Serica Energy plc
AIM : SQZ
TSX : SQZ

Serica Energy plc

March 31, 2011 02:00 ET

Serica Energy plc: 2010 Annual Report to Shareholders

LONDON, UNITED KINGDOM--(Marketwire - March 31, 2011) - Serica Energy plc ("Serica" or the "Company") (TSX:SQZ)(AIM:SQZ), the oil and gas exploration and production company, announces its results for the year ended 31 December 2010. The results and associated Management Discussion and Analysis are included below and copies are available at www.serica-energy.com and www.sedar.com.

Highlights

Financial:

  • 2010 sales revenue US$31.3 million
  • Gross profit before expenses US$12.5 million
  • Loss before tax US$43.2 million after charges of:
    • US$29.5 million exploration costs
    • US$11.8 million relating to reappraisal of Kambuna field reserves
  • Carry forward UK ring fence tax allowances available US$126 million
  • Since the year end:
    • All outstanding debt repaid
    • Current unrestricted cash balances US$21 million

Operations:

  • Kambuna field:
    • Consistently delivered at rate demanded throughout the year
    • 2010 gross average daily sales 31 mmscfd gas and 2,685 bpd condensate
    • 2011 YTD gross average daily sales c.40 mmscfd gas and c.3,000 bpd condensate
    • Condensate price strong - US$106 per barrel realised in February 2011
    • RPS estimate 8.2 mmboe remaining gross reserves at 1/1/11
  • Columbus field:
    • Front end engineering studies largely completed
    • Negotiations continue for export via Lomond field but alternative routes under review
    • NSAI estimate 12.6 mmboe gross reserves in Block 23/16f
    • Uncertainty introduced by UK Budget tax increase
  • Outcome of 2010 exploration drilling:
    • Conan and Oates encountered water-bearing sands - costs largely met by partners
    • Dambus and Marindan encountered gas but sub-commercial

Corporate:

  • Paul Ellis, CEO retires but will remain involved in a consultancy capacity
  • Tony Craven Walker, Chairman will act as Chairman and interim CEO
  • Peter Sadler, COO becomes Business Development Director, to focus on acquisition strategy
  • Mitch Flegg, currently responsible for Serica's Drilling & Developments, becomes COO

Outlook:

  • Prospects identified for 2011/12 drilling:
    • UK/Ireland – Spaniards, Doyle, Boyne, Liffey
    • Indonesia – Kambuna North, Kutai, East Seruway
  • Final award of three UK offshore blocks under UK 26th Licensing Round anticipated
  • Indonesian assets under discussion with interested parties which may lead to a sale
  • New acreage under negotiation
  • Financial resources to support acquisitions

Paul Ellis, Chief Executive of Serica commented:

"Despite a very active year it was disappointing that we did not experience success with the drill bit. However, we have a number of very interesting prospects yet to drill and, although the recent Budget tax changes are likely to have an impact, we continue to evaluate options to develop the Columbus field.

Following a strategic overview, we are considering proposals which may result in us selling our properties in Indonesia, including our remaining interest in the Kambuna field. Such a sale, in addition to adding to our cash position, will enable us to release resources to develop new opportunities through acquisition or licence awards.

I am retiring as CEO in April but I shall be continuing to work with the Company in relation to some of the new areas currently under negotiation. I am extremely confident in the Company's future and its management and strongly believe in its success."

Tony Craven Walker, Chairman of Serica commented:

"Paul Ellis, our CEO, is retiring having reached normal retirement age but I am delighted that he will be continuing to provide his invaluable services as representative on some of our ongoing projects. Paul has been key to building both the technical and operating skills of the Company and I and the Board would like to express our thanks for the contribution he has made whilst he has been with us.

Until we have identified a successor I shall be acting as both Chairman and interim CEO. In this capacity I will have a very strong executive team. Peter Sadler, who has been our COO, is taking on the new responsibility of Business Development Director to identify acquisition opportunities which complement our existing business and provide new growth potential. In this role he will be working closely with Chris Hearne, our Finance Director. Peter's position as COO will be taken by Mitch Flegg who has been responsible for the successful drilling operations of Serica's wells over the past 5 years and for the field developments at Kambuna and Columbus. This is a strong team and I am looking forward to working with them.

Serica is underpinned by its core assets and a healthy balance sheet. With unrestricted cash resources, no debt, experienced management, exploration prospects and the opportunity to expand into new areas the future holds great potential."

31 March 2011

The technical information contained in the announcement has been reviewed and approved by Peter Sadler, Chief Operating Officer of Serica Energy plc. Peter Sadler is a qualified Petroleum Engineer (MSc Imperial College, London, 1982) and has been a member of the Society of Petroleum Engineers since 1981.

Notes to Editors

Serica Energy plc is an oil and gas exploration and production company based in London, England, and holds exploration and production licences in the UK offshore, onshore Spain, the Atlantic Margins of Ireland and Morocco and in Indonesia. The Company's producing and development assets are a 25% interest in the producing Kambuna field offshore Indonesia and a 50% stake in the UK Central North Sea Columbus field.

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.

To receive Company news releases via email, please contact nick.elwes@collegehill.com and specify "Serica press releases" in the subject line.

CHAIRMAN'S REPORT

Dear Shareholder

I write at a time when unprecedented events are taking place in North Africa and the Middle East and the political landscape is changing in many of the important oil producing nations. Oil prices are again rising strongly and business horizons are changing quickly.

How long it will be before the situation stabilises is uncertain but, with the scale of the disaster in Japan also likely to slow the development of nuclear energy, it is clear that the need for new sources of oil and gas is stronger than ever. The role of smaller players in developing new ideas in previously overlooked or under explored regions has been fully demonstrated in recent years and that role will continue. It is our firm belief that the Company has the skills and potential to pursue such opportunities.

In 2010, Serica carried out its most active exploration programme, drilling a total of four wells in the East Irish Sea, the UK North Sea and Indonesia. The results were, however, disappointing. The two wells drilled in Indonesia encountered hydrocarbons but not in commercial quantities. Of the four wells, three were drilled by Serica as operator. I am pleased to report that all were drilled to a very high technical standard, fully demonstrating the Company's operating skills. A significant proportion of the Company's share of UK drilling costs was borne by partners as the result of farm-outs. However, we are writing off US$29.5 million to account for seismic, drilling and other costs borne by the Company in 2010 and earlier years. The bulk of this relates to wells drilled in Indonesia. 

In Indonesia, the Kambuna field consistently delivered at the rate demanded throughout the year and continues to do so. However the greater than expected reservoir pressure decline noted in our second and third quarter results has not significantly improved and has resulted in a downward revision to reserves. We have accordingly taken an impairment charge of US$11.8 million to the carrying cost of the asset.

In the light of these results, the Board has been reviewing its strategy and the areas in which it operates. In Indonesia, the Board has felt that the cost and difficulty of doing business is too high compared to the potential rewards and we have already been gradually disposing of our interests. This has enabled us to realise material profits from two sales over the past two years and we are currently in discussions with interested parties with a view to the possible disposal of the balance of our Indonesian properties. In the UK, the infrequency of licensing round awards and the challenges in gaining access to existing infrastructure, where we have yet to reach agreement on commercial terms that would enable us to bring our Columbus field onto production, provide additional constraints. The change to North Sea taxation recently announced by the Chancellor of the Exchequer is likely to add further uncertainty to delay the development of new North Sea fields.

Whilst continuing to seek ways in which we can expand and accelerate our business in the UK the Company is now setting its sights on new areas where we feel there are opportunities for greater growth. We have a strong position in the waters west of Ireland, where we have already shown the presence of oil in the Slyne Basin, and have emerging positions in the Irish Rockall basin and in the waters off Morocco. We intend to build on these as well as looking for new underexplored areas. We expect to be successful in the award of three out of the four UK offshore blocks for which we applied in the 26th Licensing Round and are in negotiations for new prospective acreage overseas.

As we seek to expand these activities we are announcing a number of executive changes. Paul Ellis, our Chief Executive, reaches normal retirement age on 10th April 2011 and, in accordance with his contract, will be retiring from the Company on that date. Whilst he is retiring at a time when the Company has yet to see the full benefits of his hard work I personally, and the Board, would like to thank him for all he has done to build the technical and operating skills of the Company and to lay the foundations for the future. Until the process of identifying a successor to the CEO has been completed I shall be acting as Chairman and interim CEO and I am pleased that Paul will continue to provide his full support to the Company in a consultancy capacity during this period including representing the Company for new licence awards currently under negotiation.

It is a major plank of the Company's forward strategy to identify acquisition possibilities, both in the UK and overseas, to complement our exploration activities and to provide Serica with additional growth potential. To further this objective, Peter Sadler will be taking up the role of Business Development Director. I am pleased that this will enable the Company to benefit from Peter's skills and his wide experience to the full. Mitch Flegg, who has been responsible for the successful drilling operations of all of Serica's wells over the past five years and for the field development studies for Columbus, will be taking over from Peter as Chief Operating Officer. Mitch has the undoubted experience for the role and I am delighted that he has accepted the position.

Since the start of 2011 the Company has paid off all outstanding debt and retains undrawn facilities amounting to US$50 million. With technical expertise, proven operating capability, no debt and cash resources currently standing at some US$21 million the Company is in a good position to seek new exploration and partnership opportunities whilst building on its existing acreage. We recognise that the risks and the time frames involved in exploration are significant limiting factors and the disappointing outcome of our 2010 exploration programme has been a setback. It is to increase opportunity, spread risk, accelerate return and improve the chance of success that, as we expand our portfolio and focus on new areas, we shall be reviewing the potential for acquisition.

The Company's share price has performed poorly over the year, reflecting the lack of drilling success in 2010 and the downward revision to Kambuna reserves. However, the Company's core assets and healthy balance sheet provide a strong underpinning and I hope that 2011 will see a substantial improvement for all shareholders.

Tony Craven Walker
Chairman
30 March 2011

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following management's discussion and analysis ("MD&A") of the financial and operational 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 2010.

Serica's activities are based in the UK, Ireland, Spain, Morocco and Indonesia. References to the "Company" include Serica and its subsidiaries where relevant. All figures are reported in US dollars ("US$") unless otherwise stated.

CHIEF EXECUTIVE OFFICER'S REPORT – 2010

By the end of 2009, having achieved farm-outs in preparation for the Conan and Oates exploration wells, commenced production from the Kambuna field and reduced our exposure in South East Asia through the transaction with Kris Energy, Serica anticipated an exciting year in 2010. However, all the hard work carried out to establish an excellent starting point for the year did not ultimately bring the rewards for which we had hoped.

In Indonesia, the difficulties encountered with the Kambuna field gas buyer in 2009 continued to affect gas sales well into 2010 and the buyer did not finally resolve its problems until July, when contract rates were then achieved through the end of the year. In mid-year we noted that Salamander Energy, the Kambuna field operator, had reported a reduction in forecast Kambuna ultimate recoverable reserves based on early indications of a greater than expected reservoir pressure decline observed in one of the Kambuna wells. Given the significant extrapolation required to make this forecast, and based on previous experience with other similar reservoirs, we took the view that, in time, the rate of pressure decline might reduce, leading to a less severe reserves forecast.

However, by the end of 2010 there was little sign of any change in the decline rate and our independent reserves evaluators, RPS, have therefore reduced Serica's remaining reserves as shown in the table in our results. Serica's original interest in the Kambuna field was 65% and through transactions in 2008 and 2009 we reduced our stake to 25%. As a result the reduction in reserves is not as significant to the Company as it could have been. Kambuna gas sales in 2011 are continuing to meet expectations and average around 40 mmscfd gross, with gross condensate sales around 3,400 bpd. The condensate sales price in February 2011 was $105.88/bbl.

Our drilling programme in the Kutai PSC Indonesia encountered gas in both the Dambus and Marindan offshore exploration wells, but unfortunately not in commercial quantities. In November we announced that we were undertaking a strategic review of our Indonesian assets and we are currently in discussion with interested parties which may lead to a sale of the properties.

In 2009 we discovered non-commercial oil in a shallow Jurassic reservoir in the Bandon well in our Slyne Basin licence FEL 1/06 off the west coast of Ireland and, in 2010, we carried out the site surveys and environmental studies required for further drilling. We now have all the data required to drill two deeper Jurassic oil prospects at the Boyne and Liffey locations and are seeking a new partner in the blocks prior to contracting a drilling rig. Due to the extreme sea conditions experienced in the winter months it is only possible to drill a well in the Irish Atlantic in the short summer drilling season. Whilst it is possible to drill in 2011 it is more likely that drilling will take place in 2012.

We have also been continuing our studies in the Irish Rockall Basin Licence FEL 1/09, to refine our interpretation of the Muckish prospect. The Rockall Basin is a highly underexplored area of the Atlantic Margin off the north west coast of Ireland and we are making plans to be ready to drill the Muckish prospect in 2012.

In the UK we continued our efforts to secure commercial terms for the processing and transportation agreements for Columbus field production via the adjacent Lomond field, operated by BG Group ("BG").

Serica (on behalf of the Columbus partners) has been actively cooperating with BG in the design and FEED studies for a Bridge Linked Platform ("BLP") to be installed adjacent to the Lomond field platform that would receive production from Columbus, Arran and other fields (including future BG developments) for transportation via the Lomond field to the CATS and Forties pipeline systems. As part of these studies, the Columbus partners carried out a pipeline route survey from Columbus to the proposed BLP location.

However negotiations to date with BG have not secured acceptable terms and it is currently uncertain that Columbus will be developed via Lomond. In parallel with its negotiations with BG, Serica has therefore been evaluating alternative export routes in conjunction with its partners in Block 23/16f and other field operators in the area.

Netherland Sewell Associates Incorporated ("NSAI") has reviewed the sub-surface data on Columbus and also Serica's detailed report prepared to complement the Field Development Plan submission. The NSAI review incorporates wells drilled in Block 23/21 to the south by BG and NSAI interprets the data to indicate that some of the Columbus reserves may lie in Block 23/21. On this basis NSAI interpret gross 2P reserves lying in Block 23/16f to be 12.6 mmboe, a net 6.3 mmboe to Serica. Further studies are required to determine the reserve allocation between the blocks but the NSAI review results in a 2P reserves reduction net to Serica of 2.5 mmboe.

We drilled two exploration wells in UK waters during the year, for each of which we had high expectations.

In the East Irish Sea we drilled the Conan prospect in Block 113/26b, a Triassic Sherwood Sandstone gas prospect lying about 10 kilometres from the North Morecambe gas field. Although the well encountered the Sherwood reservoir, the sands were water-bearing and the well was plugged and abandoned as a dry hole. It is now believed that an anomalously thick anhydrite layer found above the reservoir level was responsible for creating a seismic response that appeared to indicate the presence of hydrocarbons and that this layer is thin or absent above the examples of valid hydrocarbon responses seen over many of the gas fields discovered in the East Irish Sea. The result has not changed the merits of the Doyle prospect in the adjacent Block 113/27c. Serica has a 65% interest in the Block and expects to see further drilling in this licence.

In the Central North Sea we drilled the Oates prospect in Block 22/19c, a Palaeocene Forties Sandstone prospect that exhibits a very similar seismic response to that seen at the Columbus field 20 kilometres to the east. The Forties reservoir was encountered as prognosed but, as at Conan, the sands were water-bearing. It has taken some time to understand why the exploration technique that was 100% successful in the Columbus area (seven gas-condensate discoveries in seven exploration wells) did not result in a hydrocarbon discovery at Oates. The most likely reason for the false hydrocarbon indicator is the anomalous nature of the overlying shale that can produce a very similar response to that of hydrocarbons.

As is our normal practice we worked hard to minimise Serica's downside cost and both of the UK wells were farmed out in order to achieve significant cost reduction. The cost of the two wells to Serica was around US$3 million out of a total of about US$24 million.

As we realise the value of our interests in Indonesia we can focus more attention on areas of greater prospectivity and better commercial terms than those currently available in South East Asia and we intend to reshape our exploration portfolio on that basis. We shall also seek acquisitions that will enable us to build the exploration portfolio more rapidly than is possible through licence round awards.

With no debt and with the proven abilities to manage the downside of the exploration business, Serica is well positioned to move forward with new and exciting projects. Peter Sadler is taking responsibility as Business Development Director to pursue acquisition opportunities for the Company and Mitch Flegg, who has been with Serica since 2006, is to take over the position of Chief Operating Officer. Both Peter and Mitch have a huge amount of experience to bring to these roles and I look forward to seeing the results of their new responsibilities.

Finally, while it has been a great pleasure to work with the Serica team since 2005 all good things must eventually come to an end. After nearly 43 years in the E&P business the time has come for me to take a back seat and I shall be retiring on 10th April. I expect to be involved in a consultancy role in the future, helping the Company on its new course, and I still have a large personal shareholding – so I will certainly be maintaining my interest in Serica's future.

I should like to thank the Serica staff and the Board for supporting me over the last 5½ years and I remain very confident of the Company's ultimate success.

Paul Ellis, Chief Executive Officer

REVIEW OF LICENCE HOLDINGS AND OPERATIONS

Serica holds offshore licence interests in the UK North Sea, the UK East Irish Sea, Ireland and Morocco, onshore licence interests in Spain and licence interests both onshore and offshore in Indonesia.

The following table summarises the Company's Licences as at 31 December 2010.

         
Block(s) Description Role % at Location
      31/12/10  
UK        
15/21g Exploration Non-operator 30% Central North Sea
22/19c Exploration Non-operator 50% Central North Sea
23/16f Columbus field
Development planned
Operator 50% Central North Sea
23/16g Exploration Operator 50% (1) Central North Sea
48/17d Exploration Operator 65% (2) Southern Gas basin
110/2d Exploration Operator 100% East Irish Sea
113/26b Exploration Operator 65% East Irish Sea
113/27c Exploration Operator 65% East Irish Sea
210/19a Exploration Operator 100% Northern North Sea
210/20a Exploration Operator 100% Northern North 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
         
Spain        
Abiego Exploration Operator 75% Pyrenees/Ebro Basin
Barbastro Exploration Operator 75% Pyrenees/Ebro Basin
Binéfar Exploration Operator 75% Pyrenees/Ebro Basin
Peraltilla Exploration Operator 75% Pyrenees/Ebro Basin
         
Morocco        
Foum Draa Exploration Non-operator 25% Tarfaya Basin
Sidi Moussa Exploration Non-operator 25% Tarfaya Basin
         
Indonesia        
Glagah Kambuna
TAC
Kambuna Field
Production
Non-Operator 25% Offshore
North Sumatra
East Seruway
PSC
Exploration Operator 100% Offshore
North Sumatra
Kutai PSC Exploration Operator 30% Kutai basin
         
Notes:
 
 (1) Interest relinquished in February 2011.
 (2) Interest now 0% following transfer of 65% interest and operatorship to Hansa Hydrocarbons in January 2011.

The following is a summary of the status of operations on these licences.

United Kingdom

Columbus Field Area - Block 23/16f – Central North Sea

Block 23/16f covers an area of approximately 52 square kilometres in the Central North Sea and contains the majority of the Columbus field, discovered by Serica in 2006. Serica operates the block and holds a 50% interest.

Serica has drilled three successful wells in the Columbus field Palaeocene Forties Formation sands in Block 23/16f and in 2009, in the adjacent Block 23/21, Lomond field operator BG International Limited ("BG") completed drilling two wells which encountered Forties sands with similar reservoir pressures to those at Columbus.

In 2010 BG carried out FEED studies for a Bridge Linked Platform ("BLP") adjacent to the Lomond platform that would provide gas and condensate reception facilities for Columbus and other fields. However, the commercial proposal that has recently emerged from BG for processing and transportation via the BLP and the Lomond field are such that Serica and its partners in Block 23/16f are continuing to evaluate alternative export routes.

Independent consultant Netherland, Sewell & Associates ("NSAI") carried out a reserves report on the Columbus field for the end of 2010. This report estimates that the gross Proved plus Probable Reserves of the field are 79.5 bcf of gas and 4.9 mm bbl of liquids, a total of 18.2 mmboe. Serica holds a 50% interest in those Columbus reserves lying in Block 23/16f and NSAI estimates that Serica's net reserves are 26.8 bcf of sales gas and 1.8 mm bbl of liquids.

Central North Sea – Block 23/16g

Following further technical review, the Block was relinquished by Serica and its joint venture partner in February 2011.

Central North Sea - Block 22/19c

In June 2009 Serica was awarded sole rights to a Production Licence over UK Central North Sea Block 22/19c in the UK 25th Round of Offshore Licensing. Block 22/19c is located approximately 20 kilometres to the west of Serica's Columbus field.

In January 2010 Serica reached agreement with Premier Oil plc ("Premier") for the farm-out of Block 22/19c. Under the terms of the farm-out agreement, Premier funded the Oates exploration well and assumed the role of operator. Serica was carried through the well and retains a 50% interest.

The Oates well 22/19c-6 was spudded on 30 July. The target of the well was the Palaeocene age Forties Sandstone, which is a significant oil and gas producing reservoir in the Central North Sea. The data acquired on the Oates well confirms that the Forties Sandstone was entered at 2,904 metres measured depth ("MD") BRT but logging indicates that no hydrocarbons are present in the sands at this location and the well was plugged and abandoned as a dry hole. Detailed analysis of the well results was undertaken to determine the reason for the apparent hydrocarbon indicators on the 3D seismic data and it appears that the specific nature of the overlying shale can produce an apparent hydrocarbon response in the Forties Sandstone reservoir. This new insight will help to reduce exploration risk in future exploration wells drilled in this play.

Central North Sea – Block 15/21g

Block 15/21g was awarded in the 25th Round of UK Offshore Licensing in 2008. Serica has a 30% interest with its partners Encore (40% interest and operator) and Nautical Petroleum (30%). It occupies an area of 33 square kilometres in the Central North Sea, immediately west of the Scott field and contains a potentially significant extension to the existing Jurassic oil discovery well 15/21-38 in Block 15/21a, which flowed 2660 bpd of 25° API oil from a good quality Jurassic aged Upper Claymore sand. The "Spaniards" prospect is a stratigraphic trap and pressure interpretation suggests that the oil column in the discovery well may extend down-dip into Block 15/21g.

The Spaniards Prospect is shared between Block 15/21g and Block 15/21a, operated by DEO Petroleum. The 15/21a and 15/21g groups are currently discussing plans to drill a joint well to test the prospect.

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

Serica was awarded a 100% interest in Blocks 113/26b and 113/27c in the UK 24th Offshore Licensing Round in 2007 and is the operator. The blocks cover an area of approximately 145 square kilometres in the East Irish Sea and lie immediately to the north of the Millom field and within ten kilometres of the Morecambe field - one of the UK's largest gas fields.

In January 2010 Serica reached agreement with Agora Oil & Gas (UK) AS ("Agora") for the farm-out of the blocks. Under the terms of the farm-out agreement, Agora funded 70% of the Conan exploration well and has earned a 35% interest in the blocks. Serica retains a 65% interest and operatorship of the blocks.

The Conan exploration well 113/26b-3 was spudded on 10 May and reached a total depth of 1,827 metres. The main reservoir target, the Triassic age Sherwood Sandstone, was encountered at 1,776 metres but no hydrocarbons were encountered and the well was plugged and abandoned. It appears that the seismic anomaly that defined the Conan prospect and that was thought to indicate the presence of hydrocarbons was related to a lithological feature not previously seen in other wells in the area.

Recently Agora assigned part of its interest to MPX Energy Ltd and plans for further exploration of the blocks are being discussed, with particular attention being paid to the Doyle prospect which has not been affected by the results of the Conan well.

Northern North Sea - Blocks 210/19a and 210/20a

In October 2010, in the 26th Round of UK Offshore Licensing, the Company was awarded a Licence over Blocks 210/19a and 210/20a in the Northern North Sea ("NNS"). Serica is the operator of the new licence and has a 100% interest.

Blocks 210/19a and 210/20a are contiguous part blocks immediately adjacent to the Otter field. A number of oil prospects have been provisionally identified on the blocks at Jurassic Brent Group and Home Sand levels. Two of the Brent Group prospects are down-faulted traps, an emerging and successful play in the NNS, and the other is a conventional Brent fault block. The fourth prospect is in a Jurassic reservoir known as the Home Sand.

The work programme includes the licensing and interpretation of 3D seismic data and Serica will make a drill or drop decision within two years of the award.

Southern North Sea – Block 48/17d

In January 2011, Serica relinquished its 65% operated interest in Block 48/17d to Hansa Hydrocarbons, the operator of the adjacent Block 48/16a which contains the Chablis discovery.

Pending UK Licences

Awards of further licences applied for by Serica in the 26th Round of UK are expected to be made when the results of environmental assessments currently being undertaken by the Department of Energy and Climate Change have been assessed.

Ireland

Slyne Basin – Licence FEL 01/06 - Blocks 27/4, 27/5 (west) and 27/9

Serica is the operator and holds a 50% interest in Licence FEL 01/06, which covers an area of 611 square kilometres in the Slyne Basin off the west coast of Ireland.

The shallow Jurassic oil discovery made by Serica in 2009 in the Bandon exploration well 27/4-1 provides clear evidence of the presence of oil in this part of the Slyne Basin although the discovery itself was not commercial. Having subsequently identified deeper Jurassic oil prospects of potentially commercial size at the Liffey and Boyne locations, Serica acquired well-site survey data in preparation for a drilling programme in 2011/12.

Rockall Basin – Licence FEL 1/09 – Blocks 5/17, 5/18, 5/22, 5/23, 5/27 and 5/28

Serica holds a 100% working interest in Licence FEL 1/09 covering six blocks in the northeastern part of the Rockall Basin off the west coast of Ireland. The six blocks cover a total area of 993 square kilometres.

The Rockall Basin has an areal extent of over 100,000 square kilometres in which only three exploration wells have been drilled to date and the basin is therefore regarded as very underexplored. Of these exploration wells the 12/2-1 Dooish gas-condensate discovery, approximately nine kilometres to the south of the licence, encountered a 214 metre hydrocarbon column.

Serica shot several new 2D long-offset seismic lines across the Muckish structure, a large exploration prospect already identified on existing 3D seismic data, and evaluation of the data has increased confidence in the potential of the prospect, which covers an area of approximately 30 square kilometers in a water depth of 1,450 metres.

Spain

The Company holds a 75% interest and operatorship in the Abiego, Barbastro, Binéfar and Peraltilla Exploration Permits onshore northern Spain. The Permits cover an area of approximately 1,100 square kilometres between the Ebro Basin and the Pyrenees.

Several gas prospects have been identified by Serica and the Company is currently seeking a farm-in partner.

Morocco

In August 2009 the Company was awarded a 25% interest in two Petroleum Agreements for the contiguous areas of Sidi Moussa and Foum Draa, offshore Morocco. The blocks together cover a total area of approximately 12,700 square kilometres in the sparsely explored Tarfaya Basin, about 100 kilometres south west of the city of Agadir.

Sidi Moussa and Foum Draa are covered by over 5,200 square kilometres of modern 3D seismic data and over 2,000 kilometres of 2D seismic data. A drill or drop decision is required to be made at the end of the initial phases of the Agreements. The initial phase of the Sidi Moussa area was due to end February 2011 and that of Foum Draa is due to end February 2012. Discussions are at an advanced stage with the Government concerning an extension of the initial phase for Sidi Moussa which is expected to be confirmed soon.

The Tarfaya Basin is geologically analogous to the oil producing salt basins of West Africa. Based on the extensive grid of existing seismic data, Serica has identified a large number of prospects and leads in the Blocks. The areas extend from the Moroccan coastline into water depths reaching a maximum of 2,000 metres.

Indonesia

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

The Glagah Kambuna Technical Assistance Contract ("TAC") covers an area of approximately 380 square kilometres and lies offshore North Sumatra. Serica holds an interest of 25% in the TAC which contains the producing Kambuna gas field.

The Kambuna gas is used for power generation to supply electricity to the city of Medan in North Sumatra and for industrial uses. The gas sales prices per thousand standard cubic feet under the contracts with PLN and Pertiwi Nusantara Resources ("Pertiwi") are currently approximately US$5.40 and US$7.00 respectively, escalated at 3% per annum. A third contract for the supply of gas for LPG attracts the same price as the PLN contract and can add up to 10% to contracted gas sales.

Kambuna gas yields significant volumes of condensate (light oil) and currently approximately 75 barrels of condensate per million standard cubic feet of sales gas are extracted. The condensate is sold to the state oil company Pertamina at the official Attaka Indonesian Crude Price less 11 cents per barrel. The Kambuna condensate lifted in December fetched a price of US$93.01/barrel with sales in February 2011 realising US$105.88/barrel.

The operational difficulties experienced by PLN soon after first gas in 2009 persisted into 2010, with contract rates not being achieved consistently until the second half. Gross Kambuna field sales were 11,278 million standard cubic feet of gas and 980,193 barrels of condensate, equivalent to gross average daily sales for the year of 31 mmscfd and 2,685 bbl/day.

By the third quarter of 2010 average gross gas sales were in excess of 40 mmscfd with all three gas buyers purchasing gas. In September 2010, average gas sales of 42 mmscfd were achieved, the highest monthly figure to date. The field was shut down for two weeks in November 2010 to complete the commissioning of the permanent production facilities, and average gas sales in December 2010 of 39 mmscfd were achieved.

In August 2010 Serica reported that the Kambuna field operator, Salamander Energy, had commissioned an independent reserves audit of its operated fields, including the Kambuna field. The operator's new estimates of reserves relied primarily on shut-in and flowing down-hole pressure data recorded in only one of the Kambuna wells during a period of interrupted production. It was noted that, if the estimates were to be confirmed by future field observations it would result in a reduction in Serica's remaining net entitlement 2P reserves as at 1 January 2010, from 6.0 mmboe to 3.4 mmboe.

Serica commissioned an independent reserves audit on the Kambuna field for its 2010 annual reserves filings. This new reserves report, carried out by RPS Energy, the same consultants as used by the operator, estimates that at 31 December 2010 the gross Proved plus Probable Reserves of the field are 28.1 bcf of sales gas and 2.3 mm bbl of condensate, a total of 8.2 mmboe. These new estimates reflect significant reductions in reserves from the figures previously reported by Serica in 2009, and occur as a result of observing a faster than anticipated pressure decline in the Kambuna 3 well. However, part of the reduction in reserves is due to the reclassification of the Upper Belumai reservoir interval as contingent resources rather than reserves. The Upper Belumai interval represented approximately 20% of the best estimate of gas initially in place in the Kambuna field made by RPS as at 31 December 2009 for Serica's 2009 annual report.

The Kambuna offshore facilities are designed to accommodate a further well which the Joint Venture has approved for drilling in 2011 to exploit the gas bearing potential of a northern extension of the field. This activity plus the planned installation of gas compression which is being brought forward, is expected to maintain the productive capacity of the field at current levels until late 2011 or early 2012.

The performance of the field will continue to be monitored throughout 2011 as further production information becomes available.

East Seruway PSC

Serica is operator and holds a 100% interest in the East Seruway PSC offshore North Sumatra, Indonesia, adjacent to the Glagah Kambuna TAC. The PSC covers an area of approximately 5,864 square kilometres which is largely unexplored.

Serica has a detailed regional understanding of the offshore North Sumatra Basin having been a PSC operator there since 2003. In 2010, the Company completed the acquisition of 2,100 line kilometres of 2D seismic data in the PSC to define further the exploration potential prior to drilling an exploration well in the block.

Serica is currently interpreting the new seismic data before drilling an exploration well in the block.

Kutai PSC

Serica is the operator of the Kutai Production Sharing Contract ("PSC") and holds a 30% interest. The PSC is divided into five blocks located in the Mahakam River delta both onshore and offshore East Kalimantan.

The interpretation of offshore 3D seismic data revealed several exploration targets. Serica secured the Trident IX jack-up drilling rig to drill the Dambus and Marindan prospects.

The Dambus-1 offshore exploration well was spudded on 4 September 2010. The objective of the well was to investigate the potential for gas and oil accumulations in a stacked sequence of Miocene sands. Dambus-1 was drilled as a deviated well to a total depth of 3,225 metres MD (2,713 metres true vertical depth subsea ("TVDSS")). Based on the indicative data obtained while drilling, hydrocarbons were encountered in clean sands in the gross interval 2,070-2,102 metres MD (1,787-1,812 metres TVDSS) and there were indications of further hydrocarbon-bearing sands in an interval below 2,760 metres MD (2,340 metres TVDSS). In order to obtain definitive data on the extent of the hydrocarbon bearing sands, the well was plugged back and sidetracked and wireline logs, pressure data and fluid samples were acquired. Sidetrack Dambus-1ST was drilled to a total depth of 2,800 metres MD (2,568 metres TVDSS). Excellent quality gas-bearing Miocene reservoir sands were encountered in the interval 2,025-2,047 metres MD (1,795-1,816 metres TVDSS) of which the net gas-bearing sands amounted to approximately 18 metres.

Following an extensive logging and sampling programme in Dambus-1ST, the deeper sands were found to be water bearing. The upper gas-bearing sands alone are not currently expected to be commercially exploitable by themselves and the well was plugged and abandoned. Other prospects and leads exist in the area around Dambus and they will be reviewed in light of the Dambus result. The gas discovered at Dambus will reduce the threshold volume required for the development of any further resources that may be discovered in the immediate area.

The Trident IX drilling rig then moved to the Marindan prospect in the southern offshore part of the PSC and the Marindan-1 well was spudded on 27 October 2010. The objective of the well was to investigate the potential for hydrocarbon accumulations in a sequence of Miocene sands and carbonates. Marindan-1 was drilled as a deviated well and on 2 December 2010 reached total depth of 3,469 metres measured depth ("MD") (3,225 metres TVDSS). High gas readings and oil shows were recorded in the interval 2,670-3,260 metres MD and downhole logs indicate thin hydrocarbon bearing sand and carbonate reservoirs, but the indicated volume of hydrocarbons present is not expected to be sufficient to justify commercial development and the well was plugged and abandoned.

Hydrocarbons have been discovered both at Marindan and Dambus, but the accumulations found in the wells are not sufficient to support standalone development. A review of options for the development of these discoveries together with other undrilled prospects in the Kutai PSC is currently underway.

Forward Programme

Serica has an active exploration and field development programme for 2011.

In the UK, efforts continue to bring the Columbus field to project sanction. Negotiations are ongoing with BG with a view to securing acceptable terms for offtake via the Lomond platform but, in the event that agreement is not reached, the 23/16f partners are developing alternative offtake solutions. In Block 15/21g a well is planned on the Spaniards prospect, subject to agreement with the partners on the neighbouring Block 15/21a. The Spaniards prospect straddles both blocks. In the East Irish Sea, the possibility of drilling the Doyle prospect in Block 113/27c is under review.

In Ireland, plans are in hand to drill two wells on the Boyne and Liffey prospects which have been identified following the discovery of oil in the 2009 Bandon well drilled by Serica. Due to the costs involved in drilling Boyne and Liffey the Company is seeking a partner before the wells are drilled and, with the short drilling season in the Irish Atlantic, the wells are therefore more likely to be drilled in 2012 than in 2011.

In Spain our Permit areas are under review by a potential farminee and, if terms can be agreed, a commitment to drill an exploration well will be given to the Spanish authorities.

In Morocco we have identified a large number of prospects in our offshore acreage and we anticipate that at least one of the licences will be extended into the second exploration period in which a well will be drilled.

In Indonesia, a well is planned to exploit the gas bearing potential of a northern extension of the Kambuna field. If this well is successful, it will increase field reserves and, together with the installation of compression facilities, will extend Kambuna field plateau production rates. This well is scheduled to be drilled in the second half of 2011. In the adjacent East Seruway Block, an exploration well is scheduled for the end of 2011 or early 2012. In the Kutai PSC area, an onshore well commitment is outstanding but we have so far been unable to secure a drilling permit from the Forestry authorities. Serica is continuing to analyse the results of the 2010 offshore drilling campaign in order to determine the future offshore programme.

Serica has identified new areas which it believes hold greater prospects for growth and it will continue to pursue these opportunities throughout 2011. In November 2010 the Company announced a strategic review of its Indonesian assets. As a result of this review the Company is evaluating proposals from interested parties which may lead to a disposal of these properties. Any funds raised would be invested in new ventures where the Company sees greater potential.

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)
boepd barrels of oil equivalent per day
bopd or bpd barrels of oil or condensate per day
FPSO Floating Production, Storage and Offtake vessel (often a converted oil tanker)
LNG Liquefied Natural Gas (mainly methane and ethane)
LPG Liquefied Petroleum Gas (mainly butane and propane)
mcf thousand cubic feet
mm bbl million barrels
mmboe million barrels of oil equivalent
mmBtu million British Thermal Units
mmscfd million standard cubic feet per day
PSC Production Sharing Contract
Proved
Reserves
Proved reserves are those Reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
Probable
Reserves
Probable reserves are those additional Reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved + probable reserves.
Possible
Reserves
Possible reserves are those additional Reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved + probable + possible reserves
Reserves Estimates of discovered recoverable commercial hydrocarbon reserves calculated in accordance with the Canadian National Instrument 51-101
Contingent
Resources
Estimates of discovered recoverable hydrocarbon resources for which commercial production is not yet assured, calculated in accordance with the Canadian National Instrument 51-101
Prospective
Resources
Estimates of the potential recoverable hydrocarbon resources attributable to undrilled prospects, calculated in accordance with the Canadian National Instrument 51-101
TAC Technical Assistance Contract
tcf trillion standard cubic feet

FINANCIAL REVIEW

Results of Operations

The results of Serica's operations detailed below in this MD&A, and in the financial statements, are presented in accordance with International Financial Reporting Standards ("IFRS").

Serica generated a loss of US$44.2 million for 2010 compared to a profit of US$5.8 million for 2009.

Continuing operations 2010     2009  
  US$000     US$000  
           
Sales revenue 31,302     7,643  
           
Cost of sales (18,758 )   (6,376 )
           
Gross profit 12,544     1,267  
           
Expenses:          
           
  Impairment of fixed assets and goodwill (11,797 )   -  
  Pre-licence costs (1,924 )   (901 )
  E&E asset and other write offs (29,486 )   (8,590 )
  Administrative expenses (7,353 )   (6,639 )
  Foreign exchange gain 55     228  
  Share-based payments (1,231 )   (1,687 )
  Depreciation (137 )   (118 )
           
Operating loss before net finance revenue and tax (39,329 )   (16,440 )
           
  Profit on disposal -     26,864  
  Finance revenue 174     641  
  Finance costs (4,083 )   (3,754 )
           
(Loss)/profit before taxation (43,238 )   7,311  
           
Taxation charge for the year (979 )   (1,531 )
           
           
(Loss)/profit for the year (44,217 )   5,780  
           
Earnings/(loss) per ordinary share - EPS          
Basic and diluted EPS on (loss)/profit for the year (US$) (0.25 )   0.03  

Serica generated a gross profit of US$12.5 million for the year ended 31 December 2010 from its retained 25% interest in the Kambuna Field.

The Company generated its first sales revenue from the Kambuna field in Indonesia during Q3 2009. Revenue is recognised on an entitlement basis for the Company's net working field interest. All revenue in 2010 was generated from a 25% field interest, revenues for Q3 and Q4 2009 were generated from a 50% field interest until mid December 2009 when a 25% interest in the asset was disposed of to KrisEnergy Limited.

In 2010, gross Kambuna field gas production averaged 31 mmscf per day together with average condensate production of 2,685 barrels per day. Field commissioning work was completed in Q4 2010. The 2010 gas production was sold at prices averaging US$5.88 per Mscf (2009 US$5.48 per Mscf) and generated US$15.3 million (2009 US$4.0 million) of revenue net to Serica. Condensate production is stored and sold when lifted at a price referenced to the Indonesia Attaka official monthly crude oil price. Liftings in the year earned US$16.0 million (2009 US$3.6 million) of revenue net to Serica at an average price of US$80.8 per barrel (2009 US$72.1 per barrel).

Cost of sales for 2010 were driven by production from the Kambuna field and totalled US$18.8 million (2009 US$6.4 million). The charge comprised direct operating costs of US$7.6 million (2009 US$4.5 million) and non cash depletion of US$11.5 million (2009 US$2.2 million), partially offset by an increase in condensate inventory of US$0.3 million (2009 US$0.3 million). The direct operating costs included temporary Early Production Facility charges of US$2.3 million which were incurred until the completion of the permanent Onshore Receiving Facility in the fourth quarter 2010. The direct operating costs and depletion rose as a result of increased production from the Kambuna field. Depletion charges per boe increased significantly in Q4 2010 following the Kambuna field reserves downgrade announced in the operating review.

The Company generated a loss before tax of US$43.2 million for 2010 compared to a profit before tax of US$7.3 million for 2009.

The overall 2010 loss before tax included a US$11.8 million pre-tax impairment of the Kambuna asset and US$29.5 million of Exploration and Evaluation (E&E) and other asset write offs which are discussed below. The 2009 profit before tax included a profit on disposal of US$26.9 million.

The US$11.8 million pre-tax impairment related to the Kambuna field and resulted from the reserves downgrade. The impairment is recorded against oil and gas property, plant and equipment (US$11.7 million) and goodwill (US$0.1 million).

Pre-licence costs included direct costs and allocated general administrative costs incurred on oil and gas activities prior to the award of licences, concessions or exploration rights. The expense of US$1.9 million for 2010 was significantly higher than the 2009 charge of US$0.9 million. The increase largely arose from the work undertaken during Q2 2010 on the 26th Licensing Round in the UK and during Q4 2010 on other new ventures in the Western Hemisphere. During 2010 the Company was awarded interests in Blocks 210/19a and 210/20a in the UK Northern North Sea and is awaiting the outcome of other applications.

Asset write offs in 2010 of US$29.5 million (2009 of US$8.6 million) included E&E asset expenses from the Kutai PSC in Indonesia (US$24.3 million) and Oates in the UK North Sea (US$3.5 million). The Management's decision to write off Kutai costs follows the impairment of the Kambuna field, whose reserves had previously covered the carrying cost of the Company's SE Asia assets. The Management's decision to write off the costs of the Oates prospect follows the unsuccessful well and the absence of any further drilling plans for the block. Other write offs included costs from relinquished licences and sundry items. The asset write off of US$8.6 million during 2009 was primarily allocated to the Chablis block (US$7.1 million).

Administrative expenses of US$7.4 million for 2010 increased from US$6.6 million for 2009. The Company continues to manage carefully its financial resources and the increase reflects greater corporate activity in the year compared to 2009.

The impact of foreign exchange was not significant in 2010 or 2009.

Share-based payment costs of US$1.2 million reflected share options granted and compare with US$1.7 million for 2009. Whilst further share options were granted in January 2010, the incremental charge generated from those options has been offset by the decline in charges for options granted in prior years. Included within the respective annual charges are expenses of US$0.8 million (Q4 2009) and US$0.2 million (Q1 2010) arising from the extension of certain existing share options in December 2009. The extension of certain existing share options in November 2010 created a charge of US$0.1 million that was fully expensed in Q4 2010 and included within the 2010 annual charge.

Negligible depreciation charges in all periods represent office equipment and fixtures and fittings. The depletion and amortisation charge for Kambuna field development costs is recorded within 'Cost of Sales'.

The 2009 profit on disposal of US$26.9 million was generated in December 2009 when the Company disposed of a package of assets in South East Asia (comprising a 25% interest in the Kambuna TAC, a 24.6% interest in the Kutai PSC and the Company's entire 33.3% interest in the Block 06/94 PSC, Vietnam) to KrisEnergy Limited.

Finance revenue for 2010, comprising interest income of US$0.2 million, compares with US$0.6 million for 2009. The majority of finance revenue was earned in Q1 2010 and Q4 2009 and arose from interest earned on the consideration from the South East Asia asset disposal noted above. Bank deposit interest income has been negligible in 2010 and 2009 due to the significant reduction in average interest rate yields available since 2H 2008.

Finance costs consist of interest payable, arrangement costs spread over the term of the bank loan facility and other fees. Finance costs directly related to the Kambuna development were capitalised until the field commenced commercial production during Q3 2009.

The taxation charge of US$1.0 million (2009 US$1.5 million) arose from Indonesian operations, and comprised a deferred tax credit of US$0.1 and a current tax charge of US$1.1 million.

The net loss per share of US$0.25 for 2010 compares to net earnings per share of US$0.03 for 2009.

Summary of Quarterly Results              
               
Quarter ended: 31 Mar   30 Jun   30 Sep   31 Dec  
  US$000   US$000   US$000   US$000  
2010                
Sales revenue 5,334   6,537   10,018   9,413  
(Loss)/profit for the quarter (2,740 ) (1,646 ) 281   (40,112 )
Basic earnings per share US$ (0.02 ) (0.01 ) 0.002   (0.22 )
Diluted earnings per share US$ (0.02 ) (0.01 ) 0.002   (0.22 )
                 
                 
2009                
Sales revenue -   -   4,167   3,476  
(Loss)/profit for the quarter (9,938 ) (2,504 ) (926 ) 19,148  
Basic earnings per share US$ (0.06 ) (0.01 ) (0.01 ) 0.11  
Diluted earnings per share US$ (0.06 ) (0.01 ) (0.01 ) 0.11  
                 

The fourth quarter 2010 loss includes asset write offs of US$29.5 million attributed to the Kutai and Oates E&E assets and an impairment charge of US$11.8 against the Kambuna development and production asset.

The fourth quarter 2009 profit includes a profit of US$26.9 million generated on the disposal of a 25% interest in the Kambuna field, Indonesia and certain E&E asset interests in South East Asia.

The third quarter 2009 result includes first revenue streams from the Kambuna field.

The first quarter 2009 loss includes asset write offs of US$7.1 million on the Chablis asset.

Working Capital, Liquidity and Capital Resources

Current Assets and Liabilities

An extract of the balance sheet detailing current assets and liabilities is provided below:

  31 December
2010
    31 December
2009
 
  US$000     US$000  
Current assets:          
  Inventories 2,748     2,855  
  Trade and other receivables 14,669     106,381  
  Financial assets -     1,500  
  Cash and cash equivalents 30,002     18,412  
Total Current assets 47,419     129,148  
           
Less Current liabilities:          
  Trade and other payables (13,574 )   (9,231 )
  Income tax payable (1,466 )   (391 )
  Financial liabilities (11,671 )   (46,447 )
Total Current liabilities (26,711 )   (56,069 )
           
Net Current assets 20,708     73,079  

At 31 December 2010, the Company had net current assets of US$20.7 million which comprised current assets of US$47.4 million less current liabilities of US$26.7 million, giving a significant overall decrease in working capital of US$52.4 million in the year.

Inventories decreased from US$2.9 million to US$2.7 million over the year.

Trade and other receivables at 31 December 2010 totalled US$14.7 million, which included US$5.5 million of trade debtors from gas and condensate sales in November and December. Other significant items included US$1.6 million for the Company's share of a rig deposit for the Kutai drilling programme, other advance payments on ongoing operations, recoverable amounts from partners in joint venture operations in the UK and Indonesia, sundry UK and Indonesian working capital balances, and prepayments. The significant decrease from the 2009 year end debtor balance of US$106.4 million was largely caused by the receipt of cash proceeds in January 2010 from the disposal of assets to KrisEnergy Limited in December 2009. All trade debtors outstanding at Q4 2010 were received in Q1 2011.

Financial assets at 31 December 2009 represented US$1.5 million of restricted cash deposits which were utilised during Q1 2010.

Cash and cash equivalents increased from US$18.4 million to US$30.0 million in the year. In January 2010, the Company received US$99.2 million in outstanding consideration from KrisEnergy and it repaid US$60.7 million in gross drawings on its loan facility in the year. During 2010 the Company generated US$31.3 million of revenues from the Kambuna field but also incurred ongoing field operating costs and exploration drilling expense on two wells in Indonesia and the Conan well in the UK. Other costs included seismic work across the portfolio in Indonesia and Ireland, Columbus Field Development Plan expense together with ongoing administrative costs and corporate activity.

Trade and other payables of US$13.6 million at 31 December 2010 chiefly include significant trade creditors and accruals from the 2010 Kutai offshore drilling progamme and the completion of the permanent production facilities of the Kambuna field. Other items include sundry creditors and accruals from the ongoing Indonesian and UK exploration programmes, payables for administrative expenses and other corporate costs.

The current tax creditor of US$1.5 million arises in respect of Indonesian operations.

Financial liabilities comprise drawings under the senior debt facility and are disclosed net of the unamortised portion of allocated issue costs. The balance was classified as short-term as at 31 December 2010 and was fully repaid in February 2011.

Long-Term Assets and Liabilities

An extract of the balance sheet detailing long-term assets and liabilities is provided below:

  31 December
2010
    31 December
2009
 
  US$000     US$000  
           
Exploration and evaluation assets 68,604     66,030  
Property, plant and equipment 37,546     53,864  
Goodwill -     148  
Financial assets 1,431     -  
Long-term other receivables 4,748     5,639  
Financial liabilities -     (24,371 )
Provisions (1,706 )   -  
Deferred income tax liabilities (1,339 )   (1,435 )

During 2010, total investments in petroleum and natural gas properties represented by exploration and evaluation assets ("E&E assets") increased from US$66.0 million to US$68.6 million. These amounts exclude the Kambuna development and production costs which are classified as property, plant and equipment.

The net US$2.6 million increase consists of US$30.6 million of additions, less US$27.8 million of asset write-offs and US$0.2 million of relinquished licence costs. 2010 write-offs were charged against the Kutai (US$24.3 million) and Oates (US$3.5 million) assets.

The US$30.6 million of additions were incurred on the following assets:

In Indonesia, US$16.3 million was incurred on the Kutai PSC, chiefly on the Dambus and Marindan exploration wells, and US$4.1 million was spent on exploration work and G&A on the East Seruway concession.

In the UK & Western Europe, US$3.6 million was incurred on the Company's share of drilling the Conan well in the East Irish Sea, US$3.9 million on the Columbus FDP (including FEED work on the BLP), US$0.5 million on a site survey in Ireland and US$2.0 million on other UK and Ireland exploration work and G&A. The Company's share of drilling costs on the Oates prospect in Block 22/19c was borne by a third party following the farm-out announced in Q1 2010. US$0.3 million was incurred on the Morocco interests.

Property, plant and equipment chiefly comprise the net book amount of the capital expenditure on the Company's interest in the Kambuna development. During 2010, the Company's investment decreased from US$53.8 million to US$36.7 million. This US$17.1 million decrease comprised depletion charges of US$11.5 million arising from the production of gas and condensate, and the Q4 2010 impairment of US$11.6 million, partially offset by US$4.3 million of capex additions in the year and the decommissioning asset of US$1.7 million set up in Q4 2010 to correspond with the booked decommissioning liability. The property, plant and equipment also included balances of US$0.8 million (2009: US$0.1 million) for office fixtures and fittings and computer equipment.

Goodwill, representing the difference between the price paid on acquisitions and the fair value applied to individual assets, was impaired following the downgrade in Kambuna reserves and reduced from US$0.1 million to US$nil.

Financial assets at 31 December 2010 represented US$1.4 million of restricted cash deposits.

Long-term other receivables of US$4.7 million are represented by value added tax ("VAT") on Indonesian capital spend which will be recovered from future production.

Financial liabilities as at 31 December 2009 represented by drawings under the senior secured debt facility are disclosed net of the unamortised portion of allocated issue costs.

Provisions of US$1.7 million at 31 December 2010 are in respect of Kambuna field decommissioning payments in Indonesia.

The deferred income tax liability of US$1.3 million arises in respect of the Company's retained Kambuna asset interest in Indonesia.

Shareholders' Equity

An extract of the balance sheet detailing shareholders' equity is provided below:

  31 December
2010
    31 December
2009
 
  US$000     US$000  
           
Total share capital 207,657     207,633  
Other reserves 18,428     17,197  
Accumulated deficit (96,093 )   (51,876 )

Total share capital includes the total net proceeds, both nominal value and any premium, on the issue of equity capital.

Other reserves mainly include amounts credited in respect of cumulative share-based payment charges. The increase in other reserves from US$17.2 million to US$18.4 million reflects a credit to equity in respect of share-based payment charges in 2010.

Asset values and Impairment

At 31 December 2010 Serica's market capitalisation stood at US$122 million (£79 million), based upon a share price of £0.445, which was exceeded by the net asset value at that date of US$130 million. By 29 March 2010 the Company's market capitalisation had decreased to US$110 million. Management conducted a thorough review of the carrying value of its assets and determined that no further write-downs were required beyond those already disclosed above.

Capital Resources

Available financing resources and debt facility

Serica's prime focus has been to deliver value through exploration success. To-date this has given rise to the Kambuna gas field development in Indonesia, with first production achieved in August 2009, and the Columbus gas field in the UK North Sea, for which development plans are being formulated.

Typically exploration activities are equity financed whilst field development costs are principally debt financed. In the current business environment, access to new equity and debt remains uncertain. Consequently, the Company has given priority to the careful management of existing financial resources. The production from Kambuna complements the Company's exploration activities with sales revenues and reweights the balance from investment to income generation.

In November 2009 the Company replaced its US$100 million debt facility with a new three-year facility for an equal amount. The new facility, which was arranged with J.P.Morgan plc, Bank of Scotland plc and Natixis as Mandated Lead Arrangers, was principally to refinance the Company's outstanding borrowings on the Kambuna field. It was also put in place to finance the appraisal and development of the Columbus field and for general corporate purposes.

In January 2010 the Company received the proceeds from the disposal of assets to Kris Energy and repaid US$47.6 million of its debt, and at 31 December 2010, the Company held cash and cash equivalents of US$30.0 million and US$1.4 million of restricted cash. Following the debt repayments in the year, management decided to reduce the facility to US$50 million total capacity so as to restrict ongoing facility costs. The ability to draw under the facility for development is determined both by the achievement of milestones on the relevant project and also by the availability calculated under a projection model.

As of 29 March 2011, the Company's debt facility was fully repaid, leaving a net cash position of approximately US$21.0 million.

Overall, the current cash balances held, the revenues from the retained 25% Kambuna interest and the control that the Company can exert over the timing and cost of its exploration programmes both through operatorship and through farm-outs leave it well placed to manage its commitments.

Summary of contractual obligations

The following table summarises the Company's contractual obligations as at 31 December 2010;

       
  Total <1 year 1-3 years >3 years
Contractual Obligations US$000 US$000 US$000 US$000
         
Long term debt 11,800 11,800 - -
Operating leases 1,330 609 721 -
Other long term obligations 1,826 260 696 870
         
Total contractual obligations 14,956 12,669 1,417 870

Lease commitments

At 31 December 2010, Serica had no capital lease obligations. At that date, the Company had commitments to future minimum payments under operating leases in respect of rental office premises and office equipment for each of the following years as follows:

  US$000
31 December 2011 609
31 December 2012 539

Capital expenditure commitments, obligations and plans

As at 31 December 2010, the Company's share of expected outstanding capital costs in respect of its 25% interest on the Kambuna project totalled approximately US$2.0 million. These expected costs include amounts contracted for but not provided as at 31 December 2010.

In addition, the Company also has obligations to carry out defined work programmes on its oil and gas properties, under the terms of the award of rights to these properties, over the next two years as follows:

Year ending 31 December 2011 US$ 11,250,000
Year ending 31 December 2012 US$ nil

These obligations reflect the Company's share of the defined work programmes and were not formally contracted at 31 December 2010. The Company is not obliged to meet other joint venture partner shares of these programmes. The most significant 2011 obligations are in respect of the East Seruway PSC and Kutai PSC in Indonesia. Other less material minimum obligations include G&G, seismic work and ongoing licence fees in the UK and Indonesia.

Off-Balance Sheet Arrangements

The Company has not entered into any off-balance sheet transactions or arrangements.

Critical Accounting Estimates

The Company's significant accounting policies are detailed in note 2 to the attached audited 2010 financial statements. International Financial Reporting Standards have been adopted. The costs of exploring for and developing petroleum and natural gas reserves are capitalised and the capitalisation and any write off of E&E assets, or depletion of producing assets necessarily involve certain judgments with regard to whether the asset will ultimately prove to be recoverable. Key sources of estimation uncertainty that impact the Company relate to assessment of commercial reserves and the impairment of the Company's assets. Oil and gas properties are subject to periodic review for impairment whilst goodwill is reviewed at least annually. Impairment considerations necessarily involve certain judgements as to whether E&E assets will lead to commercial discoveries and whether future field revenues will be sufficient to cover capitalised costs. Recoverable amounts can be determined based upon risked potential, or where relevant, discovered oil and gas reserves. In each case, recoverable amount calculations are based upon estimations and management assumptions about future outcomes, product prices and performance. 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.

Financial Instruments

The Group's financial instruments comprise cash and cash equivalents, bank loans and borrowings, accounts payable and accounts receivable. It is management's opinion that the Group is not exposed to significant interest or credit or currency risks arising from its financial instruments other than as discussed below:

  Serica has exposure to interest rate fluctuations on its cash deposits and its bank loans; given the level of expenditure plans over 2011/12 this is managed in the short-term through selecting treasury deposit periods of one to three months. Treasury counterparty credit risks are mitigated through spreading the placement of funds over a range of institutions each carrying acceptable published credit ratings to minimise counterparty risk.
   
  Where Serica operates joint ventures on behalf of partners it seeks to recover the appropriate share of costs from these third parties. The majority of partners in these ventures are well established oil and gas companies. In the event of non payment, operating agreements typically provide recourse through increased venture shares.
   
  Serica retains certain cash holdings and other financial instruments relating to its operations, limited to the levels necessary to support those operations. The US$ reporting currency value of these may fluctuate from time to time causing reported foreign exchange gains and losses. Serica maintains a broad strategy of matching the currency of funds held on deposit with the expected expenditures in those currencies. Management believes that this mitigates much of any actual potential currency risk from financial instruments. Loan funding is available in US Dollars and Pounds Sterling and is drawn in the currency required.

It is management's opinion that the fair value of its financial instruments approximate to their carrying values, unless otherwise noted.

Share Options

As at 31 December 2010, the following director and employee share options were outstanding:

  Expiry Date Amount Exercise cost
      Cdn$
  December 2014 200,000 200,000
  January 2015 600,000 600,000
  June 2015 1,100,000 1,980,000
       
      Exercise cost
      £
  August 2012 1,200,000 1,182,000
  October 2013 750,000 300,000
  January 2014 656,000 209,920
  November 2015 (i) 334,000 323,980
  November 2015 117,000 113,490
  January 2016 1,275,000 1,319,625
  May 2016 180,000 172,800
  June 2016 270,000 259,200
  November 2016 120,000 134,400
  January 2017 723,000 737,460
  May 2017 405,000 421,200
  March 2018 1,581,000 1,185,750
  March 2018 850,000 697,000
  January 2020 4,153,500 2,824,380
  June 2020 250,000 162,500
   
 (i) In November 2010 options held under the Serica Energy PLC Enterprise Management Incentive Plan (the EMI Plan) were extended for a further five years to November 2015.

In January 2010, 2,175,000 share options were granted to executive directors with an exercise cost of £0.68 and an expiry date of 10 January 2020. The exercise of the options is subject to certain performance criteria as set out in the Directors' Report. Also in January 2010, 2,028,500 share options were granted to certain employees other than directors with an exercise cost of £0.68 and an expiry date of 10 January 2020. Exercise of certain of the options granted to executive directors and employees is conditional on shares purchased in the Company being retained for a period of one year from the date of purchase in January 2010. The options granted in January 2010 cannot be exercised until three years from the date of grant.

In April 2010, 52,000 share options were exercised by employees other than directors at a price of £0.32.

In January 2011, 90,000 share options were exercised by employees other than directors at a price of £0.32.

Outstanding Share Capital

As at 29 March 2011, the Company had 176,660,311 ordinary shares issued and outstanding.

Business Risk and Uncertainties

Serica, like all companies in the oil and gas industry, operates in an environment subject to inherent risks. Many of these risks are beyond the ability of a company to control, particularly those associated with the exploring for and developing of economic quantities of hydrocarbons. Principal risks can be classified into four main categories: operational, commercial, regulatory and financial.

Operational risks include production interruptions, well or reservoir performance, spillage and pollution, drilling complications, delays and cost over-run on major projects, well blow-outs, failure to encounter hydrocarbons, construction risks, equipment failure and accidents. Commercial risks include access to markets, access to infrastructure, volatile commodity prices and counterparty risks. Regulatory risks include governmental regulations, licence compliance and environmental risks. Financial risks include access to equity funding and credit.

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.

Nature and Continuance of Operations

The principal activity of the Company is to identify, acquire and subsequently exploit oil and gas reserves. Its current activities are located primarily in Western Europe, North Africa and Indonesia.

The Company's financial statements have been prepared with the assumption that the Company will be able to realise its assets and discharge its liabilities in the normal course of business rather than through a process of forced liquidation. During the year ended 31 December 2010 the Company generated a loss of US$44.2 million from continuing operations. At 31 December 2010 the Company had US$18 million of net cash.

The Company intends to utilise its existing cash balances and future operating cash inflows, together with the currently available portion of the US$50 million senior secured debt facility, to fund the immediate needs of its investment programme and ongoing operations. Further details of the Company's financial resources and debt facility are given above in the Financial Review in this MD&A.

Additional Information

Additional information relating to Serica, including the Company's annual information form, 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

Paul Ellis Christopher Hearne
Chief Executive Officer Finance Director

30 March 2011

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
             
      2010   2009  
  Notes   US$000   US$000  
             
Sales revenue 4   31,302   7,643  
             
Cost of sales 5   (18,758 ) (6,376 )
             
Gross profit     12,544   1,267  
             
Impairment of fixed assets and goodwill 16,17   (11,797 ) -  
Pre-licence costs     (1,924 ) (901 )
E&E and other asset write offs 15   (29,486 ) (8,590 )
Administrative expenses     (7,353 ) (6,639 )
Foreign exchange gain     55   228  
Share-based payments 29   (1,231 ) (1,687 )
Depreciation 7   (137 ) (118 )
             
Operating loss before net finance revenue and tax     (39,329 ) (16,440 )
             
Profit on disposal 10   -   26,864  
Finance revenue 11   174   641  
Finance costs 12   (4,083 ) (3,754 )
             
(Loss)/profit before taxation     (43,238 ) 7,311  
             
Taxation charge for the year 13 a ) (979 ) (1,531 )
             
(Loss)/profit for the year     (44,217 ) 5,780  
             
             
(Loss)/profit per ordinary share - EPS            
Basic and diluted EPS on (loss)/profit for the year (US$) 14   (0.25 ) 0.03  
Basic and diluted EPS – continuing operations (US$) 14   (0.25 ) 0.03  

Group Statement of Comprehensive Income

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

Serica Energy plc
Balance Sheet
As at 31 December
 
    Group       Company      
    2010   2009   2010   2009  
  Notes US$000   US$000   US$000   US$000  
Non-current assets                  
Exploration & evaluation assets 15 68,604   66,030   -   -  
Property, plant and equipment 16 37,546   53,864   -   -  
Goodwill 17 -   148   -   -  
Investments in subsidiaries 18 -   -   11,830   130,684  
Financial assets 19 1,431   -   1,431   -  
Other receivables 19 4,748   5,639   -   -  
    112,329   125,681   13,261   130,684  
Current assets                  
Inventories 20 2,748   2,855   -   -  
Trade and other receivables 21 14,669   106,381   123,302   211,664  
Financial assets 21 -   1,500   -   1,500  
Cash and cash equivalents 22 30,002   18,412   26,696   16,922  
    47,419   129,148   149,998   230,086  
                   
TOTAL ASSETS   159,748   254,829   163,259   360,770  
                   
Current liabilities                  
Trade and other payables 23 (13,574 ) (9,231 ) (939 ) (6,569 )
Income taxation payable 13 (1,466 ) (391 ) -   -  
Financial liabilities 24 (11,671 ) (46,447 ) (11,671 ) (46,447 )
                   
Non-current liabilities                  
Financial liabilities 24 -   (24,371 ) -   (24,371 )
Provisions 25 (1,706 ) -   -   -  
Deferred income tax liabilities 13d) (1,339 ) (1,435 ) -   -  
                   
TOTAL LIABILITIES   (29,756 ) (81,875 ) (12,610 ) (77,387 )
                   
NET ASSETS   129,992   172,954   150,649   283,383  
                   
Share capital 27 207,657   207,633   172,385   172,361  
Merger reserve 18 -   -   4,322   112,174  
Other reserves   18,428   17,197   18,428   17,197  
Accumulated deficit   (96,093 ) (51,876 ) (44,486 ) (18,349 )
                   
TOTAL EQUITY   129,992   172,954   150,649   283,383  

Approved by the Board on 30 March 2011

Paul Ellis Christopher Hearne
Chief Executive Officer Finance Director
   
Serica Energy plc
Statement of Changes in Equity
For the year ended 31 December 2010
 
Group Share
capital
Other
reserves
Accum'd
deficit
  Total  
  US$000 US$000 US$000   US$000  
             
At 1 January 2009 207,633 15,510 (57,656 ) 165,487  
             
Profit for the year - - 5,780   5,780  
Total comprehensive income - - 5,780   5,780  
Share-based payments - 1,687 -   1,687  
             
At 31 December 2009 207,633 17,197 (51,876 ) 172,954  
             
Loss for the year - - (44,217 ) (44,217 )
Total comprehensive income - - (44,217 ) (44,217 )
Share-based payments - 1,231 -   1,231  
Proceeds on exercise of options 24 - -   24  
             
At 31 December 2010 207,657 18,428 (96,093 ) 129,992  
             
Company Share
capital

Merger
reserve
  Other
reserve
Accum'd
deficit
  Total  
  US$000 US$000   US$000 US$000   US$000  
                 
At 1 January 2009 172,361 112,174   15,510 (12,718 ) 287,327  
                 
Loss for the year - -   - (5,631 ) (5,631 )
Total comprehensive income - -   - (5,631 ) (5,631 )
Share-based payments - -   1,687 -   1,687  
                 
At 31 December 2009 172,361 112,174   17,197 (18,349 ) 283,383  
                 
Loss for the year - -   - (133,989 ) (133,989 )
Total comprehensive income - -   - (133,989 ) (133,989 )
Proceeds on exercise of options 24 -   - -   24  
Share-based payments - -   1,231 -   1,231  
Transfers - (107,852 ) - 107,852   -  
                 
At 31 December 2010 172,385 4,322   18,428 (44,486 ) 150,649  
                 
Serica Energy plc
Cash Flow Statement
For the year ended 31 December
 
  Group
2010
US$000
  2009
US$000
  Company
2010
US$000
  2009
US$000
 
Operating activities:                
(Loss)/profit for the year (44,217 ) 5,780   (133,989 ) (5,631 )
Adjustments to reconcile (loss)/profit for the year to net cash flow from operating activities                
Taxation 979   1,531   -   -  
Net finance costs 3,909   3,113   3,488   1,350  
Profit on disposal -   (26,864 ) -   -  
Depreciation 137   118   -   -  
Depletion and amortisation 11,479   2,227   -   -  
Asset write offs 29,486   8,590   -   -  
Impairment 11,797   -   126,193   -  
Share-based payments 1,231   1,687   1,231   1,687  
(Increase)/decrease in trade and other receivables (9,152 ) (7,810 ) 104   209  
Decrease in inventories 177   40   -   -  
Increase/(decrease) in trade and other payables 4,343   (2,232 ) (546 ) (1,573 )
                 
Net cash flow from operations 10,169   (13,820 ) (3,519 ) (3,958 )
                 
Investing activities:                
Interest received 765   50   58   43  
Purchase of property, plant and equipment (5,241 ) (41,609 ) -   -  
Purchase of E&E assets (30,569 ) (22,976 ) -   -  
Proceeds from disposals 99,532   5,000   -   -  
Funding provided to Group subsidiaries -   -   (23,263 ) (53,662 )
Funds from Group subsidiaries -   -   99,532   -  
Net cash flow from investing activities 64,487   (59,535 ) 76,327   (53,619 )
                 
Financing activities:                
Finance costs paid (2,313 ) (5,360 ) (2,313 ) (3,526 )
Proceeds on exercise of options 24   -   24   -  
Proceeds from loans and borrowings -   40,144   -   40,144  
Repayments of loans and borrowings (60,700 ) -   (60,700 ) -  
Net cash from financing activities (62,989 ) 34,784   (62,989 ) 36,618  
                 
Net increase/(decrease) in cash and cash equivalents 11,667  
(38,571
) 9,819  
(20,959
)
Effect of exchange rates on cash and cash equivalents (77 ) 161   (45 ) 123  
Cash and cash equivalents at 1 January 18,412   56,822   16,922   37,758  
                 
Cash and cash equivalents at 31 December 30,002   18,412   26,696   16,922  

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 2010 were authorised for issue by the Board of Directors on 30 March 2011 and the balance sheets were signed on the Board's behalf by Paul Ellis and Chris Hearne and will be delivered to the registrar in due course. 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 primarily in Western Europe, North Africa and Indonesia. 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 2010. 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 2010 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$133,989,000 (2009: US$5,631,000).

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 2010.

The Group and Company financial statements are presented in US dollars and 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 available debt facilities are described in the Financial Review above. As at 31 December 2010 the Group had US$18 million of net cash and, by 29 March 2011, the Company had US$21 million of net cash.

The Directors are required to consider the availability of resources to meet the Group and Company's liabilities for the forseeable future. As described in the MD&A, the current business environment is challenging and access to new equity and debt remains uncertain. However, the management considers that it will not require recourse to either to cover its existing commitments.

This is based upon the following factors: operating cash inflows are being generated from the Kambuna field; gas sales contracts for Kambuna are in place at fixed prices and any fluctuations in condensate prices will be largely offset by variations in cost recovery entitlement; the Company has a record of prudent financial management, including the raising of capital through farm down and the sale of part of its Kambuna field interest; and, the Company has an established relationship with its existing banking syndicate. The option of further asset sales is also open to the Company.

After making enquiries and having taken into consideration the above factors, the Directors have a 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 goodwill, oil & gas development assets and E&E assets), decommissioning provisions, share-based payment costs and the assessment of the status of the Group's Indonesian operations review.

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.

Decommissioning provisions

Management has determined that, based on their understanding of the contractual agreements they are party to in Indonesia, the Company has a constructive obligation to incur future decommissioning costs as at 31 December 2010. However these assumptions involve judgement, which may be subject to change, and therefore the position will be reviewed on an ongoing basis. A change in circumstances may result in a change to the liability being recorded in future periods.

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 29).

Indonesian Assets

In late 2010 the Company initiated a strategic review of its Indonesian assets and is currently in discussion with interested parties which may result in the disposal of these assets. However, as such a disposal could not be categorised as 'highly probable' at 31 December 2010, these assets did not meet the relevant criteria to be classified as 'assets held for re-sale under IFRS 5. The disposal was not considered highly probable at that point as the management was not committed to a particular course of action and a disposal would not be concluded if any offers were not to prove sufficiently attractive to the Company.

Basis of Consolidation

The consolidated financial statements include the accounts of Serica Energy plc (the "Company") and its wholly owned subsidiaries Serica Energy Corporation, Serica Energy Holdings B.V., Asia Petroleum Development Limited, Petroleum Development Associates (Asia) Limited, Serica Energia Iberica S.L., Serica Holdings UK Limited, Serica Energy (UK) Limited, PDA Lematang Limited, APD (Asahan) Limited, APD (Biliton) Limited, Serica Energy Pte Limited, Serica Kutei B.V., Serica Glagah Kambuna B.V., Serica East Seruway B.V., Serica Indonesia Holdings B.V., Serica Sidi Moussa B.V. and Serica Foum Draa B.V.. 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.

Business combinations prior to 1 January 2010

Business combinations are accounted for using the purchase method of accounting. The purchase price of an acquisition is measured as the cash paid plus the fair value of other assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange.

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 Venture Activities

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 assets of the ventures. These are classified as jointly controlled assets and consequently, these financial statements reflect only the Group's proportionate interest in such activities.

Full details of Serica's working interests in those petroleum and natural gas exploration and production activities classified as jointly controlled assets 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; Indonesia, UK & North West Europe and Spain.

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.

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. Upon the successful development of an oil or gas field in a contract area, the cumulative excess of paying interest over working interest in that contract is generally repaid out of the field production revenue attributable to the carried interest holder.

Property, Plant and Equipment – Oil and gas properties

Capitalisation

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

Depletion

Oil and gas properties are not depleted until production commences. Costs relating to each single field cost centre are depleted on a unit of production method based on the commercial proved and probable reserves for that cost centre. The depletion calculation takes account of the estimated future costs of development of recognised proved and probable reserves. Changes in reserve quantities and cost estimates are recognised prospectively from the last reporting date.

Impairment

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

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

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. The Group did not carry any provision for decommissioning costs during 2009.

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.

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

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 standards and interpretations not applied

The following new and amended IFRS and IFRIC interpretations are mandatory as of 1 January 2010 unless otherwise stated. The impact of those applicable to the Group is described below.

i) Amendment to IFRS2 Group cash-settled Share-based Payment Arrangements

The amendment clarifies the accounting for group cash-settled share-based payment transactions, where a subsidiary receives goods or services from employees or suppliers but the parent or another entity in the group pays for those goods or services. This amendment did not have any impact on the financial position or performance of the group.

ii) IFRS 3 (revised) Business Combinations

The revised standard increases the number of transactions to which it must be applied including business combinations of mutual entities and combinations without consideration. IFRS 3 (revised) introduces significant changes in the accounting for business combinations. These changes will have a significant impact on profit or loss reported in the period of an acquisition, the amount of goodwill recognised in a business combination and profit or loss reported in future periods.

iii) IAS 27 (amended) Consolidated and Separate Financial Statements

The amended standard requires that a change in the ownership interest of a subsidiary (without loss of control) is accounted for as a transaction with owners in their capacity as owners and these transactions will no longer give rise to goodwill or gains and losses. The standard also specifies the accounting when control is lost and any retained interest is remeasured to fair value with gains or losses recognised in profit or loss. The Group has concluded that the amendment did not have any impact on the financial position or performance of the Group.

iv) Amendment to IAS 39 Financial Instruments: Recognition and Measurement - Eligible hedged items

The amendment clarifies that an entity is permitted to designate a portion of the fair value changes or cash flow variability of a financial instrument as a hedged item. The Group has concluded that the amendment did not have any impact on the financial position or performance of the Group, as the Group has not entered into any such hedges.

v) IFRIC 17 Distribution of Non-cash Assets to Owners

The interpretation provides guidance on accounting for arrangements whereby an entity distributes non-cash assets to shareholders either as a distribution of reserves or dividends. The adoption of the interpretation did not have an impact on the Group.

Certain new standards, amendments to and interpretations of existing standards have been issued and are effective for the Group's accounting periods beginning on or after 1 January 2011 or later periods which the Group has not early adopted. Those that are applicable to the Group are as follows:

i) IAS 24 Related Party disclosures – effective 1 January 2011

The amended standard clarified the definition of a related party to simplify the identification of such relationships and to eliminate inconsistencies in its application. The Group does not expect any impact on its financial position or performance.

ii) IFRS 9 Financial Instruments: Classification and Measurement – effective 1 January 2013

IFRS 9 as issued reflects the first phase of the IASBs work on the replacement of IAS 39 and applies to classification and measurement of financial assets as defined in IAS 39. The adoption of the first phase of IFRS 9 will have an effect on the classification and measurement of the Group's financial assets. The Group will quantify the effect in conjunction with the other phases, when issued, to present a comprehensive picture.

iii) IFRIC 19 Extinguishing Financial Liabilities with Equity Instruments - effective 1 July 2010

IFRIC 19 clarifies that equity instruments issued to a creditor to extinguish a financial liability qualify as consideration paid. The adoption of this interpretation will have no effect on the financial statements of the Group.

iv) Improvements to IFRS (issued in May 2010)

The Group expects no impact from the adoption of the amendments on its financial position or performance.

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