administrative expenses		(4,458)	(5,274)
Foreign exchange gain		341	180
Share-based payments	25	(252)	(570)
Depreciation	6	(109)	(341)
Operating loss before net finance revenue and tax		(5,107)	(16,798)
Gain on disposal	13	-	1,023
Finance revenue	9	16	12
Finance costs	10	(38)	(615)
Loss before taxation		(5,129)	(16,378)
Taxation charge for the year	11 a)	-	-
Loss for the year from continuing operations		(5,129)	(16,378)
Discontinued operations
Profit/(loss) for the year from discontinued operations	4	121	(8,330)
Loss for the year		(5,008)	(24,708)
Loss per ordinary share - EPS
Basic and diluted EPS on continuing operations (US$)	12	(0.03)	(0.09)
Basic and diluted EPS on loss for the year (US$)	12	(0.03)	(0.14)

* restated for discontinued operations - see note 4

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
		2013	2012	2013	2012
	Notes	US$000	US$000	US$000	US$000
Non-current assets
Exploration & evaluation assets	13	74,609	66,880	-	-
Property, plant and equipment	14	-	1,145	-	-
Investments in subsidiaries	15	-	-	-	13,830
Other receivables	16	1,293	1,706	-	-
		75,902	69,731	-	13,830
Current assets
Inventories	17	258	481	-	-
Trade and other receivables	18	3,851	8,941	98,148	111,768
Financial assets	18	420	412	420	412
Cash and cash equivalents	19	26,062	22,345	25,459	21,424
		30,591	32,179	124,027	133,604
TOTAL ASSETS		106,493	101,910	124,027	147,434
Current liabilities
Trade and other payables	20	(4,417)	(11,677)	(959)	(1,080)
Provisions	21	-	(1,601)	-	-
TOTAL LIABILITIES		(4,417)	(13,278)	(959)	(1,080)
NET ASSETS		102,076	88,632	123,068	146,354
Share capital	23	227,958	209,758	192,686	174,486
Merger reserve	15	-	-	-	4,322
Other reserve		20,297	20,045	20,297	20,045
Accumulated deficit		(146,179)	(141,171)	(89,915)	(52,499)
TOTAL EQUITY		102,076	88,632	123,068	146,354

Approved by the Board on 9 April 2014

Antony Craven Walker                            Christopher Hearne

Chief Executive Officer                           Finance Director

________________________________      _____________________________________

Serica Energy plc

Statement of Changes in Equity

For the year ended 31 December 2013

Group		Share capital	Other reserve	Accum'd deficit	Total
		US$000	US$000	US$000	US$000
At 1 January 2012		207,702	19,475	(116,463)	110,714
Loss for the year		-	-	(24,708)	(24,708)
Total comprehensive income		-	-	(24,708)	(24,708)
Share-based payments		-	570	-	570
Proceeds on exercise of options		56	-	-	56
Issue of ordinary shares		2,000	-	-	2,000
At 31 December 2012		209,758	20,045	(141,171)	88,632
Loss for the year		-	-	(5,008)	(5,008)
Total comprehensive income		-	-	(5,008)	(5,008)
Share-based payments		-	252	-	252
Issue of ordinary shares		19,525	-	-	19,525
Fees from issue of shares		(1,325)	-	-	(1,325)
At 31 December 2013		227,958	20,297	(146,179)	102,076

Company	Share capital	Merger reserve	Other reserve	Accum'd deficit	Total
	US$000	US$000	US$000	US$000	US$000
At 1 January 2012	172,430	4,322	19,475	(49,535)	146,692
Loss for the year	-	-	-	(2,964)	(2,964)
Total comprehensive income	-	-	-	(2,964)	(2,964)
Proceeds on exercise of options	56	-	-	-	56
Share-based payments	-	-	570	-	570
Issue of ordinary shares	2,000	-	-	-	2,000
At 31 December 2012	174,486	4,322	20,045	(52,499)	146,354
Loss for the year	-	-	-	(41,738)	(41,738)
Total comprehensive income	-	-	-	(41,738)	(41,738)
Share-based payments	-	-	252	-	252
Issue of ordinary shares	19,525	-	-	-	19,525
Fees from issue of shares	(1,325)	-	-	-	(1,325)
Transfers	-	(4,322)	-	4,322	-
At 31 December 2013	192,686	-	20,297	(89,915)	123,068

Serica Energy plc

Cash Flow Statement

For the year ended 31 December

	Group 2013 US$000	2012 US$000	Company 2013 US$000	2012 US$000
Operating activities:
Loss for the year	(5,008)	(24,708)	(41,738)	(2,964)
Adjustments to reconcile loss for the year
to net cash flow from operating activities:
Net finance costs	28	621	22	605
Profit on disposal	-	(1,023)	-	-
Depreciation	109	341	-	-
Depletion and amortisation	1,036	13,116	-	-
Asset write-offs	299	10,462	-	-
Impairment	-	4,361	40,000	-
Share-based payments	252	570	252	570
Other non-cash movements	(310)	98	(345)	(141)
Decrease in trade and other receivables	4,570	4,051	204	263
Decrease in inventories	24	17	-	-
(Decrease)/increase in trade and other payables	(2,108)	(3,600)	(212)	278
payables
Use of provisions	(1,607)	-	-	-
Cash generated from operations	(2,715)	4,306	(1,817)	(1,389)
Taxation paid	-	(302)	-	-
Net cash (out)/inflow from operations	(2,715)	4,004	(1,817)	(1,389)
Investing activities:
Interest received	16	12	16	8
Purchase of property, plant and equipment	-	(690)	-	-
Purchase of E&E assets	(13,094)	(5,816)	-	-
Cash inflow from disposals	933	5,250	-	-
Funding provided to Group subsidiaries	-	-	(12,762)	-
Funds from Group subsidiaries	-	-	-	4,036
Net cash flow from investing activities	(12,145)	(1,244)	(12,746)	4,044

Financing activities:
Gross proceeds from issue of shares	19,525	-	19,525	-
Fees from issue of shares	(1,325)	-	(1,325)	-
Finance costs paid	(38)	(615)	(38)	(613)
Proceeds on exercise of options	-	56	-	56
Net cash flow from financing activities	18,162	(559)	18,162	(557)
Net increase in cash and cash equivalents	3,302	2,201	3,599	2,098
Effect of exchange rates on cash and cash
equivalents	415	198	436	184
Cash and cash equivalents at 1 January	22,345	19,946	21,424	19,142
Cash and cash equivalents at 31 December	26,062	22,345	25,459	21,424

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 2013 were authorised for issue by the Board of Directors on 9 April 2014 and the balance sheets were signed on the Board's behalf by Antony Craven Walker and Chris Hearne. Serica Energy plc is a public limited company incorporated and domiciled in England & Wales. 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 and the TSX.

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 2013. 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 2013 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 deficit dealt with in the financial statements of the parent Company was US$41,738,000 (2012: US$2,964,000).

On 1 September 2005, the Company completed a reorganisation (the "Reorganisation").  whereby the common shares of Serica Energy Corporation were automatically exchanged on a one-for-one basis for ordinary shares of Serica Energy plc, a newly formed company incorporated under the laws of the United Kingdom. In addition, each shareholder of the Corporation received beneficial ownership of part of the 'A' share of Serica Energy plc issued to meet the requirements of public companies under the United Kingdom jurisdiction. Under IFRS this reorganisation was considered to be a reverse takeover by Serica Energy Corporation and as such the financial statements of the Group represent a continuation of Serica Energy Corporation.

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 2013.

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 financial position of the Group, its cash flows and capital commitments are described in the Financial Review above. Although the Group no longer benefits from sales revenue generated from its interest in the Kambuna field, following the capital raising of US$18.2 million (net of expenses) which completed in November 2013, the Group held cash and cash equivalents of US$26.1 million as at 31 December 2013.

 
The Directors are required to consider the availability of resources to meet the Group and Company's liabilities for the foreseeable future. Since the year end the Group has paid outstanding commitments of US$2.8 million from the recent Foum Draa exploration well in Morocco. It will also use these funds to pay its share of drilling costs over the contractual US$50 million cap on the Sidi Moussa well in Morocco, which is expected to spud in Q3 2014.   The Group's planned exploration well on the Doyle prospect in 2015 is also subject to a capped carry, which is not currently forecast to be exceeded. Any share of costs over the carry would not be significant and could be satisfied from current cash balances.

The cash in place will cover other geological and geophysical, exploration, technical and administrative costs associated with its ongoing business in the short to medium term. In particular, it also provides balance sheet support to help achieve infrastructure access and project sanction for the Columbus field, and covers pre-drilling work in Namibia. When the final decision to proceed with the Columbus development is made, the Group would use alternative means of finance to fund its share of development costs.

The Group has a record of prudent financial management with particular success in the raising of capital through farm down and will seek to continue this strategy.

 
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 annual 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 judgments 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 share-based payment costs.

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 datasets using its own internal expertise.

Impairment

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 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 15).

Share-based payment costs

The estimation of share-based payment costs requires the selection of an appropriate valuation model, consideration as to the inputs necessary for the valuation model chosen and the estimation of the number of awards that will ultimately vest, inputs for which arise from judgments relating to the continuing participation of employees (see note 25).

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 Namibia B.V., Serica Energy Corporation, Asia Petroleum Development Limited, Petroleum Development Associates (Asia) Limited, Petroleum Development Associates Lematang Limited, Serica Energia Iberica S.L., Asia Petroleum Development (Asahan) Limited and Asia Petroleum Development (Biliton) 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 jointly controlled 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.

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.

The Kambuna field was depleted using proved and probable entitlement reserves until 30 June 2011. However, given the relatively short remaining field life, the Company then concluded that it was appropriate to use proved reserves as a basis for the specific depletion calculation for the Kambuna field asset with effect from 1 July 2011. Following the advancement of field shut-in plans and handover arrangements with Pertamina in 2H 2013, the Company concluded that, with effect from 1 October 2012, it was appropriate to use its best estimates of remaining production quantities as a basis to calculate the reserves for specific depletion and impairment calculations for the Kambuna field. The Kambuna property was fully depleted in July 2013.

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.

Asset Disposals

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.

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.

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 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.

Borrowing costs

Borrowing costs directly relating to the acquisition, construction or production of a qualifying capital project under construction are capitalised and added to the project cost during construction until such time the assets are substantially ready for their intended use i.e when they are capable of commercial production. Where funds are borrowed specifically to finance a project, the amounts capitalised represent the actual borrowing costs incurred. All other borrowing costs are recognised in the income statement in the period in which they are incurred.

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.  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, except for the following new and amended IFRS and IFRIC interpretations effective as of 1 January 2013 unless otherwise stated. The adoption of the standards or interpretations is described below:

i)        IAS 1 Financial Statement presentation - Presentation of items of Other Comprehensive Income

The amendments to IAS 1 change the grouping of items presented in Other Comprehensive Income. Items that could be classified to profit or loss at a future point in time would be presented separately from items that will never be reclassified. The amendment affects presentation only and has no impact on the Group's financial position or performance. The amendment became effective for annual periods beginning on or after 1 July 2012.

ii)       IFRS 10 Consolidated Financial Statements

IFRS 10 replaces the portion of IAS 27 Consolidated and Separate Financial Statements that addresses the accounting for consolidated financial statements. The application of IFRS 10 and IAS 27 did not impact the Group's accounting for its interests in subsidiaries.

iii)       IFRS 11 Joint Arrangements

IFRS 11 replaces IAS 31 Interests in Joint Ventures and SIC-13 Jointly-controlled Entities - Non-monetary Contributions by Venturers. IFRS 11 removes the option to account for jointly controlled entities (JCEs) using proportionate consolidation. Instead JCEs that meet the definition of a joint venture must be accounted for using the equity method. The application of IFRS 11 did not impact on the financial position or performance of the Group.

iv)      IFRS 12 Disclosure of Involvement with Other Entities

IFRS 12 includes all of the disclosures that were previously in IAS 27 related to consolidated financial statements, as well as all of the disclosures that were previously included in IAS 31 and IAS 28. These disclosures relate to an entity's interests in subsidiaries, joint arrangements, associates and structured entities. A number of new disclosures are also required but the application of IFRS 12 did not impact on the financial position or performance of the Group.

v)       IFRS 13 Fair Value Measurement

IFRS 13 establishes a single source of guidance under IFRS for all fair value measurements. IFRS 13 does not change when an entity is required to use fair value, but rather provides guidance on how to measure fair value under IFRS when fair value is required or permitted, and also requires additional disclosures. Application of IFRS 13 hasnot materially impacted the fair value measurements of the Group.

Standards issued but not yet effective

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

IFRS 9 Financial Instruments: Classification and Measurement

IFRS 9 as issued reflects the first phase of the IASBs work on the replacement of IAS 39 and applies to the classification and measurement of financial assets and financial liabilities as defined in IAS 39. The standard is expected to be effective for annual periods beginning on or after 1 January 2018.

Amendments to IAS 36: Recoverable Amount Disclosures for Non-Financial Assets

The amendment addressed certain unintended consequences arising from consequential amendments made to IAS 36 when IFRS 13 was issued. The amendment is effective for annual periods beginning on or after 1 January 2014.

The Directors anticipate the adoption of the standards and interpretations listed above, or any others in issue but not yet adopted, will not have a material impact on the Financial Statements of the Group.

 

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