Northern Petroleum Plc - Cabot Energy Plc · Northern Petroleum Plc Annual Report and Accounts 2010 5 3.2illion*m Oil million bbl: Net probable reserves 53.16 Total net reserves boe:

Corporate

Governance

Accounts

North

ern P

etroleum

Plc A

nnual Report and A

ccounts 2010

For more information see our website: www.northpet.com

Where We Operate 2 Highlights2 Key Performance Indicators 4 2010: A Year of Progress and Achievement 5 2011: Exciting Prospects6 Chairman’s Statement9 Review of Operations

22 Corporate Statement – Health, Safety and the Environment 23 Risk Management25 Financial Review 32 Directors and Advisers 35 Directors’ Report38 Statement of Directors’ Responsibilities39 Report on Directors’ Remuneration 43 Independent Auditors’ Report

44 Consolidated Income Statement45 Consolidated Statement of Comprehensive Income 46 Consolidated Statement of Financial Position47 Consolidated Statement of Cash Flows 48 Consolidated Statement of Changes in Equity49 Notes to the Accounts 81 Unaudited Statement of Reserves 83 Company Balance Sheet 84 Notes to the Company Accounts91 Notice of Annual General Meeting Form of Proxy Glossary of Terms and Abbreviations

Italy

Belgium

Republic of Ireland

Luxembourg

Germany

Slovakia

Poland

Czech Republic

Denmark

Norway

Sweden

The NetherlandsUnited

Kingdom

France

Spain

Portugal

Switzerland

AlgeriaMorocco

Gibraltar

Tunisia

Malta

Slovenia

Croatia

Bosnia and Herzegovina Serbia

Albania

Montenegro

Greece

Austria Hungary

Northern Petroleum manages operations in the Netherlands, Italy, the United Kingdom and has interests in Guyane.

Suriname

Guyana

Venezuela

Brazil

ColombiaGuyane

AnnualReportandAccounts2010

Northern Petroleum Plc

Addingandrealisingshareholdervalue

NorthernPetroleumPlcMartin House5 Martin LaneLondon EC4R 0DPTelephone: 020 7469 2900Facsimile: 020 7469 2901E-mail: [email protected]: www.northpet.com

© Northern Petroleum PlcJune 2011

Designed and produced by SampsonMay Designwww.sampsonmay.com

NorthernPetroleumPlcAnnual Report and Accounts 2010

53.2million*Oil million bbl: Net probable reserves 53.16 Total net reserves boe: 53.16

For more information on Northern’s operations in The Netherlands see p9

For more information on Northern’s operations in the UK see p14For more information on Northern’s operations in Italy see p16* On completion of the agreement with Azimuth, Northern’s net Probable Reserves

will be 45.2 million boe

For more information on Northern’s operations in Guyane see p20

Licence Status Area Interest OperatorOnshore–ExplorationSavio Award Po Valley 80.00% NorthernLongastrino Award Po Valley 30.00%* NorthernCascina Alberto Application Po Valley 100.00% NorthernLa Sacca Award Po Valley 100.00% NorthernPunta Marina Award Po Valley 100.00% NorthernOffshore–ExplorationC.R146.NP Award Sicily Channel 100.00% NorthernC.R147.NP Award Sicily Channel 100.00% Northernd347C.R-.NP Application Sicily Channel 100.00% Northern

G.R17.NP Award Sicily Channel 45.00%** ShellG.R18.NP Award Sicily Channel 45.00%** ShellG.R19.NP Award Sicily Channel 45.00%** Shelld21G.R-.NP Application Sicily Channel 100.00% NorthernG.R20.NP Award Sicily Channel 30.00%** ShellG.R21.NP Award Sicily Channel 30.00%** ShellG.R22.NP Award Sicily Channel 30.00%** ShellF.R 39.NP Award Southern Adriatic 85.00%^ NorthernF.R 40.NP Award Southern Adriatic 85.00%^ Northernd59F.R-.NP Application Ionian Sea 100.00% Northernd60F.R-.NP Application Southern Adriatic 100.00% Northernd61F.R-.NP Application Southern Adriatic 100.00% Northernd149D.R-.NP Application Southern Adriatic 100.00% Northernd351C.R-.NP Application Sicily Channel 100.00% Northernd63F.R-.NP Application Ionian Sea 100.00% Northernd64F.R-.NP Application Ionian Sea 100.00% Northernd25G.R-.NP Application Sicily Channel 100.00% Northernd26G.R-.NP Application Sicily Channel 100.00% Northernd65F.R-.NP Application Southern Adriatic 100.00% Northernd66F.R-.NP Application Southern Adriatic 100.00% Northernd30G.R-.NP Application Sicily Channel 100.00% Northernd71F.R-.NP Application Southern Adriatic 100.00% Northernd72F.R-.NP Application Southern Adriatic 100.00% Northernd29G.R-.NP Application Sicily Channel 50.00% Northernd75F.R-.NP Application † Ionian Sea 100.00% Northernd77F.R-.NP Application Ionian Sea 100.00% Northernd78F.R-.NP Application † Ionian Sea 100.00% Northernd362C.R-.NP Application † Sicily Channel 100.00% Northernd358C.R-.EL Application Sicily Channel 50.00% Petroceltic

* Assuming farmin obligations by Orca Exploration Group Inc. are met.** Assuming farmin obligations by Shell Italia are met. ^ Assuming farmin obligations by Azimuth Limited are met.† Applications subject to competition.

Italy4 Onshore Permits1 Onshore Application

10 Offshore Permits22 Offshore Applications

United Kingdom

Belgium

LuxembourgFrance

Germany

Denmark

The Netherlands

Italy

Belgium

Ireland

Luxembourg

Germany

Slovakia

Poland

Czech Republic

Denmark

The Netherlands

Norway

Sweden

United Kingdom

France

Spain

Portugal

Switzerland

AlgeriaMorocco Tunisia

Malta

Slovenia

Croatia


Kosovo

Macedonia

Bulgaria

Romania

Moldova

Ukraine

Turkey

Cyprus

Northern Cyprus

Albania

Montenegro

Greece

AustriaHungary

7 millionOil million bbl: Net proven reserves 0.77; Net probable reserves 6.24 Total net reserves boe: 7.01

Exploration phase

Key:New licences and applications 0.00% OperatorExisting licences 0.00% Operator

Licence Interest* OperatorOffshore–ExplorationGuyane EEL 1.25% Tullow Oil

* Northern owns a 50% equity interest in Northpet Investments Limited, a company which has a 2.5% interest in the Guyane licence.

Licence Interest OperatorOnshore–ExplorationPEDL 069 5.00% Aurora

ExplorationPEDL 098 62.50% NorthernPEDL 125 50.00% NorthernPEDL 126 50.00% NorthernPEDL 155 50.00% NorthernPEDL 233 50.00% ProvidencePEDL 240 62.50% NorthernPEDL 256 50.00% NorthernOnshore–ProductionPL211 (Horndean Oilfield) 10.00% Star EnergyPEDL 070 (Avington Oilfield) 5.00% Star Energy

United Kingdom10 exploration and production licences2 producing oil fields1 further offshore application

Guyane

Ukraine

Turkey

Tunisia

Libya Egypt

Syria

Switz.

Sweden

Spain

Slovenia

Slovakia

Serbia

Kos.

San Marino

Russia

Kazakhstan

Romania

Portugal

Poland

Norway

Morocco

Monaco

Moldova

Malta

Mac.

Lithuania

Liech.

Lebanon

Latvia

KuwaitJordan

Saudi Arabia

Italy

Israel

Republic of Ireland

United Kingdom

Iraq

Iran

Iceland

Hungary

Greece

Gibraltar

Georgia

France

Finland

Estonia

Denmark

The Netherlands

Czech Rep.

Cyprus

Croatia

Bulgaria

Bosnia &Herz.

Belgium

GermanyBelarus

Azerbaijan

Austria

Armenia

Andorra

Algeria

Albania

Mont.

SouthOssetia

Abkhazia

Gaza Strip

WestBank

Northern Cyprus

Transnistrai

Nagorno-Karabakh

Luxembourg

Suriname

Brazil

Guyane

Corporate

Governance

Accounts

Where We Operate: Licences and Applications

29.3millionOil million bbl: Net proven reserves 5.75; Net probable reserves 4.90 Gas bcf: Net proven reserves 86.10; Net probable reserves 21.96 Petroleum million boe: Net proven reserves 20.59; Net probable reserves 8.69 Total net reserves boe: 29.28

Licence Status Interest OperatorOnshore–Exploration Engelen Licence 60.00% NorthernOosterwolde Licence 60.00% NorthernUtrecht Licence 60.00% NorthernAndel III Licence 22.50% NorthernDrenthe III (Tiendeveen & Lhee) Licence 22.50%* NorthernOnshore–Production/DevelopmentPapekop Licence 45.00% NorthernDrenthe III (Geesbrug) Licence 45.00%** NorthernDrenthe IV (Grolloo) Licence 45.00%** NorthernAndel III (Brakel, Ottoland & Wijk en Aalburg) Licence 45.00%** NorthernWaalwijk: Licence NorthernWaalwijk – North 16.67% Waalwijk – South 2 50.00% Zuid Friesland III Licence 49.56%^ NorthernOffshore–ProductionP12 Licence 23.61% Wintershall

* Assuming farmin obligation to NAM is met.** NAM has a 50% net profits interest after payback of 130% of Northern’s

development costs.^ Subject to completion of transfer of interest from Dyas to Northern.

The Netherlands1 offshore production licence9 onshore exploration and production licences6 gas fields in production

Glossary of Terms and Abbreviations

2D, 3D two / three dimensional (in relation to seismic surveys)

2P Proven plus Probable reserves

3P Proven, Probable plus Possible reserves

P50Reserves are with those with a notional 50% probability – “reasonably Probable” of being produced using current or likely technology at current prices, with current commercial terms and government consent.

€

Euro

£ British pound

$ US dollar

AGM Annual General Meeting

AIM Alternative Investment Market of the London Stock Exchange

API American Petroleum Institute

AzimuthAzimuth Limited

bbl barrel(s) of oil

B, b billion

bcf billion cubic feet

bcm billion cubic metres

Blackwatch Blackwatch Petroleum Services Ltd

boe barrel(s) of oil equivalent

boepd barrel(s) of oil equivalent per day

bopd barrel(s) of oil per day

cfcubic feet

cfd cubic feet per day

€ct/m3

Euro cents per metre cubed

d day

DBS Deferred Bonus Scheme

Dyas Dyas B.V.

EBN Energie Beheer Nederlandse B.V.

EBITDA Earnings Before Interest, Taxes, Depreciation and Amortisation

ENI Eni SpA

EU European Union

FPSO Floating Production and Storage Offloading Vessel

FRS Financial Reporting Standard

GAAP Generally Accepted Accounting Practice

Guyane EEL Guyane Maritime Permit

HSE Health, Safety and the Environment

IAS International Accounting Standards

IFRS International Financial Reporting Standards

ft feet

km, km² kilometre, square kilometres

KPI Key Performance Indicator

KPMG KPMG Audit Plc

m metres

M thousand (10^3)

MM million (10^6)

MMBBL million barrels

MMBO million barrels of oil

MMBOE million barrels of oil equivalent

mmcfd millions of cubic feet per day (of gas)

NAMNederlandse Aardolie Maatschappij B.V.: Netherlands joint venture between Shell and Exxon.

Net to NorthernNorthern Petroleum’s share

Northern or the Groupthe Company and its subsidiaries

NPNNorthern Petroleum Nederland B.V.: Dutch subsidiary of Northern Petroleum Plc.

Orca Exploration Orca Exploration Group Inc.

p pence

PetroCanada Petro-Canada Netherlands B.V.

Probable Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable in this context and when probabilistic methods are used, there should be at least at least a 50 per cent probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves.

ProspectPotential drilling target that is well defined by seismic data.

ProvedProved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions.

Providence Providence Resources (GB) Limited

RPS RPS Energy

Shell Italia Shell Italia E&P S.p.A.

Shell Shell E&P France SAS

scf standard cubic feet

Star Energy Star Energy Group plc

million stb million Stock Tank Barrels

T, t trillion (10^12)

the Company Northern Petroleum Plc

Total Total E&P Guyane Francaise SAS

TSR Total shareholder return

Tullow Tullow Oil Plc

UITF Urgent Issues Task Force

UK United Kingdom

US United States

Wessex Wessex Exploration

Corporate

Governance

Accounts





Italy

Belgium

Republic of Ireland

Luxembourg

Germany

Slovakia

Poland

Czech Republic

Denmark

Norway

Sweden


Kingdom

France

Spain

Portugal

Switzerland

AlgeriaMorocco

Gibraltar

Tunisia

Malta

Slovenia

Croatia


Albania

Montenegro

Greece

Austria Hungary


Suriname

Guyana

Venezuela

Brazil

ColombiaGuyane

1NorthernPetroleumPlcAnnual Report and Accounts 2010

Corporate

Governance

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Northern Petroleum is a full cycle oil and gas company; explorer, developer and producer, operating in areas of low risk.

The Company strategy is to obtain and develop concentrated licence positions holding high quality prospects to which it plans to bring identified improved technologies and economics arising since the last exploration efforts and without paying high entry costs.

Through undertaking geological, geophysical and engineering work Northern adds, and then realises, value for shareholders from these licences.

Northern has an established track record with major industry partners and government authorities as a trusted manager of both onshore and offshore projects acting with high integrity and is recognised for the quality of its technical team.

2 NorthernPetroleumPlcAnnual Report and Accounts 2010

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Key Performance Indicators

Staffturnover

2010: 2.44%2009: 2.56%2008: 5.88%2007: 6.67%

Aim: Smoother and more efficient work by eliminating disruption to work groups, professional and social networks, partner liaison and the retention of project related professional expertise.

Measurement: The number of resignations and terminations as a percentage of the overall employee workforce.

Riskmanagement: Provide good working conditions and competitive remuneration structure on the basis of a collective commitment to clearly defined corporate objectives. Maintain high levels of trust, integrity and transparency in the workplace. Achieve a very high performance on HSE issues. Conduct the corporate business in such a manner that employees feel pride and pleasure in being a part of it.

The Company has established a number of performance targets throughout the business to help ensure delivery of value for shareholders. The directors and management measure performance against these targets and take action where necessary to ensure success. Some of the key measures are shared opposite:

Wellsdrilledandmajorworkovers

Aim: Realisation of opportunities to add value.

Measurement: Annual activity.

Riskmanagement: Have both a high quality and quantity prospect generation capability. Achieve good local relationships to effect the speedier granting of planning consents. Acknowledge that transparency, good manners, an interest in local issues and a willingness to listen and inform is the mark of a good corporate neighbour.

2010

2009

2008

2007

2006

Netreportedreserves

2P Reserves (million boe)

Aim: To increase tangible value.

Measurement: Assessment predominantly by independently reporting petroleum engineers.

Riskmanagement: Employing high quality management and professional staff working in a highly professional, transparent and inclusive cross-disciplinary group within a clearly defined strategy.

Year

*Figure to year end 2010 excludes Azimuth.

’01 ’02 ’10*’09’08’07’06’05’04’03

40

20

120

100

80

60

Highlights

€15 million Revenue 2010 up 194%

€5.08 millionEBITDA

€23.87millionYear end working capital balances provide a sound platform for continued progress

30%Average increase in gas prices achieved in the year

Financial Operational1,825metres drilled(5,988 feet)The company drilled one well in the UK

2gas fields placed on production

89.45million barrelsNet Proven and Probable reserves of oil equivalent 31 December 2010

0.44million barrels2010 production in barrels of oil equivalent

1,520km² of 3DIn early 2010 the Company conducted a 3D seismic survey over four permits offshore Italy

Licences and applications

0 60453015

2002

2003

2004

2005

2006

2007

2008

2009

2010

Totalshareholderreturn

1 yr: 111.8p +0.4% 5 yr: 131.5p -14.6%2 yr: 124p -9.5% 10 yr:13.75p +816%

Aim: Increase share price each calendar year.

Measurements:Increase over the short, medium and long term.

Riskmanagement:Returns are heavily influenced by oil and gas prices and general stock market conditions. Deliver promises. Increase profitability.

Healthandsafety

1LostTimeIncident(LTI)

Aim: No accidents and no environmental releases.

Measurements:Incidents reported within the Company’s HSE procedures as accidents, injuries requiring medical attention and lost time incidents.

Riskmanagement:Encourage Company employees and service providers to adopt a joint and collective duty and desire for a better environment and a safer life. Maintain and continuously review and improve the Company’s HSE policies and documentation.

Growthinproduction

Production (boe)

Aim: Increasing production and income providing increases in profits and cash for corporate growth from development of the Company’s considerable existing asset base.

Measurement: The total oil and gas production per day net to Northern.

Riskmanagement: Attention to planning, good joint venture partner relationships and understanding of local environmental, health and safety issues to effect a smoother and speedier granting of planning consents. Have a willingness to talk to local groups about issues in a transparent and respectful manner.

100,000

500,000

400,000

300,000

200,000

Year ’01 ’02 ’10’09’08’07’06’05’04’03

Licence distribution Production Development Exploration

Reserves by region UK The Netherlands Italy

0 1 2 3 4 5 6 7


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H12011 H2 and plans beyond

2010: A Year of Progress and Achievement

2011: Exciting Prospects

H1 H2JanuaryFebruaryMarch

AprilMayJune

JulyAugustSeptember

OctoberNovemberDecember

8/12/10Italian Farm-out Agreement

6/1/11Oil in Markwells Wood-1 Well confirmed

January

First month of commercial production from Geesbrug – the second of four gas fields.

11/1/10

Drilling completed at Tiendeveen-1 exploration well after overcoming difficult operational problems.

23/3/10

Award of Zuid-Friesland III Production Licence containing Oppenhuizen-1 and Woudsend-1 discoveries. Interests acquired from Dyas and NAM. Estimate 107 Bscf.

21/12/10

Gas production commenced at Wijk en Aalburg – the fourth of six onshore oil and gas fields The Netherlands.

23/11/10

Oil discovery at Markwells Wood-1.

8/12/10

Italian farmout agreement signed with Orca Exploration Group Inc. to drill La Tosca prospect in the Longastrino Permit.

6/1/11

Oil in Markwells Wood-1 well confirmed.

28/1/11

Partners in Guyane Maritime contract ENSCO 8503 rig.

10/3/11

Commence drilling Zaedyus prospect in the Guyane Maritime Permit.

25/3/11

Agreement with Azimuth involving Rovesti and Giove oil discoveries.

5/4/11

Request to transfer to Shell Italia E&P S.p.A. the role of “Rappresentante Unico” for six permits west of Sicily.

27/5/11

Reserve and Production Operations Update.

Further Southern Adriatic seismic subject to consent of Italian authorities.

Drilling La Tosca well.

Markwells-1 testing.

Drilling Baxters Copse, Hedge End.

Drilling Havant well.

Ottoland extended oil production test.

Drilling Papekop production well.

Geesbrug-2 drilling and multi staged hydraulic fracturing programme.

Zuid Friesland well workover.

Drilling North Ottoland (Utrecht licence).

Well in Oosterwolde.

2/7/10

Analysis of effects of new Italian environment proposals have limited effect upon Northern.

27/9/10

Commercial gas production commenced at Brakel field – the third of six onshore oil and gas fields The Netherlands.

14/4/10

RPS Energy report assesses 2P Reserves at Baxters Copse to be 2.68 million barrels net to Northern.

25/6/10

£10 million Placing.

28/6/10

Northern signs strategic seismic collaboration agreement with PGS Ventures AS.

Symbols for bullet points:

Production

General

Guyane

Italy

Operational The Netherlands

DealsUnited Kingdom

“ Orca is delighted to be partnering with Northern Petroleum drilling the La Tosca well. We see this as a low risk exploration opportunity in a proven hydrocarbon basin with significant upside potential. This acquisition is Orca’s second entry into Italy which we believe has substantial reserves and has been overlooked by the major players.”

David Lyons, Orca Exploration Chairman and CEO

“ The Markwells Wood-1 well has to date presented us with encouraging results. An oil bearing sequence has been encountered in the target reservoir adjacent to the producing Horndean oil field within its mapped structural closure. Detailed analysis of the core and logs will provide information on reservoir quality. Expected production rates will be derived from the future test programme. Success at Markwells Wood, helped by current oil prices, should enhance the value of the other undeveloped discoveries and exploration prospects held under licence by Northern in the UK.”

Derek Musgrove, Managing Director of Northern

For more information on our activities in Italy, please turn to page 16.

For more information on our activities in the UK, please turn to page 14.


Corporate

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I reportayearofprogress.Wehavemoved forward delivering on ourstrategy in Italy to develop two oildiscoveriesandprogressthedrillingofoursubstantialhighimpactexplorationwells without further recourse todilutionofshareholdersequity.IntheUK we have made an oil discoveryatMarkwellsWoodwhich issoontobetested,andarealongsideTullow,ShellandTotaldrillingthefirstwellinapotentialnewpetroleumprovinceoffshoreGuyane.

The revisions to reserves follow an ongoing economic and technical evaluation. Reprocessing of the 3D seismic data over Geesbrug and Wijk en Aalburg fields, plus much of the rest of the Netherlands acreage has been underway for some time. When it has been received and interpreted, the static and dynamic field models will be updated with the production data later this year, it will then be possible to make a further assessment of the reserves.

The overall plan remains to sustain and increase production from the existing one well fields in The Netherlands through undertaking new drilling and completions on the larger fields, the first of which will be the Papekop-2 and Geesbrug-2 wells, once the current reprocessing of the 3D seismic data and mapping has been concluded. Currently we are moving forward on the production testing of the Markwells Wood and Ottoland oil discoveries.

The exciting and higher potential activities will, however, be in Italy, as we continue in discussion with existing and potential future new partners to explore and drill our large licence position containing significant prospects with highly material potential, as well as moving forward the developments of the Rovesti and Giove oil fields with 53 million barrels of proven and probable oil reserves. Even allowing for new partners providing the required finance our interests in these projects should remain substantial.

Together with our partner, Shell Italia, we have mapped and interpreted our 2010 3D seismic survey on four permits in the Thrust and Fold Belt offshore Sicily. This is clearly an area with substantial potential. Drilling success could establish a new oil or gas province. Northern continues to be the Operator of the joint-venture. In April 2011 Northern assigned to Shell Italia the role of “Rappresentante Unico” (the sole representative with respect to the Italian authorities of those permits) to advance discussion with the Italian authorities concerning future activities.

Azimuth Limited joined us in the southern Adriatic Sea on the two permits containing the Giove and Rovesti oil discoveries and the large Cygnus prospect. Adjustments to the booked reserves in Italy of approximately 8 million barrels of oil equivalent should be expected during 2011 to reflect this welcomed arrival of Azimuth as a new 15% partner in our moves to further explore these permits, as well as to drill and develop the Rovesti and Giove oil discoveries. Subject to governmental consents, we will be acquiring one 2D and two 3D seismic surveys in 2011.

With the advantage of 3D seismic coverage, we will be better placed to attract additional partners for the drilling of larger exploration targets, and to make progress towards the development of the two oil fields. Our interest in the Rovesti and Giove oil discoveries has been highlighted by the 2007 report of Blackwatch Petroleum Services, which assigned a Net Present Value (NPV@10%) of $610 million after tax assuming a $70 oil price and initial production rates of 9,000 and 20,000 barrels of oil per day from Rovesti and Giove respectively. That report assumed that two new build Floating Production and Storage Offloading vessels (“FPSO”) would be purchased rather than leased. Interest in our permits will no doubt be enhanced by the recent news that, in an adjacent production concession, Eni will redevelop the Aquila oil field this year with a new build FPSO, and have announced plans for eight years of additional production with an initial rate of 9,000 barrels of oil per day.

Also in the southern Adriatic Sea, we have seven applications which can no longer be applied for by others. These contain a significant number of additional exploration prospects. We look forward to the important award of these further permits and embarking upon the exploration of the wider area in this proven petroleum province. Increasing recognition by the oil industry of the exploration potential in the Adriatic is also demonstrated by our and other significant companies’ expressions of interest in the announced Montenegro licensing round.

We have delivered increased gas production and since January 2011 have a positive cash flow, our Group cash increasing to €23 million at 3 June 2011 from €21.4 million at the end of 2010. Recently you have been advised that we are revising our 2011 production forecasts and have made changes to reserves estimates in The Netherlands that were first reported upon by RPS Energy in 2006 and reviewed by them in February 2010. This 2011 revision amounts to a reduction of 13% in previously reported Group proven and probable reserves to 89 million barrels of oil equivalent, which is approximately one barrel per share at 31 December 2010, after production of 0.44 million barrels of oil equivalent during 2010.

In the year there was a significant increase in revenue to €15 million (2009: €5.1 million). As a consequence of the additional non-cash depletion and impairment charges of approximately €3 million arising from the reserves revision, I report a small pre-tax loss of €0.02 million (2009: €3.12 million loss).

At the end of 2010 the cash position was €21.4 million (2009: €15 million), the increase year on year arising from increased cash flow from record production, as well as a €11.5 million equity fund raising in June 2010, more than offsetting capital investment of €13.7 million during the year. Gas prices received during 2010 averaged €32.69 per barrel of oil equivalent (2009: €33.45 per barrel of oil equivalent), and have increased by approximately 13% over the first four months of 2011. The Group has no external debt but has the production and reserve base to obtain debt and the Board is highly likely to seek to make use of this capacity in due course.

To date we have placed into production four of the six planned oil and gas field developments following our contract with NAM in 2005. With Waalwijk and P12 included, we now generate production from six fields. Average production for the first four months of 2011 has been just over 1,900 barrels oil equivalent per day. However following the reserves revisions, our forecasted range for Group production for 2011 is now 1,550 to 1,650 barrels of oil equivalent per day.

RHRLatham,Chairman

Chairman’s Statement

US Dollars

Euros

J

120

60

80

100

MFJDNOSAJJMAMF

Brent oil prices 2010/11Price in US$ and €/bbl

P12

Waalwijk

Grolloo

Geesbrug

Please note that:

NIP 2010 still being used, pending finalisation of calculations NIP 2011 price.

Brakel

Wijk en Aalburg

J

28

26

24

22

18

20

MFJDNOSAJJMAMF

Gas price since 1 January 2010 Price in €ct/m³

Average gas price

J

26

24

22

18

20

MFJDNOSAJJMAMF

Average gas price since 1 January 2010 Price in €ct/m³


Corporate

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Corporate

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Within the Longastrino permit in the Po Valley, our new partner is Orca Exploration Group Inc. The drilling of the La Tosca prospect is scheduled for later this year. Orca will be funding all costs to the budgeted level for drilling and testing at which point Northern will retain a minimum 25% interest in this permit. A site has been selected and we now await governmental authorisations to proceed to drilling.

In the Sicily Channel, whilst some secondary prospects in C.R147.NP offshore of Pantelleria are located within an area that has been banned from drilling under the 2010 Environmental Act, the primary prospects to the north lie outside the 12 nautical mile zone covered by that Act and therefore unaffected. The outlook for these prospects has been improved by the Lambouka gas discovery made by ADX Energy in 2010 nearby and down dip in Tunisian waters. We are putting a drilling programme together to cover two C.R147.NP prospects and the larger Vesta prospect in C.R146.NP adjacent to the boundary with Malta. The timing is a matter of some difficulty in the contracting of rigs, which will need to undertake modifications to satisfy EU standards, that are primarily deployed in the Eastern Mediterranean.

I believe that the upside potential and value of our Italian projects is significant, and of a different order of magnitude to the ventures in The Netherlands, so increasingly our focus and priorities will be aimed towards them. Importantly as previously mentioned the majority of our projects lie beyond the 12 nautical mile limit that is the subject of the 2010 new Law as advised to you on 2 July 2010.

Of in terest to shareholders is our participation, albeit a small 1.25% net beneficial interest, in the Tullow, Shell, and Total well offshore Guyane, currently drilling the Zaedyus prospect, a 300–700 million barrel target. Although not in a core area, this well represents another good exploration project for Northern. If successful, there is the possibility that a new petroleum province will be opened up and at least six further similar structures have been mapped. The Zaedyus prospect alone offers an attractive upside, which if within the target range, offers a finding cost considerably under $1 per barrel to Northern.

The projects in the south of England have been reviewed. Three oil discoveries are involved, as well as a small level of oil production from the Horndean and Avington fields. At current oil prices the oil discoveries are potentially valuable assets as summarised in an RPS Energy report of April 2010. Whilst we stated a willingness to sell these assets to a buyer finding them more strategically interesting, Northern remains steadfast in its intent on realising an appropriate value for shareholders.

The values of these projects have been enhanced by the rise in oil prices and would be even further so by the successful testing of oil this summer at Markwells Wood in West Sussex following the December 2010 discovery. Detailed analysis of the core taken in the Great Oolite reservoir is ongoing to determine the details of the programme and in particular the reservoir completion treatments.

As the Markwells Wood, Baxters Copse and Hedge End oil discoveries offer a good profit potential it is in shareholders’ interests that these projects continue. We expect that progress will be made through 2011 and into 2012.

The Markwells Wood operation was a great example of Northern’s ability to work with the local community in deploying best practices of the modern oil industry. The Company’s targets are second to none in being a good corporate neighbour with a very high level of respect for the total environment. I am grateful for all the kind words and accolades on the Markwells Wood operations, and thank the Northern team for their deep seated commitment to best practice – just as they also achieved favourable comment among the local communities in The Netherlands. Northern takes great pride in its performance during the drilling operations, and its ability to conduct this with a very low level of impact on the local community, the constructive interaction with whom enabled a reduced disruption from our operations.

A degree of optimism can be taken from the results of a study initiated with the encouragement of EBN, The Netherlands state oil company. In recent months NuTech Energy Alliance, a firm of US consultants expert in the field of oil and gas shale investigation, conducted an examination of the potential of shales in the southwest of the Netherlands. The view of the chosen US

expert consultants is very encouraging and shareholders should find the description in the Operations Report to be of interest.

For the year 2010 the Board is continuing the practice of not recommending payment of a dividend. The Company’s financial resources will be committed to investing in the Company’s assets.

We have come a long way since the 1999 reorganisation of an ailing Russian orientated company. We are now in areas of low political risk and we are in production from six gas fields and two oil fields.

In The Netherlands we have proven ourselves to be a good corporate citizen and a full cycle company capable of drilling wells and placing fields into production and have the opportunity and plans to expand upon this base. We have made an oil discovery in our UK onshore portfolio. In Italy we have assembled, and are exploring, a large licence position, predominantly offshore, and continue to introduce new partners in conformity with our strategy. We have pride and distinction in that we remain Operator in our six licence venture with Shell Italia. I await with interest the results of the well currently drilling the Zaedyus prospect offshore Guyane.

Shareholders will recognise that, for the foreseeable future, we will continue to be a project rich company. That fortunate position leads us to continue a strategy of seeking, through trading and farmouts, to realise an early value from some assets to fund the growth plans of the Group.

On this basis I can advise that your Board looks to the future with confidence as it increases the pace of activities as swiftly as possible within the constraint of avoiding further dilution of shareholders’ equity. The next 18 months will prove to be a critical period of potential value creation for the Company as the high impact Italian assets are de-risked and further explored.

Vital to Northern’s success are the people who help us to unlock the potential within the portfolio. On behalf of the Board I thank them all for their continued commitment and the achievements of the last year.

RHRLathamChairman of the Board7 June 2011

Review of Operations TheNetherlands

Production

North Ottoland fields or prospects within licenceExplorationTesting on development

Chairman’s Statementcontinued

Net proven and probable reserves: Gas 108 billion cubic feet; Oil 10.65 million barrels

6 gas fields in production

1 oil field awaiting testing

1 oil field awaiting re-drilling

4 further discoveries awaiting development

3 discoveries to be progressed in 2011

PartnersEnergie Beheer Nederland B.V. (EBN) The state owned energy company engaged in the exploration, production, and sale of oil and natural gas.

Nederlandse Aardolie Maatschappij (NAM) The joint Shell / ExxonMobil Company in The Netherlands.

Dyas B.V. (DYAS) A wholly owned subsidiary of the largest privately owned conglomerate in The Netherlands, SHV Holdings NV and an active partner, as non-operator, in oil and gas exploration, development and production joint ventures.

108bcfNet proven and probable reserves: gas

10.65mmbblNet proven and probable reserves: oil and condensate

The Netherlands: overview

P12

Papekop

Oosterwolde (Haazen)

Andel III (Brakel, Ottoland & Wijk en Aalburg)

Zuid Friesland III (Oppenhuizen, Woudsend)

Drenthe III (Lhee, Lhee North, Boterveen)

Belgium

Germany

Waalwijk

Drenthe III (Geesbrug)

Drenthe IV (Grolloo)

Engelen (Kerkwijk South)

Utrecht (North Ottoland,

Willeskop, Everdingen South,

Kerkwijk)


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StrategysummaryNorthern wil l continue to develop incremental new production from its additional undeveloped onshore oil and gas fields to augment the six fields now on stream. Northern’s involvement in The Netherlands was initiated in 2004 and has been built around two core areas containing both oil and gas fields. The four gas fields have been developed first and the development of two oil fields in now underway. Continuation of the onshore exploration and development programme is coinciding with rising gas prices and a strong oil price.

The recent success of unconventional resources for shale gas and oil in North America has been the driver to assess this resource potential in The Netherlands and initial studies indicate that the Andel III Licence in the West Netherlands Basin has a potential world class shale play that in this part of the Basin is viable for oil. The ongoing work will quantify the resource potential for Andel III and the other Northern licences in the Basin and the requirements to develop this resource.

Development planning for two oil fields has been undertaken in 2010 that will result in a production well drilling and testing activity in 2011. The first development well on Papekop has been designed and preparation work for the wellsite has been approved. Reprocessed 3D seismic data will be available for planning the final well trajectory which will include a horizontal hydraulically fractured intersection of the reservoir. The Ottoland long term oil test is also being designed and permits are expected to be in place for the commencement of the test in the third quarter of 2011.

The rap id ly increas ing product ion from unconventional shale gas and oil developments in North America basins has initiated a review of this potential resource for the acreage under licence in the Netherlands. This analysis has been done in association with NuTech Energy Alliance, a Houston based consultancy with considerable expertise and experience in analysing shale resources. The work initiated for the Andel III licence has indicated the Licence has considerable potential for oil production from a shale sequence considered to be more prospective than most basins in North America. Work is now continuing to quantify the resource for all the West Netherlands Basin licences of Utrecht, Andel III, Engelen and Waalwijk.

Reviewof2010OverviewIn the period (2009–2010) Northern brought four new gas fields into production (Grolloo, Geesbrug, Brakel and Wijk en Aalburg) adding considerably to the late-life production already in place at Waalwijk and P12. Brakel came on stream in September 2010 and Wijk en Aalburg in December 2010. Average production for 2010 was 1,195 barrels of oil equivalent per day and average production for the first four months of 2011 was over 1,900 barrels of oil equivalent per day. Gas prices received in the Netherlands rose strongly during 2010 and increased by approximately 13% in the first four months of 2011.

The four fields brought into production are all wells originally drilled and subsequently suspended as gas discoveries by NAM, the original wells being utilised as the production wells. With the exception of the Geesbrug field they are being produced as single well developments. In the case of Geesbrug new wells will be required to affect an efficient gas extraction programme. A second production well at Geesbrug is being designed with a long lateral intersection of the reservoir unit with the capability of conducting multi-staged hydraulic fracturing operations. The planning of this more expensive and more productive well should await the gaining of reprocessed 3D seismic over the field and sufficient production history in order to design the extraction plan with increased confidence in its performance.

Review of Operations TheNetherlandscontinued

Netherlands – Licences and fields

Producing fieldsBrakel gas field (45% NPN)Commercial gas production commenced at the Brakel field in September 2010. The forecast contracted gross sales volume for the field commenced at 200,000 normal cubic metres per day (7.4 million standard cubic feet per day) or 1,280 barrels of oil equivalent per day. Some condensates are also being produced for sale. This is the first of the fields that Northern has installed a dedicated gas plant for the processing of the gas prior to pipeline export to the grid. The field production rate has been in line with predicted performance.

Geesbrug gas field (45% NPN)Geesbrug was brought on stream in December 2009. The field provided an initial production rate of 7.4 million cubic feet per day. The production performance since then has been analysed in conjunction with the disappointing results of the Tiendeveen-1 well five kilometres away. An updated static reservoir model has been constructed based on the test of this exploration well, updating the dynamic model will follow. A revised reserves assessment for the Geesbrug field has resulted from the revision of Gas Initially In Place volumes derived from the updated static model.

Reprocessing of all applicable 3D seismic coverage was deemed essential for placing future development wells in the field and was initiated in 2010 as part of the forward development plan. The planned 2011 Geesbrug-2 new production well will most likely be delayed into early 2012 to utilise the reprocessed 3D seismic data to determine the most appropriate location of the well. This is designed to be a 3000–4000 foot lateral reservoir intersection with multi-stage fracturing operations which are designed to result in a greater ability for higher production rates than near vertical wells.


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Review of Operations TheNetherlandscontinued

Grolloo gas field (45% NPN)The Grolloo-1 well work-over has been completed and the field came back on stream in November 2010 at a rate of 200,000 normal cubic metres per day (7.4 million cubic feet per day or 1,280 barrels of oil equivalent per day). The initial development plan had been to install compression and or other surface equipment to aid and increase production once the pressure had stabilised. Until now no such stabilisation has been observed allowing for the basis of design for the equipment.

The addition of compression cannot be achieved in time to make a material impact to 2011 gas production. The more conservative view is that pressure support from lower permeability reservoir matrix will not occur to support reservoir pressure and a revision has been made to reported reserves on this basis.

Wijk en Aalburg gas field (45% NPN)Gas production was commenced in December 2010 at an initial rate of up to 150,000 normal cubic metres per day. This is the second field where Northern has installed a dedicated gas plant. The development well has experienced the production of increasing quantities of oil, followed by increasing quantities of water, which has affected production levels. This is being addressed with well intervention operations to assess possible remedies. Given the uncertainty to future production rates it has been decided to make a revision to reported reserves.

ExplorationReprocessing and then re-interpretation of the 3D seismic data over the Andel III (45%), Drenthe III (45%), Oosterwolde (60%), Engelen (60%), Utrecht (60%) and Papekop (45%) licences is underway. This work is necessary to confirm future well locations for exploration prospects planned for drilling in 2012 and beyond.

ApplicationsAn application has been made for one new licence.

FuturePreliminary work on discoveries and exploration prospects is underway with a view to drilling in 2012 and beyond based on the results of the 3D seismic reprocessing now underway for the majority of the Licences. This includes the undeveloped discoveries of Kerkwijk and Willeskop, to be augmented by further exploration drilling on the Drenthe III Licence.

Exploration wells on the Oosterwolde and Utrecht licences are also planned for 2012 alongside our partner EBN, who has elected to enter onshore The Netherlands exploration licences alongside Northern in three separate joint ventures.

Ottoland oil field (45% NPN)The production test of the Ottoland oil well awaits planning approvals but is scheduled for 2011. Development design will be initiated following the test results.

Papekop oil and gas field (45% NPN)There has been some money-saving progress in tackling road access to the well site at Papekop. Approvals have been received to allow the drilling and testing of a new development well in the Papekop oil field to also take place in 2011.

Waalwijk gas field, North (16.67% NPN), South (50% NPN)The field continues in production with compress ion equ ipment be ing re-engineered to further enable extended field performance. The four new fields that have been brought into production are controlled remotely from the control centre at Waalwijk.

P12 (23.61% NPN)In 2010 production was impacted due to compressor problems. The compressor was removed from the platform and then re-commissioned in April 2011, production levels are now back up to the expected rates for the remainder of the year.

Production licenceZuid-Friesland III licence (44.34% NPN)Northern has acquired two further development projects and operatorship, through the award of the Zuid-Friesland III production licence in 2010. This is a welcome addition to growth plans for onshore Netherlands production and contains two undeveloped gas fields, Oppenhuizen and Woudsend, with estimated Gas Initially In Place of 107 billion cubic feet, with expected recovery factors of the order of 60%.

The review of unconventional shale oil and gas potential was initiated for the West Netherlands Basin with NuTech Energy Alliance undertaking detailed log analysis of the Andel-6 (Wijk en Aalburg), Brakel and Ottoland wells in the Andel III Licence. This work is not yet finalised but will be expanded to the other adjacent Licences and a resource potential calculated for the Andel III, Engelen, Waalwijk, and Utrecht licences based on the lateral extent and thickness of the shale horizon identified as the main oil resource potential. NuTech have identified additional intervals in the three wells analysed that are gas bearing and when compared with similar reservoir properties in North American basins would be considered productive horizons. Further analysis will be undertaken in conjunction with NuTech to quantify this potential.

Consideration is also being given to extending the work with NuTech to additional areas in The Netherlands once the current work programme is completed.

Given that Northern has a greater than 50% interest in a number of these projects, it is likely that it may seek to de-risk the portfolios by bringing in additional partners into some of these licences.

West Netherlands Basin – Fields and Prospects


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Northern’s holdings include 10 licences in the south of England covering the Weald Basin and Isle of Wight. Production currently comes from two producing fields, at Avington and Horndean, with near term drilling of discoveries at Hedge End and Baxters Copse, and an exploration prospect at Havant.

Excel lent news from the Markwel ls Wood-1 well came in December 2010. An oil bearing sequence was encountered in the target Great Oolite reservoir. This success at Markwells Wood, helped by current oil prices, will enhance the value of the other undeveloped discoveries and exploration prospects held under licence by Northern in the UK.

FutureReprocessing of all the available 2D seismic data is being carried out for Licences PEDL’s 126, 155 and 256 plus PL 211 to better image structure and assist with well planning. The Havant exploration well, with operations scheduled to commence later in 2011 will commence when the results of the reprocessing have been integrated with the regional well control. Meanwhile Providence Resources has plans to drill the Baxters Copse appraisal well in 2012. This well will be drilled from the Singleton production facilities, negating the requirement for a new surface location from which to drill. The well will target a Proven Plus Probable reserves volume of 5.36 million barrels, with upside potential for 15.06 million barrels (Proven Plus Probable Plus Possible Reserves).

Also this year, a suitable site has been identified for a production test to appraise the Hedge End-1 oil discovery and negotiations with the land owner are ongoing to obtain a lease for the site.

Production / developmentExploration

Review of Operations UnitedKingdom

2P oil reserves: 7.01 million barrels

10 licences

1 further offshore application

Partners Egdon Resources AIM-listed exploration and production company focused on the oil and gas producing basins on the onshore UK and mainland Europe.

Magellan Petroleum Corporation A NASDAQ listed company engaged in oil and gas exploration and production in Australia, North America and the UK.

Montrose Industries A private E&P and investment company which is focused on the UK onshore with an interest in PEDL’s 098 and 240.

Providence Resources Irish based, AIM-listed oil and gas exploration and production company which acts as operator for Northern in one licence, PEDL 233. Operator of Singleton oil field adjacent to PEDL’s 126 and 233.

StrategysummaryThe activities in the south of England represent a good opportunity to add value at current oil prices but with most of the productive oil fields being held by a subsidiary of Petronas it is thought that the opportunity for building a core area of significant contribution to Northern’s targets is limited.

After testing the market to ascertain if a short term realisation of a sufficient proportion of the potential value could be achieved, via a sale, efforts now refocus on moving forward to realise value through drilling operations. The first of which was the Markwells Wood-1 oil discovery which is to be tested shortly. At the time of writing, analyses of the core and log data were being finalised ahead of an extended well test planned for the summer of 2011.

7.01mTotal net reserves

0.77mOil million bbl: Net proven reserves

6.24mOil million bbl: Net probable reserves

United Kingdom: overview

Weald and Wessex Basin – Fields, Prospects and Licences

PEDL 125

PEDL 070

PEDL 240

PEDL 098

PEDL 069

PEDL 256PEDL 155

PEDL 126

PEDL 233

PL211 (Horndean Oilfield)


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StrategysummaryItaly represents the country that holds the most exciting and significant long-term opportunities in Northern’s portfolio of assets. In Italy Northern has pursued a focused approach to acreage acquisition and now has 14 permits, 20 uncontested appl icat ions and three contested applications. This position of strength is rivalled by only the former Italian state oil company Eni. The continued enhancement of Northern’s considerable asset base in Italy is a major success for the Group.

Northern, ahead of near ly al l the competition, accumulated positions in four onshore permits, 10 offshore permits and has 22 offshore applications with a concentration in three prospective core areas, mainly in deep waters. The Group has assets in the onshore gas province of the Po Valley, offshore Sicily and has two oil fields and multiple exploration prospects in the Southern Adriatic.

To realise shareholder value from this portfolio Northern is seeking to achieve further third party finance for exploration and appraisal drilling to confirm the vast potential. The involvement of such a major international group as Shell as a farm-in partner in six of its Sicily Thrust and Fold Belt permits has brought endorsement of the Company’s strategy. The addition of two more partners, Orca Exploration Group Inc. in the Po Valley Basin and Azimuth Limited in the Southern Adriatic Sea, brings additional resources and skills to progress exploration and development. Northern’s plans are for an aggressive, but realistic, strategy to enhance the value of the acreage portfolio.

Reviewof2010Northern made good progress last year in responding to the important challenge of drilling and realising the very large potential of our projects offshore Italy. Development of our assets there will not be materially affected by new Italian environmental legislation announced in mid 2010, although the consequent delay in the award of new offshore permits has slowed down planned progress. The new Law essentially bans drilling within 12 nautical miles of the Italian coast and marine parks. Our permits and applications are predominantly further offshore. Thus Northern does not expect this Law to impact upon its reported reserves or materially affect our two key core areas of the Southern Adriatic and Thrust and Fold Belt offshore West of Sicily. Working with our major joint-venture partner Shell Italia in the Thrust and Fold Belt core area offshore Sicily, the (1,520km²) 3D seismic evaluation is completed. The 3D seismic was acquired at no cost to Northern. Northern retains the operatorship of the joint-venture but the role of “Rappresentante Unico”, the sole representative with respect to the Italian authorities has been transferred

Review of Operations Italy

Italy: overview

Net probable oil reserves: 53.2 million barrels

10 offshore permits

22 offshore applications

4 onshore permits

1 onshore application

Reserves The Italian assets contribute to 53.2 boe of the reported net P2 reserves. On completion of the agreement with Azimuth, Northern’s net Probable Reserves in Italy will then be reduced to 45.2 million boe.

Partners ShellThough its Italian subsidiary, Shell Italia E&P S.p.A.

Orca Exploration Group Inc A Canadian exploration and production group.

Azimuth Limited A specialist E&P business created to acquire prospective oil and gas assets worldwide.

Interests: Offshore

Offshore West of Sicily Thrust and Fold Belt Shell farmed into six permits West of Sicily with an option to drill and test an exploration well in 2012. Large 3D (1,520km²) seismic data acquired, processed and interpreted.

Sicily Channel Two high impact oil prospects being progressed towards drilling and farmout partners being sought. Rig availability being assessed.

Durres basin in the Southern Adriatic Sea Two oil fields with probable reserves of 53.2 million barrels. Over 30 oil and gas prospects mapped in two permits and seven applications. A third party report evaluates a mean 3 billion barrels of oil in place for six prospects in two permits.

Crotone Basin in the Ionian Sea Gas discoveries and significant additional prospects close to existing infrastructure. Four of six applications within 12 nautical miles of the coast impacted by new Environmental law. Shell has two adjacent applications.

Interests: Onshore

Po Valley La Tosca prospect in the Longastrino Permit is planned for drilling late 2011 after farmout to Orca Exploration.

53.2mmboNet probable oil reserves

Exploration

Longastrino

Savio

CascinaAlberto

d66F.R-.NP

d60F.R-.NP

d65F.R-.NP

d78F.R-.NP

F.R 40.NP

d347C.R-.NP

d21G.R-.NP d362C.R-NP

G.R20.NP G.R17.NP d26G.R-.NP d25G.R-.NP

d29G.R-.NP

d351C.R-.NP

C.R146.NP

d72F.R-.NP

d64F.R-.NP

d59F.R-.NP

d77F.R-.NP

d71F.R-.NP

F.R 39.NP d149D.R-.NP

d61F.R-.NP

d75F.R-.NP

G.R22.NP G.R21.NP

G.R19.NP G.R18.NP

d358C.R-EL d30G.R-.NP

C.R147.NP

d63F.R-.NP

Punta Marina

La Sacca

18 Northern Petroleum Plc Annual Report and Accounts 2010

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19Northern Petroleum Plc Annual Report and Accounts 2010

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Review of Operations Italycontinued

It is important to recognise that these southern Adriatic permits are next to a developed oil field. In the adjacent production permit Eni operates the Aquila oil field, located in 815 metres water depth. The field is located 12 kilometres from the Giove discovery which is in 600 metres water depth. The Aquila field came on stream initially in 1998 and produced approximately 24 million barrels over eight years before production was suspended in 2006 due to the required decommissioning of the FPSO “Firenze”. Eni plans to re-develop the field in 2011 with production to a new FPSO commissioned from Saipem with a storage capacity of 700,000 barrels and a production capacity of 12,000 barrels of oil per day. Eni have announced plans for eight years of additional field production with an initial rate of 9,000 barrels of oil per day.

A further seven applications have been made surrounding the two Southern Adriatic permits, containing the Rovesti and Giove fields, with additional exploration prospects recognised with potential for both oil and gas. With the full award of permits the planned work programme would be to acquire additional new 2D seismic data to provide a consistent data set on which to high grade the over thirty prospects identified. The 2D seismic will provide a basis for selecting areas for 3D seismic and thereafter drilling locations and be the point after which Northern will seek additional partners in the permits.

to Shell. Work is continuing with the evaluation of the permits and operatorship of the joint venture will transfer to Shell for the drilling of an exploration well. Under the farmout agreement with Shell the cost of drilling and testing the first well will be at no cost to Northern.

Significant further progress has been made in 2011 on a key area for Northern with the signing of an agreement involving permits F.R39.NP and F.R40.NP in the Southern Adriatic. Our new partner is Azimuth Limited, a specialist E&P business created to acquire oil and gas assets worldwide. The primary objective of the agreement with Azimuth is to make progress with both development and exploration activities – taking the development of the Rovesti and Giove discoveries a step closer with the acquisition of 3D seismic to define suitable appraisal locations, and also provide the data required for development well locations. Additional 3D seismic coverage will be sought over a number of exploration prospects to define drilling targets. Northern recognises significant exploration potential in the two Southern Adriatic permits for both oil prospects, with a mean volume of over 3 billion barrels of oil in place and gas prospects with a mean volume of over

2 trillion cubic feet of gas. This adds up to over 1 billion barrels of oil equivalent of prospective resource in the two permits, split approximately equally between oil and gas prospects. Azimuth will become a 15% interest partner in both permits by funding a promoted share of future work programmes prior to the drilling stage. The future assignment of permit interests to Azimuth and implementation of aspects of the agreement are subject to receiving approvals from the Italian authorities.

The two oil discoveries in these permits are Rovesti, to which Blackwatch Petroleum Services has assigned 2P reserves of 33.56 million barrels of oil equivalent and Giove, for which the figure is 19.67 million barrels of oil equivalent with the advantage of 3D seismic coverage be better placed for attracting additional partners for their development. Blackwatch in 2007 assigned a Post-Tax Net Present Value (NPV@10%) of $610 million at a $70 oil price based on developing the two fields independently, each with a new build Floating Production and Storage Offloading Vessel (FPSO). Leasing of an FPSO is likely to improve the economics. The Rovesti P50 initial annual production profile is approx 9,000 barrels of oil per day declining to just under 6,000 barrels of oil per day after 5 years and for Giove the P50 initial annual production profile is over 20,000 barrels of oil per day declining to just under 10,000 barrels of oil per day after 2 years.

A third farmout in Italy was finalised in December 2010 for the drilling of the La Tosca Prospect in the Po Valley Basin, onshore Italy (Longastrino Permit). This deal with Orca Exploration, a Canadian exploration and production group will finance the drilling of the prospect and a well is scheduled for late 2011. The La Tosca prospect is estimated by Northern to have 45 billion cubic feet of gross mean prospective resource and will target an upside of 85 billion cubic feet gross prospective resource of gas. Northern will be the operator during the drilling and testing phase and Orca will assume operatorship of the permit thereafter.

Additional farmout efforts continue for C.R146.NP, with an internally estimated billion-barrels-plus sized prospect and for C.R147.NP, which our exploration team consider has been made more attractive by the Lambouka gas discovery recently announced by ADX Energy in nearby Tunisian waters.

FutureThe important challenge is to drill and realise the very large potential of some of our projects offshore Italy. In the short term those are the Thrust and Fold Belt permits. Northern continues to be the operator of the joint venture. In April 2011 Northern assigned to Shell Italia the role of “Rappresentante Unico”, the sole representative with respect to the Italian authorities, C.R147.NP in the Sicily Channel and C.R146.NP close to Maltese waters. Efforts are in hand with the latter to progress the required environmental work required for drilling while continuing to evaluate the rig market for availability of vessels within the Mediterranean.

Alongside our joint venture partner Shell Italia, in the Thrust and Fold Belt the 3D seismic data has been interpreted and evaluation continues with respect to the future exploration plans for the permits. In the Southern Adriatic, we are waiting receipt of various approvals from the Italian authorities before announcing the details, but the plan is to define and delineate suitable appraisal and exploration drilling targets by the acquisition of a 2D seismic survey and two 3D seismic surveys that will progress the future development of reserves and the drilling of exploration prospects in permits F.R39.NP and F.R40.NP that form just a part of this key area in the Italian offshore.

Also on our schedule is a well on the La Tosca Prospect where we have recently announced the farmout with Orca Exploration.

Northern continues to step up work on the priority of realising more of our Italian potential but, in line with our low-cost strategy, we will continue to actively promote farmouts, predominantly at the drilling stage. Discussions are ongoing, but we will consider only those that offer adequate value to our shareholders. Further farmout promotions for permits in three of our offshore core areas, the Sicily Channel, the Southern Adriatic Sea and the Ionian Sea, can be expected with the aim of minimal initial cost or financial exposure for Northern, or the potential to increase the work programme to augment resources available to Northern.

We will continue to seek new permits to add to our extremely valuable portfolio of Italian assets.

Northern has built a portfolio of substantial prospective value in I taly at minimal financial exposure. Validation o f t h e p o t e n t i a l w i t h i n this portfolio came first in 2008 with a farmout deal on its permits to the West of Sicily to Shell Italia. In 2010 Northern announced a farmout to the Canadian group Orca Exp lora t ion Group Inc. on its Longastrino Permit in the eastern part of the Po Valley Basin, onshore Italy. This has been followed with another farmout, this t i m e t o E & P s p e c i a l i s t Azimuth Limited for the two Italian permits which contain the significant Rovesti and Giove oil discoveries. Now, growing interest in Italy is resulting in an increasing

number of approaches for other farmouts.

T h e h i s t o r y, f ro m f i r s t invo lvement in 1999, is proof of Northern’s strategy in bui lding concentrated acreage positions that have the potent ia l to a t t rac t major industry partners. Northern has a portfolio of exploration acreage rivalling that of former Italian state oil company Eni, with interests in 37 exploration permits and applications. The farmouts have brought to Northern not only international major project, explorat ion and production expertise, but access to the funding required to develop the permits with Northern retaining substantial stakes.

Northern has made full use of its first-mover advantages. Management’s considerable industry experience enabled Northern to recognise the considerable potential in Italy’s under-explored acreage ahead of most competitors a n d t o a p p re c i a t e t h e favourable fiscal and attractive licence regimes. The strategic oil and gas potential, and the low political risk of assets in this EU member country, exactly match Northern’s geographical strategy.

Also brought to bear in Italy has been Northern’s aim of always bui lding good relations with governments and regulatory ministries. This helps it secure assets where i t can add value.

I n I t a l y N o r t h e r n h a s a c h i e v e d a d i v e r s i f i e d and balanced portfolio of permi ts in a number o f proven hydrocarbon basins both onshore and offshore. Northern’s focus is being rewarded as i t a t t rac ts partnerships with top industry players. The distribution of Northern’s permits in Italy means that i t wi l l suffer minimal impact from the new Environmental Law restricting nearshore exploration and deve lopment ac t i v i t i es . Northern is continuing to add to its assets in Italy. Success should be well rewarded in the medium and long term as the country is a high net importer of both oil and gas.

Strategy for an exciting asset

Northern is continuing to selectively add to its assets in Italy. Success should be well rewarded in the medium and long term as the country is a high net importer of both oil and gas.


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Reviewof2010Tullow followed up the 2010 3D seismic programme in the Guyane Maritime licence with the decision to drill the Zaedyus prospect in the south east of the country’s offshore waters close to the boundary with Brazil. GM-ES-1 was spudded in March 2011 and should reach total depth in August 2011 using the ENSCO 8503 rig. The Zaedyus prospect, is one of many prospects identified from the 3D seismic survey and is estimated by Tullow to contain a mid case oil reserve volume of 370 million barrels.

FutureThis basin has significant exploration potential and we keenly anticipate the results from testing the Zaedyus prospect to determine future activities. This is an unusual opportunity for us as a company to participate alongside a successful explorer such as Tullow and two major oil companies, Shell and Total, in the first well targeting a new exploration area of importance.

There is an additional billion barrel potential in the giant Matamata prospect a couple of hundred kilometres north westwards. This was the focus of the early 2D seismic efforts prior to the 2007 Jubilee discovery in Ghana which has been considered analogous.

Review of Operations Guyane

Guyane: overview

Guyane Maritime Licence (Northern 1.25% net beneficial interest)

StrategysummaryNorthern has a modest financial exposure in this interesting Guyane play that offers disproportionate upside on any exploration success. Tullow, the operator of the permit, has stated that it believes that there is the potential to open up a new oil province in Guyane. Geological analogies are being made with the giant Jubilee field, offshore Ghana.

The investment in Guyane, an overseas region of France, is consistent with Northern’s strategy of focusing on achieving high shareholder value with low-cost entry in countries of low political risk.

Shell France recently took up an option to increase its interest in the licence to 45%, with Tullow consequently reducing its interest to 27.5%. Total has a 25% interest with Northern having a net beneficial 1.25% interest.

Exploration phase

Exploration

Guyane GM-ES-1

“ThisbasinhassignificantexplorationpotentialandwekeenlyanticipatetheresultsfromtestingtheZaedyusprospecttodeterminefutureactivities.”

ENSCO 8503 rig

Brazil

Guyane

Suriname

Guyane Maritime

Guyana

North Atlantic Ocean

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Our goal is a continuous improvement in our high standards, systems of management and practices concerning health, safety and the protection of the environment (HSE). This is central to our business ethics and individual lives.

Northern, as a standard step in planning operations, performs site specific environmental and safety evaluations to minimise risk and ensure the safety of all persons involved. The increased field activity levels in Italy and the Netherlands requires the full commitment of all our staff and contractors to our high standards of HSE. Our constant concern is to ensure the safety of all involved and the elimination of any possible environmental contamination due to our operations.

The Company has retained the services of recognised HSE consulting groups in the UK as well as in our countries of operation, to assist Northern in achieving consistency of practice and regular awareness of ongoing HSE needs. In addition, the Company’s most operationally active subsidiary, Northern Petroleum Nederland B.V. (“NPN”) is proud to remain an active member of NOGEPA (Netherlands Oil and Gas Exploration and Production Association), thereby assisting us in maintaining the safest and most responsible operations possible. In Italy we are members of ASSOMINERARIA – the Italian Petroleum and Mining Industry Association.

During the year there were just four medical treatment cases across all of the Group’s operations and one of our service providers had a single lost time accident.

Total hours worked by Company employees 65,383Total number of hours worked by Contractors 203,770Total number of Medical Treatment Cases 4Total number of Lost Workday Cases 1

The Company’s commitment is to an HSE performance that our employees and partners can be proud of, establishing us as a good neighbour to society, contributing to sustainable development and earning the confidence of customers, joint venture partners and neighbours.

Corporate Statement – Health, Safety and the Environment

Northern Petroleum is an international business which has to face and manage a variety of strategic, operational and external risks. The Board maintains comprehensive risk reviews and in early 2011, primarily as an initial reaction to the Bribery Act 2010, formally established a Risks and Ethics Committee. Systems for the identification and management of key risks have been developed and are embedded within all activities.

Development, implementation and maintenance of risk assessment and management processes are a part of a comprehensive framework regularly reviewed by the Board. This process was in place throughout 2010 continuing up to and including the date of approval of the Annual Report.

Some of the key risks that impact on Northern, and other oil and gas businesses, are assessed below.

Risk Description Mitigation

Gas and oil commodity prices

The variation of both short and long term energy prices have an impact upon profits, cash resources and the level of our and others’ capability and appetite for investment in the industry.

Projects are evaluated at both expected and more conservative prices for products with preference given to those with greater ability to sustain any periods of lower prices.

The Group continues to be without leverage through loan gearing and any loan gearing would be examined under yet more stringent tests.

The Group does not currently hedge its product sales prices but this is regularly examined according to circumstances.

Exploration / appraisal risk

Exploration / appraisal drilling, especially offshore, can be capital intensive and by its nature can involve a significant element of risk.

Risk is mitigated by seeking to maintain a balanced portfolio of opportunities, which especially in the offshore is enhanced through the practice of farmouts.

Budgets / Approval for expenditure (AFEs) are prepared (or in the case of non-operated assets, reviewed) by an experienced operations team, and post mortems are held to ensure lessons are learned.

Employment of suitably qualified and experienced operations and technical personnel across the Group.

Field delivery risk Production and drilling activities entail operational risks which can result in cost escalation, timing delays and potentially lower than anticipated oil and gas reserves.

Operations and technical staff monitor data from production, development and appraisal wells so as to determine the necessity for changes to facility designs and drilling / workover programmes.

Operations and finance functions monitor closely costs against budgets / AFEs to identify early possible overruns to ensure that management and joint venture partners are fully appraised.

Employment of suitably qualified and experienced operations and technical personnel across the Group.

Loss of control of key assets

External political or industry factors may impact negatively on the Group’s ability to grow and manage its business.

All assets are currently located in mature countries of the European Union.

Long-term partnerships established with major international companies are sought by preference to reduce counterparty risks.

Agreements are under laws deemed enforceable and settlement through processes of public litigation is preferred to private arbitration.

Unfulfillment of work obligations

Production or exploration licences could be lost due to incomplete or untimely fulfillment of licence obligations.

Country reps, with support from operations, technical and legal functions monitor compliance with licence obligations.

The Group also maintains regular dialogue in respect of its licence activity with government authorities in the countries in which it has operations.

Availability of skilled technical staff

The availability of skilled personnel, especially in the more technical disciplines, is an inherent serious challenge facing the oil and gas industry.

Good working conditions, a policy of transparency in the workplace, maintenance of a good safety record and attractive remuneration and success based incentive policies have attracted and retained both experienced and junior staff.

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Technical, geographical, weather and other conditions

Risks of failure to maintain the Group’s high operational standards would have significant business and reputational risks which could impair the value of the Group’s assets.

The Group seeks continuous improvement in all its processes to ensure that management of both technical and business risks are regularly reviewed.

Northern has access to very competent in-house experienced professionals and staff.

Quality and experience are key components in the third party contract evaluation and award processes.

A good transparent working relationship is maintained with all service providers.

A considerable emphasis has been placed upon operational team building.

Environmental impact, health and safety failure or incident

An operational event affecting the community, staff or contractors could lead to loss of reputation, employees, local community support or revenues.

Across the Group, environmental and health and safety management systems, with clear policies and procedures, are implemented and performances are monitored regularly.

All staff are aware of their duty to be good corporate citizens and neighbours.

Political risk Northern operates in a number of overseas markets and may be affected by a change in legislation which impacts on these markets.

Political uncertainty can also discourage potential new project partners upon whom some of Northern’s business strategies may rely.

When evaluating new business opportunities or whether to maintain activity in an existing country of operation, preference is given to countries with a record of few legislative changes within the sector and within which the petroleum extraction industry is well established.

Considerable importance is placed at all times and upon all staff, consultants and suppliers upon the development of successful relationships with government authorities through the maintenance of high standards of working practices, transparency and the highest standards of integrity.

The Group also maintains involvement with industry associations within its countries of operation so that it can help shape, when industry is given the advance opportunity, proposed changes to the oil and gas legislative landscape.

Fiscal risk Northern operates in a number of overseas markets and its investment and other decisions may be affected, due to the long term nature of the oil and gas business, by a change in fiscal policies within these markets.

Fiscal uncertainty can also discourage potential new project partners upon whom some of Northern’s business strategies may rely.

When evaluating new business opportunities or whether to maintain activity in an existing country of operation, preference is given to countries with a record of few fiscal or economic changes within the sector and within which the petroleum extraction industry is well established.

The Group maintains involvement with industry associations within its countries of operation so that it can help shape, when industry is given the advance opportunity, proposed changes to the oil and gas fiscal landscape.

The assessment of risk and formulation of management systems enables focused and continual improvement in risk mitigation throughout the Group.

Risk Managementcontinued

Financial Review

The Company entered 2010 with a strong, ungeared, balance sheet, largely as a result of the substantial profits reported in both 2007 and 2008 from asset trading and operations. Having used this balance sheet to invest during 2009 a record €30 million in our asset base, predominantly on pre-production activity, the results for 2010 were expected to show the fruits of this investment. Significant further capital investment, again predominantly on pre-production activity, was planned and actually incurred in 2010.

Indeed, in terms of reported production, revenue and gross profit it has been a record year, reflecting the impact of the Grolloo and Geesbrug gas fields entering production in late 2009, complemented by first production from the Brakel and Wijk en Aalburg gas fields in September and December 2010 respectively. This operational progress in The Netherlands referred to above was complemented by the Company further bolstering its balance sheet with the completion during June of its first placing since May 2006.

However, the income statement for the year does not mirror this operational progress, with the Group ultimately reporting a loss after tax following the Board’s decision, as announced on 27 May, to revise downwards the Group’s 2P reserves by 75.24 Bscf, which is the equivalent of 12.97 million barrels of oil equivalent, in respect of the Geesbrug, Grolloo and Wijk en Aalburg gas fields. The additional non-cash depletion and impairment charges incurred as a result of the reserves reduction were approximately €3 million.

A summary of key financial indicators are listed in the table below.

Year ended31 December

2010€’000


2009€’000

Revenue 14,968 5,084Gross profit 6,697 1,482EBITDA (i) 5,083 (2,231)Adjusted EBITDA (ii) 6,475 (174)Loss for the year (1,155) (2,151)

Basic loss per share on result for the year (1.3) € cents (2.9) € cents

Capital expenditure 13,688 29,707Cash and cash equivalents 21,430 15,002Other working capital 2,466 3,476Net assets 85,371 73,764Total Group distributable reserves 54,039 54,769

Production (million boe) 0.44 0.13

Average revenue, in currency of receipt, per boe:Gas €32.69 €33.45Oil $73.58 $56.43

Unaudited Net Commercial Oil & Gas Reserve Quantities – Proven and Probable reserves (million boe)

89.45 102.88

(i) Earnings before interest (and other finance income and costs), tax, depreciation, depletion, amortisation and write offs of oil and gas assets.(ii) In addition to the above, is calculated before share-based payments and pre-licence costs.

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The results for the Group for the year ending 31 December 2010 show a loss before tax of €0.02 million compared with a loss before tax of €3.12 million for the year ended 31 December 2009. The basic loss per share is 1.3 € cents, compared to a loss of 2.9 € cents in 2009.

The major components of the reduction in the pre-tax loss of €3.10 million have been:

• an increase of €5.22 million in gross profit, as a result of increased revenues more than offsetting increases in production costs, and in non-cash charges for both depreciation and amortisation and asset impairments (even after taking into account the additional charges resulting from the reserves reductions referred to above and as announced on 27 May);

• a decrease of €2.32 million in net finance income; • an increase of €0.11 million in administrative expenses; and• a decrease of €0.25 million in pre-licence and other exploration expenditures written off, reflecting less new business and licence

application activity compared to that incurred principally in the second half of 2009.

The small pre-tax loss results in a tax charge for the year of €1.14 million, principally in respect of our profitable Dutch operations, compared to a tax credit of €0.97 million for 2009.

Most of the increase of €5.22 million in gross profit can be put down to rising production from new fields being put on stream in both 2009 and 2010. A revised price formula was introduced for 2010 which gave greater weight to the spot gas price. Average gas prices were 2.3% lower than in 2009, however the downwards trend in prices in 2009 was reversed in 2010 and the price has continued to rise in 2011.

After adjusting for the effect of the Brakel and Wijk en Aalburg gas fields entering production later than anticipated at the beginning of 2010, the overall result for the year is in line with budget. The result for the year is also broadly in line with our expectations at the time of the interim results, given the then revised expectations on timing of production from Brakel and Wijk en Aalburg, and the shut in of production due to a workover at Grolloo in the second half.

Given the significant pipeline of opportunities that remain available to the Group within its existing asset base, the Board has decided that it would not be appropriate to propose a dividend at this time.

The Board sanctioned significant, but as anticipated reduced, capital expenditure of €13.7 million during the year, a decrease over 2009 when record capital expenditure totalling €29.7 million was incurred across the full E&P cycle.

Production Actual production net to Northern was 0.44 million barrels of oil equivalent (“boe”), comprising 2.44 bcf of gas (2009 – 0.69 bcf), 7,975 barrels of gas condensate (2009 – 2.352 barrels) and 7,062 barrels of oil (2009 – 8,344 barrels), with an average price received for gas and oil during 2009 of €32.69 per boe (2009 – €33.45 per boe) and US$73.58 per barrel (2009 – US$ 56.43 per barrel) respectively.

Gas production from the P12 and Waalwijk operations decreased by 29.3% (2009 – decreased by 12.1%), but overall production was enhanced by a full year of production from the Grolloo and Geesbrug gas fields (which both came on stream in December 2009), plus first production from the Brakel and Wijk en Aalburg gas fields, which came on stream in September and December 2010 respectively. Oil production from continuing operations decreased by 15.4% (2009 – decreased by 1.6%), with Avington production declining by 40% compared to a more modest 8% decline seen at Horndean. Horndean especially, with its low operating costs, remains highly profitable and a useful contributor to cashflow. Production from Avington generated a small profit for the Group despite its modest production.

Accounting Policies These financial statements have been prepared by the Board using accounting policies consistent with 2009, other than where new Standards or Interpretations have been required to be adopted, as summarised below.

The following Standards or Interpretations adopted during the year have affected the reported results and financial position of the Group, but their impact has not been material:

• Revised IFRS 3 – Business Combinations;• IAS 38 – Intangible Assets;• IAS 27 – Consolidated and Separate Financial Statements;• IFRS 2 – Share-based payments; and• IAS 36 – Impairment of assets. The following new and revised Standards adopted during the year, IAS 1 – Presentation of Financial Statements and IAS 7 – Statement of Cash Flows, have solely resulted in changes to presentation and disclosure within the 2010 financial statements.

Further details on these policy changes are included within the accounting policy notes starting on page 49 (Group) and page 84 (Company).

Taxation The Group has reported a tax expense of €1.14 million for the year. This tax expense is almost entirely related to the Group’s profitable operations in The Netherlands, with little credit being taken on losses incurred in the UK and Italy, (see note 2 “Segmental information” for further details).

Taxable profits were offset by losses, mainly in the UK, resulting in an overall pre-tax loss of €0.02 million. UK and Italian losses, however, are not expected to be utilised for at least a year and with Markwells Wood not expected to receive production consent until spring 2012 at the earliest, no net deferred tax credits have been recognised in the 2010 accounts in respect of the UK or Italy. Once Markwells Wood production has been fully established, a tax credit will be recognised in respect of the prior year losses then available to offset future profits.

In the 2009 Annual Report, the Group noted the proposed further amendments by The Ministry of Finance of The Netherlands (“The Ministry”) to the Regulation for Depreciation At Will 2001 (“DAW”), but at that time had not yet decided to take advantage of the rule changes. I am pleased to report that the Group now has elected to utilise DAW for qualifying capital expenditure by its Dutch subsidiary, Northern Petroleum Nederland B.V. (“NPN”), in both 2009 and 2010. These qualifying expenditures are in respect of the Grolloo, Geesbrug, Brakel and Wijk en Aalburg fields, all of which were put into production within the initial 2009–2010 qualifying period. This use of DAW has therefore resulted in additional Dutch tax losses for those two years, which are available to be carried back in respect of profits from years prior to 2009. This election will clearly be of considerable near term immediate cash flow benefit to the Group, although the obvious quid pro quo is that NPN will have less costs deductable for tax purposes in future years. This also has contributed to the reported increase in the deferred tax liability year on year.

Whilst the introduction of DAW was designed to stimulate capital investment by Dutch companies, clearly the announcement by the British Chancellor to increase the rate of UK Supplementary Charge to Corporation Tax (“SCT”) will have the opposite effect on E&P companies with UK assets. The significant increase in SCT from 20% up to a maximum of 32%, effective from 24 March 2011, will give a total tax rate for ring fence profits of up to 62%. This increase will have no immediate detrimental effect on the Group given existing production levels, and could in theory mean certain UK assets might be worth more to Northern than they would be in the hands of another party.

Medium to long term fiscal stability, (and predictability), are key ingredients in E&P investment decisions, and form an important consideration when Northern evaluates whether to enter a new country of operation. Let us hope that, even in these austere times, governments that are contemplating fiscal changes consider wisely which of the recent Dutch or UK models might be in the best interests of long term security of supply.

For more detailed information on the Group’s tax position shareholders are referred to notes 8 and 17.

Financial Reviewcontinued

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Capital StructureThe following changes to the capital structure of the Group occurred during the year.

Shares and WarrantsDuring June 2010 your Board decided to strengthen the balance sheet and raise additional funds via an institutional share placing. A total of 11,764,706 shares were issued to a number of institutions at 85p per share, raising approximately £9.5 million after expenses. The placing was made pursuant to the authority granted by shareholders on 22 July 2009. The net proceeds of the placing were raised primarily to fund additional seismic and drilling activity in Italy and The Netherlands.

The net effect of all the share issues during 2010 was to raise the total number of ordinary shares in issue by 13,000,197, approximately 16.5% year on year. Of that increase, 11,764,706 (90.5%) is attributed to the shares issued on 25 June 2010 on completion of the placing referred to above.

Of the remaining 1,235,491 shares issued during the year, 755,000 were in respect of warrants exercised for cash, raising a total of approximately €0.27 million, while a further 480,491 shares were issued to staff and Directors at 146.4375p (418,247 shares) and 88.875p (62,244 shares) per share in lieu of bonuses and salary payments respectively.

At the year end there were approximately 7.81 million warrants in issue, which represented 8.5% of issued share capital and which had exercise prices in the range of 11.25p to 252p. A total of approximately 0.45 million warrants with exercise prices ranging from 127.5p to 150p were issued during the year to new employees, representing a continuation of the Board’s policy of granting warrants as an incentive to attract, motivate and retain senior management and key personnel.

Overall there was therefore a net decrease of approximately 5.6% (2009 – increase of 4.0%) year on year in the number of warrants in issue.

Debt Financing With surplus funds and no debt financing for projects, the Group remained debt free throughout the year.

Your Board remains keen to have in its armoury some debt facilities to both provide flexibility for growing the business and for tax efficiency, but the finance must be at a reasonable cost and based on appropriate security. Production levels are now deemed sufficient that the Group, together with its reserve base, is now in a better position to, and is therefore more likely to, enter into a reserved based lending facility in due course.

Risk AssessmentThe Group’s oil and gas activities are subject to a range of financial and operational risks, as described below, which can significantly impact its performance.

Additional details on the financial risks the Group faces are given in note 22 to the financial statements, which covers IFRS disclosures on financial instruments.

Oil And Gas Price RiskOil and gas sales revenue is subject to energy market price risk – calendar year 2010 saw a continuation of the 2009 trend of gradual, but significant, upward momentum in prices compared to the wild swings experienced in 2008. Given events in the Middle East and Japan since the turn of the year, which have given added emphasis to the security of supply debate, it is not surprising that the upward momentum has continued despite the backdrop of patchy growth in most first world countries.

The Group’s oil and gas sales revenue in 2010 comprised oil and gas on long term supply contracts, the vast majority of which is gas sales committed to GasTerra B.V. (Waalwijk, P12, Grolloo, Geesbrug, Brakel and Wijk en Aalburg). The Group has as yet, and does not currently plan to, enter into any hedging activities, although as production levels increase this position will come under more regular scrutiny. For more information see the “Financial Instruments” section below.

Liquidity and Interest Rate Risks Given the ongoing financial crisis almost every company faces greater liquidity risk at present than it did a year ago. We are however comforted that as the Group is currently debt free, and has working capital balances totalling €2.4 million at the year end. Our balance sheet will allow us to continue to progress our portfolio and seek additional low cost entry opportunities, in accordance with the Group’s strategy, as they arise. With first production having been achieved in 2010 at Brakel and Wijk en Aalburg, adding to Grolloo and Geesbrug having come on stream late last year, as described above the Group is well positioned to, and highly likely to, expand its armoury with an appropriate level of debt at the appropriate time.

Cash forecasts identifying the liquidity requirements of the Group are reviewed regularly by management and the Board to ensure that sufficient financial headroom exists for at least a twelve month period. The Board only adds commitments when it judges that there is sufficient headroom in the Group cash balances.

Despite capital expenditure of €13.7 million in 2010, principally on pre-production activity, the year end cash balance of €21.4 million was €6.4 million higher than at the end of 2009, as a result of cash flow from record production and the equity raise of €11.5 million.

In light of the Group’s continued desire to retain flexibility to pursue as aggressively as possible its exploration, appraisal and development portfolio, and to enable selective acquisition opportunities to be considered, surplus funds remained liquid during the majority of the year. Following, and in response to, the 2008 banking crisis, and the resulting significant reductions in interest rates, the focus had switched more towards preservation of capital. Since the start of 2011, the Group has decided to once again more proactively seek to increase the returns on its cash, which is being supervised by a newly formed Treasury Committee.

Given its extensive licence position the Group remains opportunity rich, but relative to the number of those opportunities, especially those offshore, is cash poor. Whilst the Group can finance less capital intensive, principally onshore, projects from internal resources and with debt for projects where there is currently proven and / or probable oil or gas in the ground, there currently remains a significant reliance on third parties, principally farminees, to allow the Group to progress the more capital intensive projects that exist offshore Italy.

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Currency Risk As in previous years the majority of capital expenditure in the year was denominated in Euro, the balance being in Sterling, and to a lesser extent, US and Canadian Dollars. Ever since 2006, when the Company converted £12 million into Euro at an average Euro / Sterling exchange rate of 1.478, the Group has held most of its liquid funds in Euro so as to naturally hedge its medium term forward capital expenditure programme. Few significant foreign currency dealings have therefore been required during 2010 and no significant additional transactions are contemplated at present.

Following the change in functional and presentational currency to the Euro during 2008, the Group now has four subsidiaries, plus the Italian branch of Northern Petroleum (UK) Limited, which maintain accounting records denominated in Euro, in line with the Company’s current functional currency. A number of the Company’s less active, and hence less material subsidiaries, continue to retain Sterling as their functional currency, so movements in the Euro / Sterling exchange rate will still affect the Group’s balance sheet, but the impact should be small, with any exchange differences that arise on consolidation being taken to reserves not the income statement. The change in functional currency to the Euro is therefore continuing to have the welcome consequence of ensuring the impact of currency movements is modest: in 2010 the exchange difference on translation of foreign operations shown in the Consolidated Statement of Comprehensive Income was a €164,000 credit, compared to a €41,000 charge in 2009.

The majority of gas sales revenues and operating costs associated with the Group’s Dutch and Italian assets are in Euro and thereby are naturally hedged, however there is the likelihood that Dutch oil revenues, as with the Group’s small UK oil revenues, will be denominated in US Dollars, while the majority of costs incurred on the UK assets will be in Sterling, neither of which are the reporting or functional currency of the Company. Consequently exchange gains or losses will continue to occur and be reported within future income statements.

A combination of all these factors has led to a €0.35 million loss on exchange for 2010 (2009: €0.57 million profit on exchange), much of which reflects the effect of the movements in Euro / Sterling exchange rate on the Group’s reported cash balances.

Financial Instruments In light of the current relatively modest foreign exchange exposures, and the reasonably robust cash balances as set out above, it was not considered either appropriate or necessary for the Group to enter into any hedging activities or trade in any financial instruments, such as derivatives, during the year. This strategy will be subject to ongoing review as the Group grows and the potential exposures increase.

Operational RiskOperational risks include equipment failure, well blowouts, pollution, fire and the consequences of bad weather. These risks cannot be understated given 2010 saw the Deepwater Horizon incident in the Gulf of Mexico, which unfortunately for the Group occurred just prior to our annual insurance renewal, which meant that deductions in premiums were not as significant as they might otherwise have been. The Group is justifiably proud of its accident free and claim free record.

The Deepwater Horizon has obviously led to both increased internal scrutiny of safety procedures and processes, and external scrutiny by regulatory authorities in each of our areas of operation, but with contrasting results / reactions from the latter. This has necessarily involved closer and more regular liaison with the Group’s insurance advisers, to whom I give thanks for their cooperation in an understandably difficult period for their industry as well as ours.

As members of the Group remain project operator of the vast proportion of its oil and gas interests, it takes increased responsibility, as part of that role for its operated producing fields, field developments and exploration drilling programmes, to ensure that all relevant legislation is met, and that all partners have appropriate insurance cover in place. The Group has insurance policies in place to mitigate these risks, and these policies contain overall limits and deductibles, which are reviewed for reasonableness each year prior to policy renewals. Additional reviews are undertaken prior to drilling to ensure that any necessary revisions to coverage, for example due to changes in well depths or complexity, or changes to well costs since policy inception, are implemented.

Cautionary StatementThis Annual Report contains certain judgements / assumptions and forward looking statements and assumptions that are subject to the normal risks and uncertainties associated with the exploration, development and production of oil and gas. Further information on some of the key judgements / assumptions can be found on page 53 under the “Critical accounting judgments and key sources of estimation uncertainty” section of the Accounting Policies note. Whilst the Directors believe that expectations reflected throughout this Annual Report are reasonable based on the information available at the time of approval of this Annual Report, actual outcomes and results may be materially different due to factors either beyond the Group’s reasonable control or within the Group’s control but, for example, following a change in project plans or corporate strategy. Therefore absolute reliance should not be placed on these judgements / assumptions and forward looking statements.

Annual General Meeting ResolutionsFinally I would like to briefly address one of the special resolutions to be proposed by the Board for the next Annual General Meeting (“AGM”) which this year is to be held on 29 June.

Shareholders approved at each of the last three AGMs a resolution to make market purchases in the Company’s own shares. Whilst the Board has chosen not to purchase any of its own shares since first being granted the authority by shareholders, the Company continues to have a significant amount of distributable reserves. Therefore the Board would once again like to maintain as much balance sheet flexibility as possible, and with that in mind is again proposing to give itself the option to increase shareholder value by making market purchases of the Company’s own shares, initially up to a maximum of 4,650,000 shares, which will represent approximately 5% of the share capital expected to be in issue as at the date of the AGM. This is the same in percentage terms as set last year. Further information on the terms under which the Company seeks such authorisation will be contained within resolution 6 of the AGM Notice.

No changes are proposed to the Company’s Articles of Association this year.

I hope that shareholders will feel able to support this year’s resolutions, and trust that there will be the usual excellent level of attendance at the AGM.

C J FossDirector of Finance, Legal & Corporate Affairs7 June 2011


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1. Derek Musgrove M.ENG. B.Sc.Managing DirectorDerek Musgrove has held the position of Managing Director since 1999. He had previously held senior managerial or board positions with RTZ Oil & Gas Limited, Candecca Resources Plc, Plascom Plc, Anglo Scandinavian Petroleum Plc and Bass Resources Limited. He was also a consultant to a number of oil and gas companies particularly in the areas of management, new projects and trading of oil and gas properties, as well as pursuing personal interests in the natural resources sector.

2. Graham Heard B.Sc., CGEOL FGSExploration and Technical DirectorGraham Heard was appo in ted as Exploration and Technical Director in May 2007, having been the Exploration Manager of Northern for the previous four and a half years. He is a former Chairman (1991) of the Petroleum Exploration Society of Great Britain. Graham has over 35 years’ experience as a petroleum geologist, beginning his career with Arco and then gaining extensive international experience with independents Siebens Oil and Quintana Petroleum. He subsequently held various executive positions with Sovereign Oil & Gas Plc, Neste Production Limited and Sands Oil & Gas Plc.

3. Chris Foss B.Sc. (ECON), ACADirector of Finance, Legal & Corporate Affairs and Company SecretaryChris Foss was appointed to the position of Director of Finance, Legal & Corporate Affairs in September 2010. Chris previously served as Director of Legal & Corporate Affairs from April 2010, Finance Director from August 2005, and Group Financial Controller and Company Secretary since January 2003. He was also Finance Director of PLUS quoted ATI Oil Plc from 2004 up until its acquisition by Northern in 2009. Chris is a member of the Institute of Chartered Accountants in England and Wales. Between 1998 and his joining the Company, Chris held various finance positions with, and acted as a consultant to, energy related subsidiaries of GE Capital Corporation, Bechtel Group Inc, United Technologies Corporation and Centrica Plc.

4. Richard Latham MBAChairmanRichard Latham was appointed Non-Executive Chairman during June 1999 and has been a member of the Board since 1995. He is also Non-Executive Chairman of Strategic Natural Resources Plc, Chairman of Ascension Holdings Limited and a number of its associated companies, Chairman of Obsidian Energy Limited and Chairman of Obsidian Minerals Limited. Richard holds an MBA degree from Cranfield and has spent most of his working life in the City – initially as an Investment Manager and for over 26 years with companies in the upstream oil and gas industry. He was formerly Deputy Chairman of Aberdeen Petroleum Plc, Chairman and Managing Director of Claremount Oil and Gas Limited and a Non-Executive Director of Atlantis Resources Limited, a company listed on the London and Toronto Stock Exchanges.

5. Jeremy White MA (OXON), FCADirectorJeremy White is currently a Non-Executive Director and is Chairman of the Audit and Health and Safety Committees, and a member of the Remuneration and Nomination Committee, having previously been Finance Director until August 2005. He is a Fellow of the Institute of Chartered Accountants in England and Wales. He has worked in the oil industry for over 25 years, and immediately before joining Northern he was UK Group Tax Controller for PetroFina’s UK operations.

6. Anthony Brewer MSIDirectorAnthony Brewer was appointed as a Non-Executive Director during August 2006 and is currently Chairman of the Remuneration and Nomination Committee and a member of the Audit Committee. He has over forty years of experience in fund management and broking, in investment analysis, institutional sales and corporate finance, and has specialist knowledge of the oil and gas sector.

Directors and Advisers

1 2 3 5 6

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DirectorsR H R LathamChairman

D R MusgroveManaging Director

C J FossDirector of Finance, Legal & Corporate Affairs

G L HeardExploration and Technical Director

J M WhiteNon-Executive

A N BrewerNon-Executive

SecretaryC J Foss, ACA

Registered OfficeMartin House5 Martin LaneLondon EC4R 0DPTelephone: 020 7469 2900Facsimile: 020 7469 2901E-mail: [email protected]

Registered No.02933545

Legal FormPublic limited company

Country of Incorporation of Parent CompanyEngland

Italy OfficeNorthern Petroleum (UK) LimitedViale Trastevere, 24900153 RomeItaly

Netherlands OfficeNorthern Petroleum Nederland B.V.Lange Voorhout 862514 EJDen HaagThe Netherlands

Independent AuditorsKPMG Audit PlcKPMG Audit Plc15 Canada Square London E14 5GL

BankersING Bank N.V.Tournooiveld 62511 CX Den HaagThe Netherlands

Lloyds Banking Group 10 Gresham StreetLondon EC2V 7AE

Staten Bolwerk 12011 MK HaarlemThe Netherlands

UniCredit BancaPiazza Cavour BRomeItaly

Nominated Adviser and Joint BrokerCenkos Securities Plc66 Hanover StreetEdinburgh EH2 1EL

Joint BrokerJefferies International LimitedVintners Place68 Upper Thames StreetLondon EC4V 3BJ

SolicitorsBerwin Leighton PaisnerAdelaide HouseLondon BridgeLondon EC4R 9HA

Gordons22 Great James StreetLondon WC1N 3ES

RegistrarsNeville RegistrarsNeville HouseLaurel Lane HalesowenWest Midlands B63 3DA

Investor RelationsFinancial Dynamics Holborn Gate26 Southampton BuildingsLondon WC2A 1PB

Public RelationsBishopsgate Communications 3 London Wall BuildingsLondon WallLondon EC2M 5SY

Directors and Adviserscontinued

Directors’ Report

The Directors present their report together with the accounts for the year ended 31 December 2010.

Principal Activity and Review of the BusinessThe Company’s and its subsidiaries’ principal activities are the exploration, development and production of oil and gas assets. Current activity is mainly carried out in The Netherlands, Italy, UK and Guyane. The Board has considered, and will continue to consider, exploration, development and production opportunities in other parts of the world.

A more detailed review of the Group’s business and assets is set out in the Chairman’s Statement, the Review of Operations and the Financial Review.

Results and DividendsThe Group has reported a net loss for the year of €1,155,000 (2009 loss: €2,151,000).

The Directors do not recommend payment of a dividend (2009: €Nil).

Going ConcernThe Directors consider the use of the going concern basis of accounting is appropriate for the Company and the Group because no material uncertainties related to events or conditions that may cast significant doubt about the ability of the Company and the Group to continue as a going concern have been identified by the Directors.

The Group’s strategy, business activities, together with the factors likely to affect its future development, performance and position are set out in the Report of the Board and the Review of Operations. The management team are experienced in forecasting and when assessing opportunities for sanction are comfortable that they are not over committing the Group. The Directors intentionally committed much of the Group’s 2010 capital spend on near term development projects so as to achieve enhanced near term revenues, whilst leaving a reasonable cash balance of €21.4 million at the 2010 year end. The Board has processes in place to ensure that no expenditure is authorised which would take the Group’s forecast cash balance below a level the Board considers is appropriate for the use of the going concern basis for preparation of its accounts.

The Financial Review describes the oil and gas pricing risks, liquidity and interest rate risks, currency risks and operational risks the Company faces and some of the actions the Company has in place to manage these risks.

Note 22 to the Accounts describes, and where appropriate quantifies, the risks the Company is exposed to, namely:

• credit risk resulting from the failure of a customer or counter party to meet its contractual obligations;• interest rate risk resulting from a reduction in interest rates reducing finance income;• foreign exchange risk resulting from costs and revenues being in different currencies;• liquidity risk resulting from the inability of the Company to meet its contractual obligations when they fall due; and• price risk from reductions in product prices resulting in a reduction in income.

The Group had cash resources of approximately €21.4 million (2009: €15.0 million) at the year end, and remains free of third party debt. As a consequence, the Directors believe that the Group is well placed to manage its business risks successfully and finance its current commitments.

The Group has created a substantial range of projects and opportunities many of which are described in this Annual Report and Accounts. It is clear that the Group can only fund a very small portion of these opportunities, and clearly not the capital intensive offshore projects, from its current cash balances. Some projects will be funded from cash flow from production, whilst others will have to wait on cash created by trading of assets and other projects will require farming out before they can progress. The Group has no external debt but now has the production and reserve base to obtain debt and the Board is highly likely to seek to use this capacity to fund some projects. In addition the Company has authority from its shareholders to raise cash by the issue of new shares to fund its programmes.

Before sanctioning any expenditure on significant new projects the Board ensures that the Group has certainty of funding. The Group does not commit to spend cash it does not have, or does not have a reasonable certainty of having. Clearly, judgement is required as to the certainty of the availability of funds. The Board carefully considers the risks described above in making these judgements. The Executive Directors have an average of approximately 30 years of experience on which to draw in making these judgements.

After making appropriate enquiries, the Directors have a reasonable expectation that the Group has adequate resources to meet all of its commitments and to continue in operational existence for the foreseeable future. Accordingly they continue to adopt the going concern basis in preparing the Annual Report and Accounts.

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Directors and Their InterestsThe Directors of the Company, who all served throughout the year, except where otherwise stated, are listed below. The Directors’ beneficial interests in the shares of the Company as at the below dates were:

At 31 December 2010(ordinary 5p shares)

At 31 December 2009(ordinary 5p shares)

A N Brewer 81,391 75,000C J Foss 107,565 67,076G L Heard 587,497 428,408R H R Latham 962,477 752,587D R Musgrove 1,037,260 991,666J M White 145,071 138,275N J Wright (Appointed 12 April 2010, resigned 26 August 2010) N/A N/A

2,921,261 2,453,012

The Directors have been granted warrants exercisable into shares of the Company. Further details of these interests are shown in the Report on Directors’ Remuneration.

Other than as shown above, no Director had any interest in the shares of the Company or any of its subsidiaries at 31 December 2010 or at 31 December 2009.

Mr A N Brewer retires from office in accordance with Article 108 of the Company’s Articles and, being eligible, offers himself for re-election at the upcoming AGM.

The Company maintains Directors’ and Officers’ insurance for the benefit of Directors and Officers of all Group companies, and has also indemnified the Directors to the fullest extent possible allowed under the Companies Act 2006 and the Company’s Memorandum and Articles of Association.

Directors’ Interest in TransactionsNo Director had, during or at the end of the year, a material interest in any other contract which was significant in relation to the Group’s business, except in respect of personal service agreements and warrants.

Employees The Group seeks to keep employees informed and involved in the operations and progress of the business by means of regular staff meetings, by country, open to all employees and Directors.

The Group operates an equal opportunities policy. The policy provides that full and fair consideration will be given to applications for employment from disabled people and people of any racial background, gender or sexual orientation. Existing employees who become disabled, to the extent that they are unable to perform the tasks they were employed to carry out, will have the opportunity where practical to retrain and continue in employment wherever possible.

Substantial InterestsThe following interests appeared in the register as at 23 May 2011:

Name Shares % of issued

Pershing Nominees Limited 6,015,438 6.46%TD Waterhouse Nominees (Europe) Limited 5,308,920 5.70%Barclay Share Nominees Limited 4,824,325 5.18%The Bank of New York (Nominees) Limited 4,220,603 4.53%Hanover Nominees Limited 4,042,340 4.34%Nortrust Nominees Limited 3,790,722 4.07%Hargreaves Lansdown (Nominees) Limited 3,442,517 3.70%L R Nominees Limited 3,379,967 3.63%HSDL Nominees Limited 3,139,738 3.37%

In addition, as at 6 June 2011, the Company has been advised of the following beneficial holdings of 3% or more of the issued share capital in accordance with the Transparency Obligations Directive (Disclosure and Transparency Rules) Instrument 2009:

Name Shares % of issued

Barry Lonsdale 5,558,661 5.97Royal Bank of Scotland Group Plc 4,679,491 5.03Majedie Asset Management Limited 3,689,100 3.96

Financial InstrumentsDetails of the financial risk management objectives and policies, and details on the use of financial instruments by the Company and its subsidiary undertakings, are provided in the Financial Review and in note 22 to the financial statements.

Supplier Payment PolicyIt is the Group’s policy to negotiate clear and satisfactory arrangements for the payment of suppliers as part of the overall terms and conditions of the supply and to make payment accordingly. At 31 December 2010, the Group had an average of 14 (2009: 18) days of purchases outstanding in trade payables.

Communication with ShareholdersThe Company provides extensive information about the Group’s activities in the Annual Report and Accounts, copies of which are sent to shareholders. Additional copies of this, and the Interim Report, are also available by application to the Company Secretary. The Group is active in communicating with both its institutional and private shareholders and welcomes queries on matters relating to shareholdings and the business of the Group. All shareholders are encouraged to attend the Annual General Meeting, to be held this year on 29 June in London, at which Directors and senior management will be introduced and available to answer questions. The Company also makes every effort to keep its website as up to date as possible.

AuditorIn accordance with Section 489 of the Companies Act 2006, a resolution for the re-appointment of KPMG Audit Plc as auditor of the Company is to be proposed at the forthcoming Annual General Meeting.

Disclosure of Information to AuditorsThe Directors who held office at the date of approval of this Directors’ Report confirm that, so far as they are each aware, there is no relevant information of which the Company’s auditors have not been made aware; and each Director has taken all the steps that he ought to have taken as a Director to make himself aware of any relevant information and to establish that the Company’s auditors are aware of that information.

By order of the Board on 7 June 2011

C J Foss (Secretary to the Board)

Directors’ Reportcontinued

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Report on Directors’ Remuneration

Remuneration and Nomination CommitteeThe Company’s Remuneration and Nomination Committee is chaired by A N Brewer and the Committee’s other member is J M White. The Committee meets at least twice a year. Other Directors often attend meetings by invitation but are not involved in any matter relating to themselves.

The information in this report has been given on a voluntary basis, as the Company is listed on AIM rather than the Full List, and is therefore not required to provide information that complies fully with the Companies Act 2006 requirements.

Remuneration PolicyThe Committee makes recommendations to the Board on an overall remuneration package for all Directors and senior management. The Committee takes into account Group and individual performance, market value and sector conditions. The Company ensures that pay is set at an appropriate level and is comparable with peer group companies in the independent oil and gas sector.

There are four elements of the remuneration package for Directors and senior management:

• basic annual salary or fees;• benefits in kind;• bonus scheme; and• long term incentive plan, which has to date been represented by warrants.

Notice PeriodsThe notice period of Executive Directors is eighteen months, while that of Non-Executive Directors is nine months.

Basic Salary or FeesExecutive Directors are salaried employees, while the remuneration of Non-Executive Directors is by way of fees.

Basic salaries or fees are reviewed annually, or when an individual changes position or responsibility. In deciding appropriate remuneration levels, Group and individual performance and market factors are considered.

In addition to basic salary or fees, Directors receive certain benefits in kind. Executive Directors receive life assurance, critical illness and private medical and dental insurance, while Non-Executive Directors are only entitled to private medical insurance.

Annual Bonus Scheme A one year bonus scheme has been recommended for 2011. As in previous years the mechanism used has two parts – a performance related bonus based on collective and individual targets, based on a percentage of each individual Director’s average annual salary for 2011, and a further percentage of salary based on share price performance.

Any bonus will be paid in January 2012, half in cash and half in new shares. The number of new shares issued will be determined by the average mid market price prevailing in the first three weeks of January 2012. Any Director who resigns prior to the settlement date will be ineligible to receive a bonus. Long Term Incentive SchemeThe Board believes that the attraction, motivation and retention of senior management is central to the Group’s success. To date this has been carried out by the issue of warrants to Directors; this has been considered an effective incentive and a crucial means of achieving this objective.

All warrants are issued at a price not lower than the prevailing market price of the Company’s shares at the date of issue.

The Remuneration and Nomination Committee will continue to, on at least an annual basis, review the effectiveness of the current scheme. In view of the recent tax changes the scheme will be kept under constant review in 2011.

Statement of Directors’ Responsibilities in Respect of the Annual Report and the Financial Statements

The Directors are responsible for preparing the Annual Report and the Group and Parent Company financial statements in accordance with applicable law and regulations.

Company law requires the Directors to prepare Group and Parent Company financial statements for each financial year. As required by the AIM Rules of the London Stock Exchange they are required to prepare the Group financial statements in accordance with IFRSs as adopted by the EU and applicable law and have elected to prepare the Parent Company financial statements in accordance with UK Accounting Standards and applicable law (UK Generally Accepted Accounting Practice).

Under company law the Directors must not approve the financial statements unless they are satisfied that they give a true and fair view of the state of affairs of the Group and Parent Company and of their profit or loss for that period. In preparing each of the Group and Parent Company financial statements, the Directors are required to:

• select suitable accounting policies and then apply them consistently;• make judgements and estimates that are reasonable and prudent;• for the Group financial statements, state whether they have been prepared in accordance with IFRSs as adopted by the EU;• for the Parent Company financial statements, state whether applicable UK Accounting Standards have been followed, subject to any

material departures disclosed and explained in the financial statements; and• prepare the financial statements on the going concern basis unless it is inappropriate to presume that the Group and the Parent

Company will continue in business.

The Directors are responsible for keeping adequate accounting records that are sufficient to show and explain the Parent Company’s transactions and disclose with reasonable accuracy at any time the financial position of the Parent Company and enable them to ensure that its financial statements comply with the Companies Act 2006. They have general responsibility for taking such steps as are reasonably open to them to safeguard the assets of the Group and to prevent and detect fraud and other irregularities.

The Directors are responsible for the maintenance and integrity of the corporate and financial information included on the Company’s website. Legislation in the UK governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

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Report on Directors’ Remunerationcontinued

Warrants held by Directors serving at 31 December 2010 were as follows:

At 1 January

2009’000s

Issued’000s

Exercised’000s

At 1 January

2010’000s

Issued’000s

Exercised’000s

At 31 December

2010’000s

A N Brewer:At 117.0p (exercisable by 31 October 2011) 150 – – 150 – – 150At 68.5p (exercisable by 31 December 2013) 105 – – 105 – – 105

255 – – 255 – – 255C J Foss:At 12.5p (exercisable by 31 July 2011) 200 – – 200 – – 200At 130.0p (exercisable by 31 July 2011) 275 – – 275 – – 275At 68.5p (exercisable by 31 December 2013) 193 – – 193 – – 193At 80.0p (exercisable by 30 April 2013) – 31 – 31 – – 31At 252.0p (exercisable by 16 June 2013) – 31 – 31 – – 31

668 62 – 730 – – 730G L Heard:At 11.25p (exercisable by 31 July 2011) 140 – (40) 100 – (100) –At 130.0p (exercisable by 31 July 2011) 125 – – 125 – – 125At 138.5p (exercisable by 31 December 2012) 100 – – 100 – – 100At 68.5p (exercisable by 31 December 2013) 175 – – 175 – – 175

540 – (40) 500 – (100) 400R H R Latham:At 15.625p (exercisable by 31 July 2011) 120 – – 120 – (120) –At 11.25p (exercisable by 31 July 2011) 280 – – 280 – (280) –At 130.0p (exercisable by 31 July 2011) 150 – – 150 – – 150At 68.5p (exercisable by 31 December 2013) 105 – – 105 – – 105

655 – – 655 – (400) 255D R Musgrove:At 15.625p (exercisable by 31 July 2011) 250 – – 250 – – 250At 11.25p (exercisable by 31 July 2011) 660 – – 660 – – 660At 130.0p (exercisable by 31 July 2011) 400 – – 400 – – 400At 68.5p (exercisable by 31 December 2013) 280 – – 280 – – 280At 80.0p (exercisable by 30 April 2013) – 31 – 31 – – 31At 252.0p (exercisable 16 June 2013) – 31 – 31 – – 31

1,590 62 – 1,652 – – 1,652J M White:At 15.625p (exercisable by 31 July 2011) 120 – – 120 – – 120At 11.25p (exercisable by 31 July 2011) 280 – – 280 – – 280At 130.0p (exercisable by 31 July 2011) 150 – – 150 – – 150At 68.5p (exercisable by 31 December 2013) 105 – – 105 – – 105

655 – – 655 – – 655

Total 4,363 124 (40) 4,447 – (500) 3,947

Directors’ RemunerationRemuneration earned by Directors who served during the year was as follows:

Presented in Euro Year ended 31 December 2010 Year ended 31 December 2009

Salaryor fees

€’000Bonus€’000

Compen-sation

for loss of office

€’000

Otherbenefits

€’000Total

€’000

Salaryor fees€’000

Bonus€’000

Otherbenefits

€’000Total

€’000

Executive Directors (salaries):C J Foss 247 – – 11 258 231 115 9 355G L Heard 230 – – 9 239 223 115 9 347D R Musgrove 317 – – 15 332 299 150 13 462N Wright 80 – 219 2 301 – – – –

Non-Executive Directors (fees):A N Brewer 42 – – 3 45 41 21 3 65R H R Latham 65 – – 6 71 63 33 5 101J M White 45 – – 2 47 43 22 2 67

1,026 – 219 48 1,293 900 456 41 1,397

Presented in GBP (settlement currency)

Year ended 31 December 2010 Year ended 31 December 2009

Salaryor fees

£’000Bonus£’000

Compen-sation

for loss of office

£’000

Otherbenefits

£’000Total£’000

Salaryor fees£’000

Bonus£’000

Otherbenefits

£’000Total

£’000

Executive Directors (salaries):C J Foss 212 – – 9 221 205 102 8 315G L Heard 197 – – 8 205 197 102 8 307D R Musgrove 272 – – 13 285 265 134 11 410N Wright 69 – 188 1 258 – – – –

Non-Executive Directors (fees):A N Brewer 36 – – 3 39 36 19 2 57R H R Latham 56 – – 5 61 56 29 4 89J M White 39 – – 2 41 38 20 2 60

881 – 188 41 1,110 797 406 35 1,238

The bonuses for 2009 were settled in 2010, and in accordance with the provisions of the bonus scheme 50% of the bonus was settled in ordinary shares of the Company.

The remuneration of Non-Executive Directors includes fees currently set at £2,280 (€2,649) per annum for acting as members of each of the Company’s Audit, Remuneration and Nomination and Health and Safety Committees.

Additional payments of two times basic salary or fees are due to Directors in the event that a single shareholder (or group of shareholders acting in concert) obtains control of more than 29.9% of the Company’s ordinary shares and exercises control over the Company or its Board, or seeks to remove the Director concerned from office. With effect from 1 January 2011 these payments amount to £514,440 (€597,665) for D R Musgrove, £394,640 (€458,484) for C J Foss, £394,640 (€458,484) for G L Heard, £111,600 (€129,654 for R H R Latham, £76,680 (€89,085) for J M White and £72,120 (€83,787) for A N Brewer.

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We have audited the consolidated financial statements of Northern Petroleum Plc for the year ended 31 December 2010 set out on pages 44 to 80. The financial reporting framework that has been applied in the preparation of the Group financial statements is applicable law and International Financial Reporting Standards (IFRSs) as adopted by the EU. The financial reporting framework that has been applied in the preparation of the Parent Company financial statements is applicable law and UK Accounting Standards (UK Generally Accepted Accounting Practice).

This report is made solely to the Company’s members, as a body, in accordance with Chapter 3 of Part 16 of the Companies Act 2006. Our audit work has been undertaken so that we might state to the Company’s members those matters we are required to state to them in an auditor’s report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the Company and the Company’s members, as a body, for our audit work, for this report, or for the opinions we have formed.

Respective Responsibilities of Directors and AuditorAs explained more fully in the Directors’ Responsibilities Statement set out on page 38, the Directors are responsible for the preparation of the financial statements and for being satisfied that they give a true and fair view. Our responsibility is to audit, and express an opinion on, the financial statements in accordance with applicable law and International Standards on Auditing (UK and Ireland). Those standards require us to comply with the Auditing Practices Board’s (APB’s) Ethical Standards for Auditors.

Scope of the Audit of the Financial StatementsA description of the scope of an audit of financial statements is provided on the APB’s website at www.frc.org.uk/apb/scope/private.cfm.

Opinion on Financial StatementsIn our opinion:

• the financial statements give a true and fair view of the state of the Group’s and of the Parent Company’s affairs as at 31 December 2010 and of the Group’s loss for the year then ended;

• the Group financial statements have been properly prepared in accordance with IFRSs as adopted by the EU;• the Parent Company financial statements have been properly prepared in accordance with UK Generally Accepted

Accounting Practice; and• the financial statements have been prepared in accordance with the requirements of the Companies Act 2006.

Opinion on Other Matters Prescribed by the Companies Act 2006In our opinion the information given in the Directors’ Report for the financial year for which the financial statements are prepared is consistent with the financial statements.

Matters on Which We Are Required to Report by ExceptionWe have nothing to report in respect of the following matters where the Companies Act 2006 requires us to report to you if, in our opinion:

• adequate accounting records have not been kept by the Parent Company, or returns adequate for our audit have not been received from branches not visited by us; or

• the Parent Company financial statements are not in agreement with the accounting records and returns; or• certain disclosures of Directors’ remuneration specified by law are not made; or• we have not received all the information and explanations we require for our audit.

J Lowes (Senior Statutory Auditor)for and on behalf of KPMG Audit Plc, Statutory AuditorChartered Accountants15 Canada SquareLondonE14 5GL 7 June 2011

Report on Directors’ Remunerationcontinued

Independent Auditors’ Report to the members of Northern Petroleum Plc

On the exercise of the Company’s warrants during the year the Directors made aggregate notional gains of £582,000 (€645,000) (2009: £55,000, €62,000); the highest single gain made by an individual Director was £333,000 (€370,000) (2009: £55,000, €62,000). The closing mid-market price of the shares on 31 December 2010 was 109p (2009: 128.5p) and the range of closing mid-market prices during the year was 84p to 152.5p (2009: 63p to 163p).

This report was approved by the Board on 7 June 2011 and signed on its behalf by:

A N BrewerChairman of the Remuneration and Nomination Committee


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Notes


2010€’000


2009€’000

Revenue 2 14,968 5,084

Production costs (4,884) (2,077) Depletion and amortisation – property, plant & equipment (3,387) (1,525)

Cost of sales 2 (8,271) (3,602)

Gross profit 6,697 1,482

Pre-licence costs (593) (847)

Administrative expenses – other (4,246) (2,565) Administrative expenses – share incentives 3 & 18 (359) (1,927)

Administrative expenses – total (4,605) (4,492)

Profit / (loss) from operations 3 1,499 (3,857)

Finance costs 6 (1,524) (552) Finance income 7 17 1,365 Share of operating loss of joint ventures & associates (8) (80)Loss before tax (16) (3,124)

Tax (expense) / credit 8 (1,139) 973

Loss for the year (1,155) (2,151)

Basic earnings per share on loss for the year 9 (1.3) cents (2.9) cents

Diluted earnings per share on loss for the year 9 (1.3) cents (2.9) cents

All results are from continuing activities and are attributable to equity shareholders of the parent.

The notes on pages 49 to 80 form part of these financial statements.


2010€’000


2009€’000

Loss for the year (1,155) (2,151)

Exchange differences on translation of foreign operations 164 (41)

Other comprehensive income / (loss) for the year, net of income tax 164 (41)

Total comprehensive loss for the year (991) (2,192)

All amounts are attributable to equity shareholders of the parent.


Consolidated Income Statementfor the year ended 31 December 2010

Consolidated Statement of Comprehensive Incomefor the year ended 31 December 2010


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Consolidated Statement of Financial Positionat 31 December 2010

Consolidated Statement of Cash Flowsfor the year ended 31 December 2010

Notes2010

€’0002009

€’000

AssetsNon-current assetsIntangible assets 10 31,810 27,880 Property, plant and equipment 11 58,123 45,895 Investments in joint ventures 12 579 259Investments in associates 12 15 15 Loans and other receivables 14 129 118

90,656 74,167Current assetsInventories 13 124 98 Trade and other receivables 14 8,668 14,376 Cash and cash equivalents 21,430 15,002

30,222 29,476

Total assets 120,878 103,643

LiabilitiesCurrent liabilitiesTrade and other payables 15 6,326 8,103Corporation tax liability 15 – 2,895

6,326 10,998Non-current liabilitiesTrade and other payables 30 169Provisions 16 16,286 9,564 Deferred tax liabilities 17 12,865 9,148

29,181 18,881

Total liabilities 35,507 29,879

Net assets 85,371 73,764

Capital and reservesShare capital 18 5,768 4,983Share premium 11,501 194Merger reserve 10,289 10,289Special reserve (Distributable) 28,428 28,410Special reserve (Un-distributable) 155 173Share incentive plan reserve 3,964 3,865Foreign currency translation reserve (345) (509)Retained earnings 25,611 26,359 Total equity 85,371 73,764

All amounts are attributable to equity shareholders of the parent. The notes on pages 49 to 80 form part of these financial statements.

These financial statements were approved and authorised for issue by the Board of Directors on 7 June 2011 and were signed on its behalf by:

D R Musgrove C J FossDirector Director

REGISTERED NO. 02933545


2010€’000


2009€’000

Cash flows from operating activitiesLoss before tax (16) (3,124) Depletion and amortisation 3,387 1,525Depreciation – non-oil and gas property, plant and equipment 205 181Foreign exchange loss / (gain) 348 (567) Finance income (17) (798) Finance charges 1,176 552 Share-based payments 799 1,210 Expenses settled by issue of shares 65 63 Share of operating loss in associate 8 80 Net cash inflow / (outflow) before movements in working capital 5,955 (878)

Increase in inventories (26) (43) Decrease in trade and other receivables 8,247 9,831(Decrease) / increase in trade and other payables (2,539) 2,127Net cash inflow from changes in working capital 5,682 11,915

Taxes paid (2,857) (964)

Net cash inflow from operating activities 8,780 10,073

Cash flows from investing activitiesInterest received 17 178 Interest paid (6) (69) Purchase of property, plant and equipment (9,526) (16,939) Expenditure on exploration and evaluation assets (2,835) (12,768) Purchase of other intangible assets (999) –Investment in joint venture company (328) (183) Acquisition costs of ATI net of cash and cash equivalents acquired – (727)Net cash outflow from investing activities (13,677) (30,508)

Cash flows from financing activitiesIssue of ordinary shares net of fees associated with placing 11,464 –Proceeds from the exercise of equity warrants 270 60 Net cash inflow from financing activities 11,734 60

Net increase / (decrease) in cash and cash equivalents 6,837 (20,375) Cash and cash equivalents at start of year 15,002 34,927 Effect of exchange rate movements (409) 450 Cash and cash equivalents at end of year 21,430 15,002

Other than the ATI acquisition in 2009 there have been no significant non-cash transactions during either year. The notes on pages 49 to 80 form part of these financial statements.


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Consolidated Statement of Changes in Equityfor the year ended 31 December 2010

Notes to the Accountsfor the year ended 31 December 2010

Sharecapital€’000

Sharepremiumaccount

€’000

Mergerreserve

€’000

Special reserves

€’000

Shareincentive

planreserve

€’000

Foreigncurrency

translationreserve

€’000

Retainedearnings

€’000Total

€’000

At 1 January 2009 4,488 23,964 – 4,698 2,384 (468) 28,479 63,545Total comprehensive loss for the year – – – – – (41) (2,151) (2,192)Cancellation of share premium account – (23,885) – 23,885 – – – –Issue of shares during the year 8 115 – – – – – 123ATI acquisition 487 – 10,289 – 302 – – 11,078Equity share warrants exercised – – – – (31) – 31 –Share-based payments – – – – 1,210 – – 1,210At 31 December 2009 4,983 194 10,289 28,583 3,865 (509) 26,359 73,764 Total comprehensive loss for the year – – – – – 164 (1,155) (991)Issue of shares during the year – placing 715 11,437 – – – – – 12,152Costs and fees associated with share placing – (688) – – – – – (688)Issue of shares during the year – warrants and staff bonus 70 558 – – (293) – – 335Equity share warrants exercised – – – – (407) – 407 –Share-based payments – – – – 799 – – 799At 31 December 2010 5,768 11,501 10,289 28,583 3,964 (345) 25,611 85,371

All amounts are attributable to equity shareholders of the parent.

The following describes the nature and background to each reserve within owners’ equity:

Share premium Amount subscribed for share capital in excess of nominal value.

Other reserves: – Merger reserve

The notional “share premium” on the shares issued in consideration for the takeover of ATI Oil Plc, evaluated at the closing market price on the day of acquisition, 24 June 2009, less the nominal value of those shares issued.

– Special reserve (distributable) – Special reserve (un-distributable)

The special reserves relate to the court sanctioned cancellation of the share premium account in July 2009 and the elimination of the previous deferred shares in issue and the cancellation of a proportion of the share premium account as at 31 December 2004 in accordance with the court order dated 31 October 2005.

– Share incentive plan reserve The share incentive plan reserve captures the equity related element of the expense recognised for the issue of warrants, comprising of the cumulative charge to the income statement for IFRS 2 charges for share-based payments less amounts released to re-tained earnings upon the exercise of warrants.

Foreign currency translation reserve Exchange differences arising on consolidating the assets and liabilities of the Group’s non- Euro functional currency operations (including comparatives) are classified as equity and transferred to the Group’s translation reserve.

Retained earnings Cumulative net gains and losses recognised in the financial statements.

1. Accounting PoliciesThe principal accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have been consistently applied to all the years presented, unless otherwise stated.

Basis of preparationThe consolidated financial statements have been prepared under the historical cost convention and have been approved by the Directors in accordance with EU adopted International Financial Reporting Standards (IFRS) and International Financial Reporting Interpretations Committee (IFRIC) interpretations issued by the International Accounting Standards Board (IASB), and with those parts of the Companies Act 2006 applicable to companies reporting under IFRS. The Company has elected to prepare its Parent Company financial statements in accordance with UK GAAP; these are presented on pages 83 to 90. The Group has adopted all of the standards and interpretations issued by the International Accounting Standards Board and the International Financial Reporting Interpretations Committee that are relevant to its operations.

Going concern basis of preparationAs set out in more detail in the Directors’ Report on page 35, the Directors consider the use of the going concern basis of accounting is appropriate for the Company because no material uncertainties related to events or conditions that may cast significant doubt about the ability of the Company to continue as a going concern have been identified by the Directors.

The Company has processes in place in order to ensure a reasonable cash balance is maintained at all times. The Company continually monitors its cash balances and these are reported to the Board at least weekly. The Board also reviews the forecast cash balance at the end of each of the next twelve months on a rolling basis. Before making a decision to add significant new commitments the Board considers the risks to the delivery of these cash forecasts. The risks are described in note 22 to the financial statements. The Board approved bonus scheme for Directors and management also requires the maintenance of a minimum cash balance at all times.

After making appropriate enquiries, the Directors have a reasonable expectation that the Group has adequate resources to meet all its commitments and to continue in operational existence for the foreseeable future. Accordingly they continue to adopt the going concern basis in preparing the Annual Report and Accounts.

Changes in accounting policiesAdoption of new and revised standards

A In the current year, the following new and revised standards and interpretations are effective and have been adopted but have had no effect on the amounts reported in these financial statements.

(i) Standards affecting the reported results and financial position

RevisedIFRS3–BusinessCombinations The revised standard applies prospectively to business combinations

made after 1 January 2010. Business combinations which took place before 1 January 2010 do not need to be restated as a result of the adoption of this standard. The most significant changes to the Group’s previous accounting policies for business combinations are as follows:

• all transaction costs which previously could be capitalised are now expensed as they are incurred;

• any pre-existing equity interest in the entity acquired is re-measured to fair value at the date of obtaining control, with any resulting gain or loss recognised in the income statement; and

• any changes to the cost of an acquisition, including contingent consideration, resulting from events after the date of acquisition are recognised in the income statement.

IAS38–IntangibleAssets The IASB issued amendments to IAS 38 in April 2009, which clarifies

the description of valuation techniques commonly used to measure the fair value of intangible assets acquired in a business combination for which no active market exists.

IAS27–ConsolidatedandSeparateFinancialStatements The amendments to IAS 27 (2008), arising due to the amendments

to IFRS 3, reflect changes to the accounting for non-controlling (minority) interest and deal primarily with the accounting for changes in ownership interests in subsidiaries after control is obtained, the accounting for the loss of control of subsidiaries, and the allocation of profit or loss to controlling and non-controlling interests in a subsidiary.

IFRS2–Share-basedpayments In June 2009 IFRS 2 was amended to clarify the scope and

accounting for group cash-settled share-based payment transactions in the separate financial statements of the entity receiving the goods or services, when that entity has no obligation to settle the share-based transaction.

IAS36–Impairmentofassets In April 2009 IAS 36 was amended to state that the largest unit to

which goodwill is allocated is operating segment level as defined in IFRS 8 before applying the aggregation criteria of IFRS 8.12.

(ii) Standards affecting presentation and disclosure

IAS1–PresentationofFinancialStatements In April 2009 IAS 1 “Presentation of Financial Statements” was

amended to state that the classification of the liability component of a convertible instrument as current or non-current is not affected by terms that, at the option of the holder, result in settlement of the liability through issue of equity instruments.

IAS7–StatementofCashFlows In April 2009 the IASB issued amendments to IAS 7 “Statement of

Cash Flows” which requires that only expenditure that results initially in the recognition of an asset may be classified as a cash flow from investing activities.

B At the date of approval of these financial statements, the following Standards and Interpretations which have not been applied in these financial statements were in issue but not yet effective and in some cases not yet adopted by the EU:

IFRS3–BusinessCombinations In May 2010 further amendments were made to IFRS 3 as follows: • to limit the accounting policy choice to measure Non-Controlling

Interests (NCI) upon initial recognition either at fair value or at the NCI’s proportionate share of the acquiree’s identifiable net assets to instruments that give rise to a present ownership interest and entitle the holder to a share of net assets in the event of liquidation; and

• to extend the scope of the guidance on how to apportion the market-based measure of an acquirer’s share-based payment awards that are issued in exchange for acquiree awards between consideration transferred and post-combination cost when an acquirer is obliged to replace the acquiree’s existing awards. IFRS 3 is amended so that the guidance for such awards also applies to voluntarily replaced acquiree awards, and introduces attribution guidance for acquiree awards that are not replaced.


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1. Accounting Policies continued IFRS7–FinancialInstruments:Disclosures This standard was amended to: • include a statement detailing that the interaction between

qualitative and quantitative disclosures, better enables users to evaluate an entity’s exposure to risks arising from financial statements; and

• require additional disclosures about the transfer of financial assets to enable users to understand the possible effects of any risks that may remain with the transferor.

IAS1–PresentationofFinancialStatements In May 2010 an amendment was made to IAS 1 “Presentation

of Financial Statements” which stated that for each component of equity a reconciliation from opening to closing balances is required to be presented in the statement of changes in equity. That reconciliation is required to show separately changes arising from items recognised in profit or loss, in other comprehensive income, and from transactions with owners acting in their capacity as owners.

IAS24–RelatedPartyDisclosures The changes introduced by IAS 24 made an amendment to the

definition of a related party.

IFRS9–FinancialInstruments This standard will replace IAS 39 – Financial Instruments: Recognition

and Measurement.

The Directors do not expect that the adoption of these Standards or Interpretations in future periods will have a material impact on the financial statements of the Group.

Basis of consolidationThe consolidated financial statements include the financial statements of the Company, its subsidiaries and interests in joint ventures and associates made up to 31 December 2010.

SubsidiariesSubsidiaries are entities over whose financial and operating policies the Group has the power to exercise control, through which it seeks to get benefits. The Group financial statements incorporate the assets, liabilities and results of operations of the Company and its subsidiaries. The results of subsidiaries acquired and disposed of during a financial year are included from the effective dates of acquisition to the effective dates of disposal.

Where necessary, the accounting policies of the subsidiaries are changed to ensure consistency with the policies adopted by the Group when presenting consolidated financial statements.

AssociatesAn associate undertaking (“associate”) is an enterprise over whose financial and operating policies the Group has the power to exercise significant influence and which is neither a subsidiary nor a joint venture of the Group. The equity method of accounting for associates is adopted in the Group financial statements, such that they include the Group’s share of operating profit or loss, exceptional items, interest, taxation and net assets of associates (“the equity method”). In applying the equity method, account is taken of the Group’s share of accumulated retained earnings and movements in reserves from the effective date on which an enterprise becomes an associate and up to the effective date of disposal.

The share of associated retained earnings and reserves is generally determined from the associate’s latest interim or final financial statements. Where the Group’s share of losses of an associate exceeds the carrying amount of the associate, the associate is carried at nil. Additional losses are only recognised to the extent that the Group has incurred obligations or made payments outside the course of ordinary business on behalf of the associate.

Joint venturesJointly controlled entities are those entities over whose activities the Group has joint control, established by contractual agreement and requiring the venturers’ consent for strategic financial and operating decisions. The equity method of accounting is adopted for joint ventures, such that the consolidated financial statements include the Group’s proportionate share of the entities’ net assets and net profit, after adjustments to align the accounting policies with those of the Group, from the date that joint control commences until the date that joint control ceases.

Jointly controlled assetsJointly controlled assets are arrangements in which the Group holds an interest on a long term basis and which are jointly controlled by the Group and one or more co-venturers under a contractual arrangement. The Group’s exploration, development and production activities are generally conducted jointly with other companies in this way. Since these arrangements do not constitute entities in their own right, the consolidated financial statements reflect the relevant proportion of costs, revenues, assets and liabilities applicable to the Group’s interests.

Intangible Assets Oil and gas assets: exploration and evaluationThe Group has continued to apply the “modified” full cost method of accounting for Exploration and Evaluation (“E&E”) expenses, having regard to the requirements of IFRS 6 “Exploration for and Evaluation of Mineral Resources”. Under the “modified” full cost method of accounting, costs of exploring and evaluating oil and gas properties are accumulated and capitalised by reference to appropriate cash-generating units. For E&E asset purposes the Group considers each country to be a cash-generating unit, so that The Netherlands, Italy, United Kingdom and Guyane are cash generating units.

E&E expenses are initially capitalised within “Intangible assets”. Such E&E expenses may include costs of licence acquisition, technical services and studies, seismic acquisition, exploration drilling and testing, but do not include costs incurred prior to having obtained the legal rights to explore an area, which are expensed directly to the income statement as they are incurred.

Intangible E&E assets related to each exploration licence or prospect are not depreciated and are carried forward until the existence (or otherwise) of commercial reserves has been determined. The Group definition of commercial reserves for such purpose is proven and probable reserves on an entitlement basis.

If commercial reserves have been discovered, the related E&E assets are assessed for impairment as set out below. The carrying value, after any impairment loss, of the relevant E&E assets is then reclassified as development and production (“D&P”) assets within property, plant and equipment.

E&E assets are assessed for impairment when facts and circumstances suggest that the carrying value of the E&E cash-generating unit to which they relate may exceed its future recoverable amount. Such indicators include the point at which a determination is made as to whether or not commercial reserves exist.

Where the E&E assets concerned fall within the scope of an established D&P cash-generating unit, the E&E assets are tested for impairment together with the established D&P assets as a single cash-generating unit. The aggregate carrying value is compared against the expected recoverable amount of the cash-generating unit, generally by reference to the present value of the future net cash flows expected to be derived from production of commercial reserves. These ceiling test values are calculated on the basis of expected future product prices or, if applicable at prices specified in a sales contract, and discounted at rates typically between 10% and 15% (2009: 7.50% and 12.50%) per annum, depending on risk considerations on an asset by asset basis. Intangible E&E assets that relate to such E&E activities remain capitalised as intangible E&E assets at cost.

Where the E&E assets to be tested fall outside the scope of any established D&P cash-generating unit and there are deemed to be no commercial reserves, or no ongoing work programme, the E&E assets concerned will generally be written off in full.

Any material impairment loss is recognised in the income statement and separately disclosed.

Property, plant and equipmentOil and gas assets: development and productionDevelopment and production assets are accumulated on a cash-generating unit basis and represent the cost of developing the commercial reserves discovered and bringing them into production, together with the E&E expenditures incurred in finding commercial reserves transferred from intangible E&E assets as outlined above.

The net book values of producing assets are depreciated on a cash-generating unit basis using the unit of production method based on entitlement to produce by reference to the ratio of production in the period to the related commercial reserves of the cash-generating unit, taking into account any estimated future development expenditures necessary to bring additional reserves into production.

An impairment test is performed for D&P assets whenever events and circumstances arise that indicate that the carrying value of development or production phase assets may exceed its recoverable amount. The aggregate carrying value is compared against the expected recoverable amount of the cash-generating unit, generally by reference to the present value of the future net cash flows expected to be derived from production of commercial reserves.

These ceiling test values are calculated on the basis of expected future product prices or, if applicable at prices specified in a sale contract, and discounted at rates between 4.5% and 12.5% (2009: 5.5% and 12.5%) per annum, depending on risk considerations on an asset by asset basis. The cash-generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped as a single cash-generating unit where the cash flows of each field are in some way interdependent.

DecommissioningWhere a material liability for the removal of production facilities and site restoration at the end of the productive life of a field exists, a provision for decommissioning is recognised. The amount recognised is the present value of estimated future expenditure determined in accordance with local conditions and requirements. A property, plant and equipment asset of an amount equivalent to the provision is also created and depreciated on a unit of production basis.

Changes in estimates are recognised prospectively, with corresponding adjustments to the provision and the associated fixed assets.

Non-oil and gas assetsProperty, plant and equipment are included in the balance sheet at cost, less accumulated depreciation and any provisions for impairment.

Software implementationThe Group has capitalised expenditure on the implementation of a new computer software package in accordance with IAS 38 “Intangible Assets”. The standard states that the product must be technically and commercially feasible, future economic benefits probable, the Group must have the technical ability and sufficient resources to complete implementation and the Group can measure reliably the expenditure attributable to the software during its implementation. The expenditure capitalised includes certain consultancy costs and staff time costs. Capitalised implementation expenditure is stated at cost less accumulated amortisation and less accumulated impairment losses. The software will be amortised from the date it is available for use and will be written off over four years.

Business combinationsThe Group has chosen to adopt IFRS 3 prospectively from the date of transition to IFRS and not restate historic business combinations from before this date. Business combinations from the date of transition until 31 December 2009 are accounted for under IFRS 3 using the purchase method. From 1 January 2010 the Group has adopted IFRS 3 revised (see page 49).

RevenueRevenue comprises net invoiced sales of hydrocarbons to customers, excluding value added and similar taxes. Income recognised, excluding value added and similar taxes, to other companies by the Group comprises charges in respect of fees for acting as operator of both production and pre-production activities, and fees for other related services, are also disclosed within production and pre-production segment revenue.

Income recognised, excluding value added and similar taxes, to other companies by the Group in respect of fees for any other services are disclosed within other operating income. Revenue is recognised on an entitlement basis once the significant risks and rewards of ownership have passed to the customer and receipt of future economic benefits is probable. Revenue from services provided is recognised once the services have been performed.

Segment reportingIn the opinion of the Directors the Group has one class of business, being the exploration for, and development and production of, oil and gas reserves, and other related activities.

The Group’s primary reporting format is determined to be the geographical segment according to the location of the oil and gas asset. Currently the activities of the Group are disclosed within the following geographical segments: The Netherlands, Italy, United Kingdom and Other EU.

Share-based paymentsIn accordance with IFRS 2 “Share-based payments”, the Group reflects the economic cost of awarding shares and share options to employees, Directors and key suppliers and consultants by recording an expense in the income statement equal to the fair value of the benefit awarded. The expense is recognised in the income statement over the vesting period of the award.


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1. Accounting Policies continuedFair value is measured by use of a Black Scholes model which takes into account conditions attached to the vesting and exercise of the equity instruments. The expected life used in the model is adjusted, based on management’s best estimate, for the effects of non-transferability, exercise restrictions and behavioural considerations.

If a warrant is cancelled before the end of its vesting period, the remaining fair value expense not yet charged to the income statement is immediately recognised in full. Upon cancellation of the warrant there will also be a transfer of the cumulative charge recognised in respect of the transferred warrants out of the share incentive reserve and into retained earnings.

An accrual for employers’ National Insurance is made in respect of share warrants granted to employees that are in profit at the year end.

PensionsA defined contribution plan is a post-employment benefit plan under which an entity pays fixed contributions into a separate entity and will have no legal or constructive obligation to pay further amounts. Obligations for contributions to defined contribution pension plans are recognised as an employee benefit expense in the income statement when they are due. Prepaid contributions are recognised as an asset to the extent that a cash refund or a reduction in future payments is available.

DepreciationThe cost of property, plant and equipment, other than costs directly related to oil and gas assets, is written off by equal annual instalments over the expected useful lives of the assets, as follows:

• Leasehold improvements – over the term of the lease• Computer hardware and software – four years• Office equipment – four years• Motor vehicles – four years

The carrying values of property, plant and equipment are reviewed for impairment if events or changes in circumstances indicate the carrying value may not be recoverable.

InventoriesInventories comprise oil and gas in tanks and field parts and supplies, all of which are stated at the lower of cost and net realisable value.

Condensate, which is currently treated as a by-product of producing gas, is stated at net realisable value.

Net realisable value is the estimated selling price in the ordinary course of business less marketing costs.

Lease CommitmentsThe annual rentals under operating leases are charged to the income statement on a straight-line basis over the term of the lease.

Financial instrumentsFinancial assetsThe Group classifies its financial assets into one of the categories discussed below, depending on the purpose for which the asset was required. The Group has not classified any of its financial assets as held to maturity.

The Group’s accounting policy for each category is as follows:

Loans and receivables: These assets are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They arise principally through the provision of goods and services to customers (i.e. trade receivables) but also incorporate other types of contractual monetary asset. They are initially recognised at fair value plus transaction costs that are directly attributable to their acquisition or issue, and are subsequently carried at amortised cost using the effective interest rate method, less provision for impairment.

Impairment provisions are recognised when there is objective evidence (such as significant financial difficulties on the part of the counterparty or default or significant delay in payment) that the Group will be unable to collect all of the amounts due under the terms receivable, the amount of such a provision being the difference between the net carrying amount and the present value of the future expected cash flows associated with the impaired receivable. For trade receivables, which are reported net, such provisions are recorded in a separate allowance account with the loss being recognised within administrative expenses in the income statement. On confirmation that the trade receivable will not be collectable, the gross carrying value of the asset is written off against the associated provision.

From time to time the Group may elect to renegotiate the terms of trade receivables due from customers with which it has previously had a good trading history. Such renegotiations may lead to changes in the timing of payments rather than changes to the amounts owed and, in consequence, the new expected cash flows are discounted at the original effective interest rate.

The Group’s receivables comprise trade and other receivables.

Cash and cash equivalents: Cash and cash equivalents include cash in hand and deposits held at call with banks.

Financial liabilitiesThe Group currently classifies its financial liabilities into current and non-current liabilities. The Group has not classified any of its liabilities at fair value through the income statement.

Share capitalFinancial instruments issued by the Group are treated as equity only to the extent that they do not meet the definition of a financial liability. The Group’s ordinary shares and unclassified ordinary shares are classed as equity instruments.

Foreign currenciesForeign currency transactions of individual companies within the Group are translated in the individual companies’ functional currency at the rates ruling when the transactions occurred. Monetary assets and liabilities denominated in other currencies are retranslated at the rate of exchange ruling at the balance sheet date. All differences are taken to the income statement.

On consolidation, assets and liabilities of subsidiaries, associate undertakings and joint ventures which are denominated in other currencies are translated into Euro at the rate ruling at the balance sheet date. Income and cash flow statements are translated at average rates of exchange prevailing during the year. Exchange differences resulting from the translation at closing rates of net investments in subsidiaries, associate undertakings and joint ventures, together with differences between earnings for the year translated at average and closing rates, are dealt with in the foreign currency translation reserve. Details of the current and prior year exchange rates used in these accounts are disclosed in note 22.

The functional currency of the Parent Company is considered to be the Euro and the Group financial statements have been presented in Euro.

TaxationThe tax expense represents the sum of the tax currently payable and deferred tax.

Current tax, including UK Corporation and any overseas tax, is provided at amounts expected to be paid (or recovered) using the tax rates and laws that have been enacted, or substantially enacted, by the balance sheet date.

Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit, and is accounted for using the balance sheet liability method. Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised. Such assets and liabilities are not recognised if the temporary difference arises from goodwill or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither the tax profit nor the accounting profit.

Deferred tax assets and liabilities are recognised for taxable temporary differences arising on investments in subsidiaries and associates, and interests in joint ventures, except where the Group is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future.

The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.

Deferred tax is calculated on an undiscounted basis at the tax rates that are expected to apply in the period when the liability is anticipated to be settled or the asset is anticipated to be realised, based on tax rates and laws enacted or substantively enacted at the balance sheet date. Deferred tax is charged or credited in the income statement, except when it relates to items charged or credited directly to equity, in which case the deferred tax is also dealt with in equity.

Cash and cash equivalentsCash, for the purposes of the cash flow statement, comprises cash in hand and deposits repayable on demand, based on the relevant exchange rates at the balance sheet date.

Cash equivalents comprise funds held in term deposit accounts and investments in money market instruments, based on the relevant exchange rates at the balance sheet date.

Critical accounting judgments and key sources of estimation uncertaintyThe preparation of the consolidated financial statements requires management to make estimates and assumptions concerning the future that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. The resulting accounting estimates will, by definition, differ from the related actual results.

Details of the Group’s significant accounting judgments and critical accounting estimates are set out in these financial statements and include:

Carrying value of property, plant and equipment (Note 11);Carrying value of intangible exploration and evaluation assets (Note 10);Valuation of petroleum and natural gas properties: consideration of impairment includes estimates relating to oil and gas reserves, future production rates, overall costs and oil and natural gas prices which impact future cash flows. In addition, the timing of regulatory approval, the general economic environment and the ability to finance future activities through the issuance of debt or equity also impact the impairment analysis. All these factors may impact the viability of future commercial production from developed and unproved properties, including major development projects, and therefore the need to recognise impairment.

Commercial reserves estimates;Oil and gas reserve estimates: estimation of recoverable reserves include assumptions regarding commodity prices, exchange rates, discount rates, production and transportation costs all of which impact future cash flows. It also requires the interpretation of complex geological and geophysical models in order to make an assessment of the size, shape, depth and quality of reservoirs and their anticipated recoveries. The economic, geological and technical factors used to estimate reserves may change from period to period. Changes in estimated reserves can impact developed and undeveloped property carrying values, asset retirement costs and the recognition of income tax assets, due to changes in expected future cash flows. Reserve estimates are also integral to the amount of depletion and depreciation charged to income.

Subsidiaries may report changes in their reserves from time to time. The aggregate of these is shown on page 81. Only where such changes in a subsidiary’s reserves are material to the Group or have a material impact on the Group financial results does the Group publish revised reserve data. This prevents numerous immaterial changes to Group reserves being announced.

Decommissioning costs (Note 16);Asset retirement obligations: the amounts recorded for asset retirement obligations are based on each field’s operator’s best estimate of future costs and the remaining time to abandonment of the oil and gas properties, which may also depend on commodity prices and any future changes to national regulations.

Share-based payments (Notes 3 and 18);The fair value of share-based payments recognised in the income statement is measured by use of a Black Scholes model which takes into account conditions attached to the vesting and exercise of the equity instruments. The expected life used in the model is adjusted, based on management’s best estimate, for the effects of non-transferability, exercise restrictions and behavioural considerations. The share price volatility percentage factor used in the calculation is based on management’s best estimate of future share price behaviour and is selected based on past experience, future expectations and benchmarked against peer companies in the industry.


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2. Segmental InformationThere are currently four geographic reporting segments. The Netherlands and United Kingdom are involved in production, development and exploration activity, with the United Kingdom also the home of the head office; Italy is involved in development and exploration operations; the “Other EU” segment comprises exploration operations in Guyane, plus some pre-licence expenditure in respect of exploration possibilities in new countries.

The segment disclosures are based on the components of the business that the Chief Operating Decision Maker (CODM) and Board monitors in making decisions about operating matters. Such components are identified on the basis of internal reports that the Board reviews regularly.

Exploration, development and production 2010

United Kingdom

€’000Italy

€’000Netherlands

€’000Other EU

€’000Total

€’000

Revenue from external customers

Gas & gas condensate – – 14,098 – 14,098

Oil 387 – – – 387

Project operator fees 83 215 185 – 483

470 215 14,283 – 14,968

Cost of sales

Production costs 117 – 4,767 – 4,884

Depletion and amortisation 72 – 3,315 – 3,387

189 – 8,082 – 8,271

Gross profit 281 215 6,201 – 6,697

Pre-licence costs (33) (288) (97) (175) (593)

Administrative expenses (2,723) (720) (1,154) (8) (4,605)

(Loss) / profit from operations (2,475) (793) 4,950 (183) 1,499

Finance charges (341) (1) (1,182) – (1,524)

Finance income 6 – 11 – 17

Share of operating loss in associates – – – (8) (8)

(Loss) / profit before tax (2,810) (794) 3,779 (191) (16)

Income tax (charge) / credit (26) 61 (1,174) – (1,139)

Net (loss) / profit for the financial year (2,836) (733) 2,605 (191) (1,155)

The Group has one major customer; of the €14,283,000 sales of gas and gas condensate in The Netherlands, (2009: €4,110,000), €13,709,000 comprises sales to GasTerra B.V. (“GasTerra”), (2009: €4,011,000).

GasTerra is an international company trading in natural gas. It operates on the European energy market and has a significant share of the Dutch gas market. The company has a strong purchasing position and has over 40 years’ experience in purchasing and selling natural gas. GasTerra is a private company with limited liability incorporated in The Netherlands. The shareholders’ structure comprises the Dutch State 10%, Energie Beheer Nederland 40%, and Shell Nederland B.V. and Esso Nederland B.V. each 25%. (Source: GasTerra website).

Revenues from external customers are attributed to individual countries by both country of production and country of customer.

Assets and liabilities at 31 December 2010United

Kingdom€’000

Italy€’000

Netherlands€’000

Other EU€’000

Total€’000

Segment assets 9,813 28,521 60,245 869 99,448Cash and cash equivalents 16,295 736 4,399 – 21,430Total assets 26,108 29,257 64,644 869 120,878

Segment liabilities (2,939) (362) (19,341) – (22,642)Current tax liabilities – – – – –Deferred tax liabilities – (3,333) (9,532) – (12,865)Total liabilities (2,939) (3,695) (28,873) – (35,507)

Other segment itemsCapital expenditure 2,947 847 9,565 1 13,360Depreciation, depletion and amortisation (260) – (2,755) – (3,015)Impairment loss – – (577) – (577)

Exchange differences on translation of foreign operations 164 – – – 164Share-based payments 799 – – – 799Other non-cash expenses 65 – – – 65

Included in segment assets aboveInvestment in joint venture and associates 15 – – 579 594Long term receivables – – – 129 129

Exploration, development and production 2009 comparative

United Kingdom

€’000Italy


€’000Other EU

€’000Total

€’000

Revenue from external customersGas & gas condensate – – 4,110 – 4,110Oil 331 – – – 331Project operator fees 69 220 334 – 623Other services 20 – – – 20

420 220 4,444 – 5,084

Cost of salesProduction costs 91 – 1,986 – 2,077Depletion and amortisation 62 – 1,173 – 1,235Impairment loss 290 – – – 290

443 – 3,159 – 3,602

Gross (loss) / profit (23) 220 1,285 – 1,482

Pre-licence costs (35) (732) 3 (83) (847) Administrative expenses (1,629) (1,413) (1,368) (82) (4,492)Loss from operations (1,687) (1,925) (80) (165) (3,857)Finance charges (61) – (491) – (552) Finance income 1,134 208 23 – 1,365Share of operating loss in associates – (72) – (8) (80) Loss before tax (614) (1,789) (548) (173) (3,124)Income tax credit 184 – 789 – 973Net (loss) / profit for the financial year (430) (1,789) 241 (173) (2,151)



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2. Segmental Information continued

Assets and liabilities at 31 December 2009United

Kingdom€’000

Italy€’000

Netherlands€’000

Other EU€’000

Total€’000

Segment assets 9,221 28,596 50,245 579 88,641

Cash and cash equivalents 12,805 591 1,606 – 15,002

Total assets 22,026 29,187 51,851 579 103,643

Segment liabilities (2,695) (592) (14,541) (8) (17,836)

Current tax liabilities (355) – (2,540) – (2,895)

Deferred tax liability – (3,333) (5,815) – (9,148)

Total liabilities (3,050) (3,925) (22,896) (8) (29,879)

Other segment items

Capital expenditure 886 4,951 26,373 – 32,210

Acquisition through business combination – 18,218 – – 18,218

Depreciation, depletion and amortisation (229) – (1,187) – (1,416)

Impairment loss (290) – – – (290)

Exchange differences on translation of foreign operations (37) – – (4) (41)

Share-based payments 1,210 – – – 1,210

Other non-cash expenses 63 – – – 63

Included in segment assets above

Investment in joint venture and associates 15 – – 259 274

Long term receivables – – – 118 118

3. Profit / (Loss) from OperationsThis is stated after charging:


2010€’000


2009€’000

Depreciation of non-oil and gas property, plant and equipment (note 11b) 205 181

Operating lease rentals – land and buildings 734 362

Operating lease rentals – other 81 14

Share-based payments – National Insurance (440) 717

Share-based payments – IFRS 2 799 1,210

Administrative expenses – share incentives 359 1,927

Auditors’ Remuneration


2010€’000


2009€’000

Audit fees payable to the Company’s auditor for the audit of the Company’s financial statements 55 57

Fees payable to the Company’s auditor and its associates for other services:

– the audit of the Company’s subsidiaries 71 42

– taxation services 6 –

– other services pursuant to such legislation 37 69

The Company has borne the Auditors’ remuneration of its non-trading UK subsidiary undertakings.

4. Directors’ RemunerationYear ended

31 December2010

€’000


2009€’000

Executive salaries including bonus 874 1,133

Non-Executive fees including bonus 152 223

Compensation for loss of office 219 –

Benefits in kind 48 41

Emoluments 1,293 1,397

Details for each Director of remuneration and interests in warrants exercisable into the Company’s shares are set out in the tables below. The total remuneration of the highest paid Director was €332,000 (2009: €462,000).



Bonus€’000

Compen-sation

for loss of office

€’000

Otherbenefits

€’000Total

€’000


Bonus€’000

Otherbenefits

€’000Total

€’000

Executive Directors (salaries):

C J Foss 247 – – 11 258 231 115 9 355

G L Heard 230 – – 9 239 223 115 9 347

D R Musgrove 317 – – 15 332 299 150 13 462

N Wright 80 – 219 2 301 – – – –

Non-Executive Directors (fees):

A N Brewer 42 – – 3 45 41 21 3 65

R H R Latham 65 – – 6 71 63 33 5 101

J M White 45 – – 2 47 43 22 2 67

1,026 – 219 48 1,293 900 456 41 1,397

Part of the bonus scheme in 2009 was settled in shares and accounted for under IFRS 2. Consequently €170,000 of the remuneration received by the Directors was excluded from the income statement in 2009 in line with applicable accounting standards.

On the exercise of warrants during the year the Directors made aggregate notional gains of £582,000 (€646,000) (2009: £55,000, €62,000); the highest single gain made by an individual director was £333,000 (€370,000) (2009: £55,000, €62,000).

5. Staff Costs and Numbers (including Directors)Year ended

31 December2010

€’000


2009€’000

Salaries 4,899 4,344

Social security costs 620 438

Defined contribution pension costs 27 26

Other benefits in kind 143 112

5,689 4,920

Charge for share-based payments (note 3) 799 1,210

National insurance accrual (release) / charge on share-based payments (440) 717

6,048 6,847

Based on timewriting, a certain element of salaries is capitalised, predominantly at the subsidiary level. The net salary cost to Northern capitalised in the year was €1,838,000 (2009: €2,287,000).



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5. Staff Costs and Numbers (including Directors) continuedThe Group operates a defined contribution pension scheme for its Dutch employees. The pension cost charge for the period represents contributions payable by the Group to the scheme and amounted to €27,000 (2009: €26,000). There were no outstanding or prepaid contributions at either the beginning or end of the financial year. Excluding the Directors, there were 36 (2009: 31) full time members of staff at the end of the year. In addition, during the year Northern Petroleum Nederland B.V. employed 6 contractors (2009: 6).

The average number of persons employed by the Group during the year, including Executive Directors, was made up as follows:

2010 2009

Technical 10 9

Professional 6 5

Operations 9 7

Administration 12 12

37 33

6. Finance ChargesYear ended

31 December2010

€’000


2009€’000

Foreign exchange losses 348 –

Other interest payable 673 219

Bank interest payable 6 –

Unwinding of discount on decommissioning provisions 497 333

1,524 552

7. Finance Income and other Finance GainsYear ended

31 December2010

€’000


2009€’000

Interest receivable 17 178

Unwinding of discount on receivables due in more than one year – 620

Foreign exchange gains – 567

17 1,365

8. Tax Expense / (Credit)

a) Analysis of tax expense / (credit)


2010€’000


2009€’000

Current tax:

UK tax – current year – (144)

Tax on overseas operations on profits for the year – current year – –

Current tax – adjustment in respect of prior years (2,578) 17

(2,578) (127)

Deferred tax:

UK tax – –

Overseas tax – origination and reversal of temporary differences 1,876 (354)

1,876 (354)

Adjustment to prior year deferred tax 1,841 (492)

Total tax expense / (credit) (note 8b) 1,139 (973)

The Group is making taxable profits in The Netherlands where it pays two taxes: Corporate Income Tax (“CIT”) at 25.5% and State Profit Share (“SPS”) at 24.5% on oil and gas activities. The Group has made taxable losses in its other countries of operation, but has not recognised deferred tax credits for these losses as they are not expected to be used in 2011 – for analysis of the tax charge by country of operation please see note 2, “Segmental Information”.

NetherlandsThe Dutch Regulation for Depreciation At Will 2001 (“DAW”) was updated in early 2009 to be applicable for both Dutch CIT and for SPS on expenditure on business assets committed to in 2009 and 2010. Under the changes, E&P companies are able, for tax purposes, to depreciate in full the carrying value of qualifying investments over two years, 2009 and 2010, at up to 50% in each year, rather than on a unit of production basis. Investment in new fixed assets qualifies if the investment was made in 2009 or 2010 and as long as the assets subject to a DAW claim are in use before 1 January 2012.

In the 2009 Annual Report, the Group noted the updates to DAW, but at that time had not yet decided to take advantage of the rule changes. The Group now has elected to utilise DAW for capital expenditure by its Dutch subsidiary, Northern Petroleum Nederland B.V. (“NPN”), in both 2009 and 2010. Use of DAW has resulted in tax losses for those years, which are available to be carried back in respect of prior years’ profits.

The 2010 tax charge relates to deferred tax liabilities arising on timing differences between NPN’s accounting and fiscal balance sheets, (which include additional allowances taken under DAW); unutilised tax losses; and a current tax adjustment in respect of prior years. By taking carry back of 2009 and 2010 tax losses into account, NPN has recognised a tax receivable of €2,540,000 for overpaid CIT and SPS in earlier years.

NPN had a routine tax audit in 2010. The tax positions for 2005 to 2008 have been agreed with the tax authorities and a deferred tax adjustment is recognised in respect of prior year timing differences of €1,727,000.

In 2010 the prior year losses capitalised as a deferred tax asset (€4,076,000) were fully utilised. The tax loss for the fiscal year 2010 has been offset against the remaining prior year profits. At year end 2010 the Group has capitalised the remaining tax loss not yet utilised amounting to €1,483,000.

b) Factors affecting tax expense / (credit)The tax expense for the year is higher than the standard rate of corporation tax in the UK 28% (2009: 28%). The difference is explained below:


2010€’000


2009€’000

Group loss before taxation (16) (3,124)

Tax on Group loss before taxation at an effective rate of 28% (2009: 28%) (4) (875)

Effects of:

Income not subject to tax in current year – (174)

Expenses not deductible for corporate income tax purposes 28 664

Capital allowances for period in excess of depreciation (1,414) (4,588)

Utilisation of brought forward tax losses – (28)

Current tax losses not utilised and carried forward 1,747 2,501

Uncrystallised capital allowances not utilised and carried forward 65 2,642

Effects of higher supplementary charges to corporation tax 760 (275)

Effects of different corporate tax rates on UK and overseas earnings (119) (29)

Prior year income subject to tax in the current year – 18

Adjustment in respect of prior years – current tax (38) 17

Adjustment in respect of prior years – deferred tax 114 (492)

Effects of overseas deferred tax – origination and reversal of temporary differences – (354)

Total current tax expense / (credit) for year 1,139 (973)



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8. Tax Expense / (Credit) continued

c) Factors that may affect future tax expenseThe Group has corporate income tax and supplementary hydrocarbon tax losses of €29.71 million (2009: €16.93 million), and uncrystallised capital allowances of approximately €1.17 million (2009: €13.28 million) that are available for offset against future taxable profits. Losses that are available for offset against future taxable profits have been recognised as deferred tax assets to the extent that they will be used to offset taxable profits in the following year.

Corporate tax amendments:

The NetherlandsIt is pleasing to be able to advise shareholders of a further amendment by the Ministry of Finance of The Netherlands (“The Ministry”) to the Regulation for Depreciation At Will 2001 (“DAW”), which extends DAW to expenditure on qualifying assets in 2011.

UKOn 23 March 2011 the Chancellor announced an additional 1% reduction in the main rate of UK Corporation Tax (CT) to 26% with effect from 1 April 2011. Additionally, it was announced that the rate of Supplementary Charge to Corporation Tax (SCT) would increase from 20% up to a maximum of 32%, effective from 24 March 2011, giving a total tax rate for ring fence profits of up to 62%. The Chancellor proposed further changes to reduce the main corporation tax rate by one per cent per annum to 23% by 1 April 2014. These changes have had no effect on the reported results for the year.

Other countries of operationSince the issue of the last Annual Report, there have been no significant changes enacted to tax legislation in the Group’s other countries of operation that are currently anticipated to have a material effect on the Group’s tax position.

9. Loss Per ShareBasic earnings or losses per share amounts are calculated by dividing the profit or loss for the period attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the year.

Diluted earnings per share amounts are calculated by dividing profit for the period attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the year, plus the weighted average number of shares that would be issued on the conversion of dilutive potential ordinary shares into ordinary shares. The calculation of the dilutive potential ordinary shares related to employee and director share option plans includes only those warrants with exercise prices below the average share trading price for each period.

2010€’000

2009€’000

Net loss attributable to equity holders used in basic calculation 1,155 2,151

Net loss attributable to equity holders used in dilutive calculation 1,155 2,151

Number’000

Number’000

Basic weighted average number of shares 86,094 75,184

Dilutive potential of ordinary shares:

Warrants exercisable under Company schemes – –

Diluted weighted average number of shares 86,094 75,184

The calculation of the diluted EPS assumes all criteria giving rise to the dilution of the EPS are achieved.

10. Intangible Assets

a) Exploration and Evaluation AssetsIntangible assets consist of the Group’s exploration projects which are pending determination of technical feasibility and commercial viability of extracting a mineral resource.

United Kingdom

€’000Italy


€’000Other EU

€’000Total

€’000

Cost:

At 1 January 2010 4,479 9,629 13,753 188 28,049

Additions 718 589 1,527 1 2,835

Transfers – – (44) – (44)

Exchange movement 138 – – 2 140

At 31 December 2010 5,335 10,218 15,236 191 30,980

Explorationexpenditurewrittenoff:

At 1 January 2010 42 – 99 28 169

Exchange movement – – – – –

At 31 December 2010 42 – 99 28 169

Netbookvalue:

At 31 December 2010 5,293 10,218 15,137 163 30,811

The comparative tables for 2009 are detailed below:

United Kingdom

€’000Italy


€’000Other EU

€’000Total

€’000

Cost:

At 1 January 2009 3,940 2,617 5,805 173 12,535

Additions 279 4,751 7,948 – 12,978

Acquisition through business combination – 2,374 – – 2,374

Transfers (24) – – 24 –

Exchange movement 284 (113) – (9) 162

At 31 December 2009 4,479 9,629 13,753 188 28,049

Explorationexpenditurewrittenoff:

At 1 January 2009 39 – 99 28 166

Exchange movement 3 – – – 3

At 31 December 2009 42 – 99 28 169

Netbookvalue:

At 31 December 2009 4,437 9,629 13,654 160 27,880

The Group’s share of the exploration and evaluation assets of joint venture and associate companies at 31 December 2010 is analysed as follows:

Total€’000

United Kingdom 12

Other EU 600

612

At the year end the contractual commitments for capital expenditure in respect of intangible assets was €143,000 (2009: €162,000), of which the Group’s share was €86,000 (2009: €73,000).

In addition, the Group’s share of the committed drilling costs in respect of the Guyane licence, on which there was a well commitment at year end is currently estimated to be $1,750,000. The well commenced drilling in March 2011.



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10. Intangible Assets continuedThe Directors have considered the carrying value of intangible assets in relation to the value of prospective resources by cost pool and believe that there is significant headroom between the two. Consequently no impairment adjustment to the carrying value of intangible assets has been made. In addition, under the terms of its agreement with NAM, the Group is able to recover the cost of drilling four exploration wells in the Netherlands, (three drilled, the results of two of which are still under review, with one still to drill), against production revenues from any or all of the four wells that are successfully put into production.

b) IT systemsComputer

software€’000

Cost:

At 1 January 2010 –

Additions 999

At 31 December 2010 999

Depreciation:


Charge for the year –

At 31 December 2010 –

Netbookvalue:


The additions of €999,000 above comprise software and implementation costs for a new IT system. The IT system is due to go live in 2011 and no depreciation has been charged in 2010 (2009: Nil).

11. Property, Plant and Equipment

a) Oil and Gas Assets

Netherlands –Developed

€’000

Netherlands – Undeveloped

€’000

UK –Developed

€’000

UK –Undeveloped

€’000

Italy –Undeveloped

€’000Total

€’000

Cost:

At 1 January 2010 22,043 12,810 745 778 16,352 52,728

Additions 8,476 5,519 16 1,066 258 15,335

Disposal (119) – – (25) – (144)

Transfers 10,952 (10,908) – – – 44

Adjustments 231 – – – – 231

Exchange movement – – 20 20 – 40

At 31 December 2010 41,583 7,421 781 1,839 16,610 68,234

Depletionandamortisation:

At 1 January 2010 6,735 – 466 – – 7,201

Charge for the year 2,738 – 72 – – 2,810

Impairment loss 577 – – – – 577

Disposal (119) – (25) – – (144)

Exchange movement – – 13 – – 13

At 31 December 2010 9,931 – 526 – – 10,457

Netbookvalue:

At 31 December 2010 31,652 7,421 255 1,839 16,610 57,777

At the year end the contractual commitments for capital expenditure in respect of property, plant and equipment was €3,555,000 (2009: €6,742,000), of which the Group’s share was €1,671,000 (2009: €3,034,000).

Adjustments in the year relate to changes in estimates for oil and gas field abandonment costs.

The impairment charge in the year relates to the Grolloo field and is included within the charge for Depletion and Amortisation – Property, Plant and Equipment, in the consolidated income statement.

At Grolloo, which started commercial production in late 2009, the initial plan had been to install compression and or other surface equipment to aid and increase production once the pressure had stabilised and there was an observable influx of supplementary gas flow from the lower permeability reservoir matrix, allowing for the basis of design for the equipment. Until now no such stabilisation has been observed. Northern considers that it is not feasible to add compression in time to make a material impact to 2011 gas production.

For the purposes of these financial statements the Group has therefore taken the decision to adopt the view that pressure support from the lower permeability reservoir matrix will not occur.

Based on revised forecast production from the Grolloo well, the Group has assessed the economic value for the Grolloo field using a discount rate of 4.5% and a gas price per normal cubic metre of €0.245 between 2011 and 2015 and €0.225 from 2016. On this basis the carrying value of the Grolloo field has been written down by €577,000. The recoverable amount of the asset is its value in use.

The tax impact of this impairment loss to the overall tax charge for the year is €288,000 to deferred tax and €Nil to current tax.

The depreciation and amortisation charge for the year has been calculated based on the revised reserves estimates for the Geesbrug, Grolloo and Wijk en Aalburg fields, and is higher as a consequence of the reported changes.

The carrying value of proven developed oil and gas assets in The Netherlands includes the Group’s interests in the producing Waalwijk and P12 gas fields, both of which were acquired during 2007 by the Company’s wholly owned Dutch subsidiary, Northern Petroleum Nederland B.V. Also included within the carrying value of proven developed oil and gas assets in The Netherlands are the Grolloo and Geesbrug gas fields that entered production in December 2009, the Brakel gas field that entered production in September 2010 and the Wijk en Aalburg gas field that entered production in December 2010.

The Group placed the Brakel and Wijk en Aalburg gas fields in The Netherlands into production during 2010. Therefore, an amount of €10,908,000 has been transferred from “Undeveloped” to “Developed” under Property, Plant and Equipment. Further assets are included within the “Undeveloped” category which are continuing to be progressed and are expected to come into production in 2012 and beyond.

The carrying value of the Brakel field was independently reviewed by RPS Energy Limited in early 2010. The carrying values of the Geesbrug, Grolloo and Wijk en Aalburg fields were updated on the basis of revised management reserve estimates issued on 27 May 2011. The carrying value of the Waalwijk field is based on the most recent management estimates and the carrying value of the P12 field is based on the most recent estimate by the field’s operator. Further information is given in the unaudited Report on Net Commercial Oil & Gas Reserve Quantities.

The carrying value of proven undeveloped oil and gas assets in The Netherlands includes the expenditures to date in respect of certain assets in which the Group has interests in The Netherlands that were independently reviewed by RPS Energy Limited in early 2010. Further information is given in the unaudited Report on Net Commercial Oil & Gas Reserve Quantities.

The carrying value of proven developed oil and gas assets in the UK includes:

• a 10% interest in the producing Horndean field owned by the Company’s wholly owned subsidiaries, Northern Petroleum (GB) Limited, Northern Petroleum (UK) Limited and NP Oil & Gas Holdings Limited; and

• a 5% interest in the producing Avington field owned by the Company’s wholly owned subsidiary, Northern Petroleum (GB) Limited.

The carrying value of proven undeveloped oil and gas assets in the UK also includes the expenditures to date in respect of certain assets under licence to the Group in the Weald Basin that have been independently reconfirmed by RPS Energy Limited during 2010 to be undeveloped oil fields with proven and / or probable reserves. Further information is given in the unaudited Report on Net Commercial Oil & Gas Reserve Quantities.

The carrying value of the undeveloped oil and gas assets in Italy includes the expenditures to date in respect of certain assets in which the Group has interests in Italy that have been independently reviewed by Blackwatch Petroleum Services Limited in October and December 2007. Further information is given in the unaudited Report on Net Commercial Oil & Gas Reserve Quantities.



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11. Property, Plant and Equipment continuedThe comparative tables for 2009 are detailed below:

Netherlands –Developed

€’000

Netherlands – Undeveloped

€’000

UK –Developed

€’000

UK –Undeveloped

€’000

Italy –Undeveloped

€’000Total

€’000

Cost:

At 1 January 2009 7,458 8,970 234 688 335 17,685

Additions 2,571 15,854 2 541 200 19,168

Acquisition through business combination – – – – 15,844 15,844

Transfers 12,014 (12,014) 501 (501) – –

Exchange movement – – 8 50 (27) 31

At 31 December 2009 22,043 12,810 745 778 16,352 52,728

Depletionandamortisation:

At 1 January 2009 5,562 – 110 – – 5,672

Charge for the year 1,173 – 62 – – 1,235

Impairment loss – – 290 – – 290

Exchange movement – – 4 – – 4

At 31 December 2009 6,735 – 466 – – 7,201

Netbookvalue:

At 31 December 2009 15,308 12,810 279 778 16,352 45,527

b) Non-Oil and Gas Assets

Leasehold improvements

€’000

Computerand office

equipment€’000

Motor vehicles

€’000Total

€’000

Cost:

At 1 January 2010 303 601 – 904

Additions – 147 36 183

At 31 December 2010 303 748 36 1,087

Depreciation:

At 1 January 2010 178 358 – 536

Charge for the year 76 126 3 205

At 31 December 2010 254 484 3 741

Netbookvalue:

At 31 December 2010 49 264 33 346

The comparative table for 2009 is detailed below:


€’000

Computer and office

equipment€’000

Motor

vehicles€’000

Total€’000

Cost:

At 1 January 2009 303 537 – 840

Additions – 64 – 64

At 31 December 2009 303 601 – 904

Depreciation:

At 1 January 2009 102 253 – 355

Charge for the year 76 105 – 181

At 31 December 2009 178 358 – 536

Netbookvalue:

At 31 December 2009 125 243 – 368

12. InvestmentsUnlisted

Investments€’000

TotalInvestments

€’000

Cost:

At 1 January 2010 274 274

Additions 328 328

Share of losses of associates (8) (8)

At 31 December 2010 594 594

Provision:

At 1 January and 31 December 2010 – –

Carrying value at 31 December 2010 594 594

Carrying value at 31 December 2009 274 274

Included in the above are the Group’s interests at the year end in the following joint venture and associated undertakings:

Country of incorporation /

registration Principal activityPrincipal country

of operation

Description and proportion of

shares held

Northpet Investments Limited England & Wales Oil and gas exploration Guyane Ordinary shares

of £1–50%

Oil & Gas Investments Limited England & Wales Oil and gas exploration UK Ordinary shares

of £1–41.32%

The aggregate amounts relating to the Group’s interest in the joint venture, Northpet Investments Limited, are: Current Assets €263,000 (2009: €520,000), Non-Current Assets €1,200,000 (2009: €611,000), Current Liabilities €158,000 (2009: €98,000) and Non-Current Liabilities €148,000 (2009: €140,000).



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12. Investments continuedSummary of financial statements of associates and joint ventures:

Reportingdate

Assets€’000

Liabilities€’000

Equity€’000

Revenue€’000

12 months (loss)

after tax€’000

2010

Northpet Investments Limited 31 December 2010 1,463 306 1,157 – (17)

Oil & Gas Investments Limited 31 May 2010 48 27 21 – –

2009

Northpet Investments Limited 31 December 2009 671 211 460 – (15)

Oil & Gas Investments Limited 31 May 2009 74 53 21 – (1)

The Group’s investment in Oil & Gas Investments Limited (“O&GI”), an associate undertaking, has been accounted for using the equity method, which has been applied to that group’s management accounts as at 31 December 2010. At 31 December 2010 the Company owned 41.32% of O&GI. Derek Musgrove and Graham Heard are also directors and shareholders of O&GI and a number of other Northern Petroleum staff are also shareholders in O&GI. O&GI currently holds interests between 1.25% and 5% in three of the UK onshore licences and one UK offshore application operated by the Group.

Northpet Investments Limited, a joint venture with Wessex Exploration Plc, has been accounted for using the equity method, which has been applied to that company’s management accounts as at 31 December 2010. At 31 December 2010 a member of the Northern Group owned 50% of Northpet Investments Limited.

The Group’s material subsidiary undertakings which are included within these consolidated accounts are:



of operation


shares held

NorthernPetroleum(GB)Limited England&WalesOilandgasexploration

andproduction UKOrdinaryshares

of£1–100%

NorthernPetroleumNederlandB.V. TheNetherlandsOilandgasexploration,

developmentandproduction NetherlandsOrdinaryshares

of€10–100%

NorthernPetroleum(UK)Limited England&WalesOilandgasexploration

andproduction ItalyOrdinaryshares

of£0.001–100%

NPNetherlandsLimited England&Wales Holdingcompany UKOrdinaryshares

of£1–100%

NPOffshoreHoldings(UK)Limited England&WalesHoldingcompanyandoilandgasexploration UK

Ordinarysharesof£1–100%

NPOil&GasHoldingsLimited England&Wales

Holdingcompanyandoilandgasexploration


of£1–100%

NPSolentLimited England&Wales Oilandgasexploration UKOrdinaryshares

of£1–100%

NPWealdLimited England&Wales Oilandgasexploration UKOrdinaryshares

of£1–100%

NorthernPetroleumE&PHoldingsLimited(formerlyATIOilLimited) England&Wales Oilandgasexploration UK

Ordinarysharesof£0.0025–100%

The comparative table for 2009 is detailed below:

ListedInvestments

€’000

Unlisted Investments

€’000

TotalInvestments

€’000

Cost:

At 1 January 2009 (2) 85 83

Additions – 183 183

Share of losses of associates (72) (8) (80)

Acquisitions through business combination 76 – 76

Foreign exchange translation differences (2) 14 12

At 31 December 2009 – 274 274

13. Inventories 2010

€’000 2009€’000

Crude oil 1 1

Condensate 55 31

Spare parts 68 66

124 98

There is no material difference between the replacement cost of inventories and the amount stated above.

The amount of inventory which has been recognised as an expense during the year is €Nil (2009: €Nil).

14. Trade and Other Receivables 2010

€’000 2009€’000

Non-current assets

Loans 129 118

129 118

Current assets

Trade receivables 1,833 1,590

Other receivables 95 4,208

Corporation tax 2,540 144

VAT recoverable 347 3,530

Prepayments and accrued income 3,853 4,904

Total trade and other receivables 8,797 14,494

A loan of $200,000 (€148,000 net of fair value discount of €19,000, (2009: €139,000 net of fair value discount of €21,000)) has been made to Northpet Investments Limited to be used to fund drilling expenditure incurred on the Guyane licence.

Non-current loans and receivables are initially recognised at fair value and subsequently held at amortised cost. The fair values of these are based on cash flows discounted using a market rate of interest for comparable transactions. The discount rate applied is 5% (2009: 5%).

Current trade and other receivables, and loans have a fair value that approximates to their book value at both balance sheet dates. No amounts have been provided against trade and other receivables (2009: €Nil) and no amounts have been written off during the year (2009: €Nil).

The carrying values of the Group’s trade and other receivables are denominated in the following currencies:

2010€’000

2009€’000

Euro 8,108 13,649

UK Sterling 516 668

US Dollars 173 177

Total trade and other receivables 8,797 14,494

Of the €8,797,000 owing at 31 December 2010, €1,220,000 was overdue (2009: €903,000). The Group considers that this amount will be recovered in full and has not impaired it.

The ageing analysis of the overdue amount is as follows:

2010€’000

2009€’000

0–3 months 42 –

4–6 months 14 903

6–12 months 261 –

1 year or more 903 –

Total overdue trade and other receivables 1,220 903



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15. Trade and Other Payables 2010

€’000 2009€’000

Non-current Liabilities

Accruals and deferred income 30 169

30 169

Current Liabilities

Trade payables 1,938 3,788

Corporation tax liability – 2,895

Taxation and social security 190 350

Other payables 205 284

Accruals and deferred income 3,993 3,681

Total trade and other payables 6,356 11,167

Trade and other payables are measured at amortised cost and their book value approximates to fair value at 31 December 2010 and 2009.

The carrying values of the Group’s trade and other payables are denominated in the following currencies:

2010€’000

2009€’000

Euro 3,885 8,407

UK Sterling 2,459 1,838

Canadian Dollars 12 739

Other – 14

Total trade and other payables 6,356 10,998

All trade and other payables are considered due within three months.

16. Provisions 2010

€’000 2009€’000

At 1 January 9,564 6,697

Additions 5,992 2,531

Adjustments 231 –

Unwinding of fair value discount 497 333

Exchange movement 2 3

At 31 December 16,286 9,564

The amount provided at 1 January 2010 represents the Group’s share of decommissioning liabilities in respect of the producing P12, Waalwijk, Geesbrug and Grolloo gas fields in The Netherlands and the producing Horndean and Avington fields in the UK and the Savio well in Italy. Additions in the year are in respect of the Brakel and Wijk en Aalburg producing gas fields in The Netherlands. The amounts provided for Geesbrug, Grolloo, Brakel, Wijk en Aalburg, P12 and Waalwijk have been discounted at 4.5% to reflect the present value of the estimated future decommissioning expenditures of these fields as they are larger, more costly facilities to abandon than the UK and Italian locations referred to above.

Adjustments in the year relate to changes in estimates for oil and gas field abandonment costs.

NPN operates the Brakel, Grolloo, Geesbrug and WIjk en Aalburg gas fields. It estimates that these provisions will become payable in approximately seven years for Grolloo, twenty years for Geesbrug, eight years for Wijk en Aalburg and twenty five years for Brakel. At Waalwijk, which NPN also operates, the most recent estimate is that this provision will become payable either in part or in full in a minimum of two years’ time, dependent upon the possible use of part of the site for one or more underground gas storage projects. The most recent estimate received from the Operator of P12 is that this provision will become payable in five years’ time. The most recent estimate received from the Operator of Horndean is that this provision will become payable in between ten and fifteen years’ time. The decommissioning liability for the Avington field is estimated to fall due in four to five years’ time and the Savio well site is expected to be abandoned during 2011.

17. Deferred Taxation 2010

€’000 2009€’000

Balance at start of year (9,148) (6,661)

Deferred tax liability recognised in income statement (15,797) (3,344)

Deferred tax asset recognised in income statement 12,080 4,190

Deferred tax arising on acquisition – (3,333)

Balance at end of year (12,865) (9,148)

Comprising:

Tax losses 12,080 4,190

Other temporary differences (24,945) (13,338)

Deferred tax liability (12,865) (9,148)

Of the €24,945,000 other temporary differences, €21,612,000 arises on accelerated allowances received for oil and gas asset expenditure still held at cost within fixed assets, plus some other minor timing differences and €3,333,000 arises on the fair value adjustment for the assets acquired as part of the ATI acquisition. These deferred tax adjustments arising on exploration expenditure and the fair value of ATI’s assets are not expected to be settled in cash and will unwind over time as new discoveries are made and, together with existing discoveries, are brought into production.

Deferred tax assets have not been recognised in respect of those losses and allowances that are not considered usable to offset taxable profits in the following year as they may not be used to offset taxable profits elsewhere in the Group, and they may have arisen in subsidiaries that may be loss making for some time. The gross unrecognised temporary differences comprise:

2010€’000

2009€’000

Timing differences on fixed assets – (6,553)

Other timing differences 4,298 3,697

Tax losses 5,548 8,551

Gross unrecognised temporary differences 9,846 5,695

18. Share Capital 2010

€’000 2009€’000

Authorised:

311,316,404 (2009: 311,316,404) ordinary shares of 5p each 19,648 19,648

Allotted, issued, called up and fully paid:

91,987,445 (2009: 78,987,248) ordinary shares of 5p each 5,768 4,983

The ordinary shares above all hold the same voting rights and there are no restrictions on the distribution of dividends.

The Group’s capital management policy is explained in note 22.



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18. Share Capital continuedWarrants:Disclosures concerning contingent rights to the allotment of shares in respect of outstanding warrants held by the Board are given in the Report on Directors’ Remuneration. Details of warrants issued, extended and exercised during the year, together with warrants outstanding at 31 December 2010 are as follows:

Issue date

Final

exercisedate

Exercisepricepence

At1January

2010’000s

Newissues’000s

Exercised’000s

Lapsedorcancelled

’000s

At31December

2010’000s

13 November 2001 31 July 2011 15.625p 490.0 – (120.0) – 370.0

1 October 2002 31 July 2011 11.25p 1,420.0 – (380.0) – 1,040.0

22 May 2003 31 July 2011 12.5p 400.0 – – – 400.0

16 August 2004 31 July 2011 31.25p 250.0 – – – 250.0

24 October 2005 30 June 2011* 35.5p 250.0 – – – 250.0

5 December 2005 30 June 2011* 43.5p 150.0 – – – 150.0

13 February 2006 30 June 2011* 66.0p 150.0 – – – 150.0

13 July 2006 30 June 2011* 137.5p 125.0 – – – 125.0

27 July 2006 31 July 2011 130.0p 975.0 – – – 975.0

28 July 2006 31 July 2011 130.5p 150.0 – – – 150.0

14 August 2006 30 June 2010 131.5p 37.5 – – (37.5) –

14 August 2006 30 June 2011 131.5p 37.5 – – – 37.5

3 November 2006 31 October 2011 117.0p 150.0 – – – 150.0

17 July 2007 31 January 2011 197.0p 10.0 – – – 10.0

1 August 2007 31 January 2011 173.5p 10.0 – – – 10.0

23 October 2007 30 April 2011 176.0p 20.0 – – – 20.0

19 December 2007 31 December 2012 138.5p 100.0 – – – 100.0

12 December 2008 1 February 2010 67.0p 17.5 – (17.5) – –

12 December 2008 31 October 2010 67.0p 125.0 – (112.5) (12.5) –

12 December 2008 1 February 2011 67.0p 17.5 – – – 17.5

12 December 2008 30 June 2011 67.0p 75.0 – – – 75.0

12 December 2008 31 December 2011 67.0p 122.5 – (37.5) – 85.0

12 December 2008 30 June 2012 67.0p 202.5 – (37.5) – 165.0

12 December 2008 31 July 2012 67.0p 75.0 – – – 75.0

12 December 2008 31 December 2012 67.0p 197.5 – – (37.5) 160.0

12 December 2008 30 June 2013 67.0p 192.5 – – – 192.5

12 December 2008 31 July 2013 67.0p 75.0 – – – 75.0

12 December 2008 30 June 2014 67.0p 55.0 – – – 55.0

31 December 2008 30 June 2012 68.5p 199.0 – – – 199.0

31 December 2008 30 June 2013 68.5p 258.0 – (50.0) – 208.0

31 December 2008 31 December 2013 68.5p 962.5 – – – 962.5

31 December 2008 30 June 2014 68.5p 258.0 – – (25.0) 233.0

12 January 2009 30 June 2013 77.5p 100.0 – – – 100.0

20 February 2009 30 September 2012 73.5p 40.0 – – – 40.0



27 April 2009 31 December 2012 118.0p 25.0 – – – 25.0

24 June 2009 31 July 2011 200.0p 25.0 – – – 25.0

24 June 2009 30 April 2013 80.0p 150.0 – – – 150.0

24 June 2009 16 June 2013 252.0p 156.3 – – – 156.3

24 June 2009 1 July 2014 252.0p 31.3 – – – 31.3

24 June 2009 1 July 2015 252.0p 31.3 – – – 31.3

30 July 2009 31 October 2010 90.0p 50.0 – – (50.0) –

6 October 2009 31 December 2011 152.0p 10.0 – – – 10.0

6 October 2009 30 June 2012 152.0p 10.0 – – – 10.0

Issue date

Final

exercisedate

Exercise

pricepence

At1January

2010’000s

Newissues’000s

Exercised’000s

Lapsedorcancelled

’000s

At31December

2010’000s




11 January 2010 31 December 2013 148.0p – 70.0 – – 70.0

11 January 2010 31 December 2013 150.0p – 35.0 – – 35.0

12 April 2010 31 October 2013 127.5p – 175.0 – – 175.0

12 April 2010 31 December 2014 127.5p – 175.0 – – 175.0

8,276.4 455.0 (755.0) (162.5) 7,813.9

*Extension and re-issue of warrants exercisable into ordinary shares:

The IFRS 2 fair values of awards granted under the Group’s Warrant Schemes have been calculated using a variation of the binomial (Black Scholes) option pricing model that takes into account factors specific to share incentive plans such as the vesting periods, the expected dividend yield on the Company’s shares and expected exercise of share warrants. The volatility used in the calculations is based on past share price movements and is estimated at 60% (2009: 100%). Risk free investment rates between 0.32% and 5.75% (2009: 0.54% and 5.75%) have also been assumed in the calculations. The weighted average exercise price of all the warrants outstanding as at 31 December 2010 was 75.6p (2009: 68.67p). The weighted average remaining contractual life of all the warrants outstanding as at 31 December 2010 was 1 year and 6 months.

Other than as described below, there are no outstanding conditions attached to the exercise of the warrants issued during the year and remaining in issue at year end.

i) Of the warrants above granted on 12 December 2008: • 30,000 are not exercisable before 1 July 2011 and will be cancelled in the event that the employee to whom they have been granted resigns

on or before 1 July 2011.

ii) Of the warrants above granted on 31 December 2008: • 233,000 are not exercisable before 1 July 2011 and will be cancelled in the event that the employees to whom they have been granted resign


iii) Of the warrants above granted on 20 February 2009: • 30,000 are not exercisable before 1 October 2011 and will be cancelled in the event that the employee to whom they have been granted

resigns on or before 1 October 2011.

iv) Of the warrants above granted on 6 October 2009: • 10,000 are not exercisable before 1 July 2011 and will be cancelled in the event that the employee to whom they have been granted resign


v) Of the warrants above granted on 11 January 2010: • 35,000 are not exercisable before 1 July 2011 and will be cancelled in the event that the employee to whom they have been granted resign


vi) Of the warrants above granted on 12 April 2010: • 175,000 are not exercisable before 1 June 2012.



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18. Share Capital continuedThe comparative table for 2009 is detailed below:

Issue date

Final

exercisedate

Exercise

pricepence

At1January

2009’000s

Newissues’000s

Exercised’000s

Cancelled’000s

Lapsed’000s

At31December

2009’000s

13 November 2001 31 July 2011 15.625p 490 – – – – 490

1 October 2002 31 July 2011 11.25p 1,460 – (40) – – 1,420

8 August 2005 31 July 2011 12.50p 400 – – – – 400

8 August 2005 31 July 2011 31.25p 250 – – – – 250

24 October 2005 30 June 2011* 35.50p 250 – – – – 250

5 December 2005 30 June 2011* 43.50p 150 – – – – 150

13 February 2006 30 June 2011* 66.00p 150 – – – – 150

13 July 2006 30 June 2011 137.50p 125 – – – – 125

13 July 2006 30 June 2010 137.50p 100 – – – (100) –

27 July 2006 27 July 2011 130.00p 975 – – – – 975

28 July 2006 31 July 2011 130.50p 150 – – – – 150

14 August 2006 30 June 2010 131.50p 88 – – – (13) 75

3 November 2006 31 October 2011 117.00p 150 – – – – 150

17 January 2007 31 January 2010 96.50p 25 – – – (25) –

23 March 2007 1 August 2010 90.00p 50 – – – (50) –

17 July 2007 31 January 2011 197.00p 10 – – – – 10

1 August 2007 31 January 2011 173.50p 10 – – – – 10

23 October 2007 30 April 2011 176.00p 20 – – – – 20

19 December 2007 31 December 2012 138.50p 100 – – – – 100

15 December 2008 30 June 2012 67.00p 80 – – (40) – 40

15 December 2008 30 June 2013 67.00p 60 – – (30) – 30

15 December 2008 30 June 2014 67.00p 60 – – (30) – 30

18 December 2008 30 June 2014 67.00p 25 – – – – 25

18 December 2008 30 June 2014 67.00p 30 – – – – 30

18 December 2008 31 July 2013 67.00p 75 – – – – 75

18 December 2008 30 June 2013 67.00p 127 – – – – 127

18 December 2008 30 June 2013 67.00p 30 – – – – 30


18 December 2008 31 July 2012 67.00p 75 – – – – 75

18 December 2008 30 June 2012 67.00p 163 – – – – 163


18 December 2008 30 June 2011 67.00p 125 – – – – 125

18 December 2008 1 February 2011 67.00p 18 – – – – 18


18 December 2008 30 June 2010 67.00p 125 – – – – 125

18 December 2008 1 February 2010 67.00p 17 – – – – 17

30 December 2008 30 June 2014 68.50p 258 – – – – 258


30 December 2008 30 June 2013 68.50p 258 – – – – 258

30 December 2008 30 June 2012 68.50p 269 – (70) – – 199

12 January 2009 30 June 2013 77.50p – 100 – – – 100

20 February 2009 30 September 2012 73.50p – 40 – – – 40



27 April 2009 31 December 2012 118.00p – 25 – – – 25

24 June 2009 1 August 2009 136.00p – 15 – – (15) –

24 June 2009 30 April 2013 80.00p – 88 – – – 88

Issue date

Final

exercisedate

Exercise

pricepence

At1January

2009’000s

Newissues’000s

Exercised’000s

Cancelled’000s

Lapsed’000s

At31December

2009’000s

24 June 2009 30 April 2013 200.00p – 25 – – (25) –

24 June 2009 31 July 2011 200.00p – 25 – – – 25

24 June 2009 16 June 2013 252.00p – 156 – – – 156

24 June 2009 30 April 2013 80.00p – 63 – – – 63

24 June 2009 1 July 2014 252.00p – 31 – – – 31

24 June 2009 1 July 2015 252.00p – 31 – – – 31

30 July 2009 30 June 2010 90.0p – 50 – – – 50

6 October 2009 31 December 2011 152.00p – 10 – – – 10

6 October 2009 30 June 2012 152.00p – 10 – – – 10




7,955 759 (110) (100) (228) 8,276

* Extension and re-issue of warrants exercisable into ordinary shares:

Other than as described below, there are no conditions attached to the exercise of the warrants issued during the year.

i) 100,000 of the warrants above granted on 12 January 2009 that have a final exercise date of 30 June 2013 are not exercisable before 1 July 2010 and will be cancelled in the event that the employee to whom they have been granted resigns on or before 1 July 2010.

ii) Of the warrants above granted on 20 February 2009:

• 40,000 are not exercisable before 1 October 2009 and will be cancelled in the event that the employee to whom they have been granted resigns on or before 1 October 2009;

• 30,000 are not exercisable before 1 October 2010 and will be cancelled in the event that the employee to whom they have been granted resigns on or before 1 October 2010; and

• 30,000 are not exercisable before 1 October 2011 and will be cancelled in the event that the employee to whom they have been granted resigns on or before 1 October 2011.

iii) 25,000 of the warrants above granted on 27 April 2009 that have a final exercise date of 31 December 2012 are not exercisable before 1 October 2010 and will be cancelled in the event that the employee to whom they have been granted resigns on or before 1 October 2010.

iv) Of the warrants above granted on 24 June 2009, all of which were issued in accordance with the Scheme of Arrangement in respect of the acquisition of ATI Oil Plc, all were exercisable with effect from 24 June 2009 except:

• 31,250 are not exercisable before 1 July 2009; and • 31,250 are not exercisable before 1 July 2010.

v) Of the warrants above granted on 6 October 2009:

• 10,000 are not exercisable before 1 January 2010 and will be cancelled in the event that the employee to whom they have been granted resigns on or before 1 January 2010;

• 10,000 are not exercisable before 1 July 2010 and will be cancelled in the event that the employee to whom they have been granted resigns on or before 1 July 2010; and

• 10,000 are not exercisable before 1 July 2011 and will be cancelled in the event that the employee to whom they have been granted resigns on or before 1 July 2011.



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18. Share Capital continuedAnalysis of changes in share capital during the year:

2010€’000

2009€’000

At 1 January 4,983 4,488Shares issued for cash as a result of exercise of warrants 43 6 Shares issued for cash as a result of placing 715 –Shares issued to staff in lieu of salary payments 27 2Shares issued as a result of an acquisition through business combination – 487

At 31 December 5,768 4,983

The following issues of new ordinary shares were made during the year:Share

capital€’000

SharePremium

€’000Total

€’000

For cash as a result of exercise of warrants:11 January 2010 – 37,500 ordinary 5p shares at 67p 2 26 2826 January 2010 – 17,500 ordinary 5p shares at 67p 1 12 133 February 2010 – 37,500 ordinary 5p shares at 67p 2 27 2926 February 2010 – 280,000 ordinary 5p shares at 11.25p 15 20 3526 February 2010 – 120,000 ordinary 5p shares at 15.625p 7 14 2116 March 2010 – 100,000 ordinary 5p shares at 11.25p 6 6 1225 June 2010 – 50,000 ordinary 5p shares at 67p 3 38 412 July 2010 – 25,000 ordinary 5p shares at 68.5p 2 19 216 July 2010 – 50,000 ordinary 5p shares at 67p 3 37 4027 July 2010 –12,500 ordinary 5p shares at 67p 1 9 101 October 2010 – 25,000 ordinary 5p shares at 68.5p 2 18 20For cash as a result of exercise of placing:25 June 2010 – 11,764,706 ordinary 5p shares at 85p 715 10,749 11,464Issued to staff in lieu of salary payments:3 February 2010 – 418,247 ordinary 5p shares at 146.4375p 24 269 29326 October 2010 – 62,244 ordinary 5p shares at 88.875p 2 63 65

785 11,307 12,092

19. CommitmentsOperating leasesThe Group’s commitments for rental payments under non-cancellable operating leases payable during the year to 31 December 2010 are as follows:

2010 Other Operating leases

€’000

2010 Land and Buildings

€’000

2009Other Operating leases

€’000

2009 Land and Buildings

€’000

Leases expiring:Within one year 75 444 18 474Between one and five years 78 418 8 846After five years – – – –

153 862 26 1,320

All leases are “operating leases” and the relevant annual rentals are charged to the income statement on a straight line basis over the lease term.

The Group has three leased offices, one in the UK, one in the Netherlands and one in Italy. The Group also leases one apartment, in the Netherlands, plus an equipment storage site in the UK. General renewal clauses exist on all leases apart from the UK storage site which terminates in 2011.

The UK office lease was signed in 2007. The UK office lease rental is subject to review every five years to take account of any changes in the economic climate. There are two break clauses, one for the Company after five years and for the landlord after four years and each subsequent year. No restrictions are imposed by the lease agreement other than a break clause after five years.

The Netherlands office lease has a remaining life of four years. The land and building lease is reviewed annually and adjusted for the consumer price index. A general renewal clause exists, however no restrictions are imposed by the lease agreement other than the period of the lease.

20. Contingent LiabilitiesPayments to DirectorsAdditional payments of two times basic salary or fees are due to Directors in the event that a single shareholder (or group of shareholders acting in concert) obtains control of more than 29.9% of the Company’s ordinary shares and exercises control over the Company or its Board, or seeks to remove the Director concerned from office. With effect from 1 January 2011 these payments amount to £514,440 (€597,665) for D R Musgrove, £394,640 (€458,484) for C J Foss, £394,640 (€458,484) for G L Heard, £111,600 (€129,654), for R H R Latham, £76,680 (€89,085) for J M White and £72,120 (€83,787) for A N Brewer.

21. Related Party TransactionsDetails of transactions and year end balances with Directors and senior management of the Company, or with companies that were at some stage during 2010 non-wholly owned subsidiaries or joint ventures or associates, are as follows:

Northpet Investments

Limited€’000

Oil & Gas Investments

Limited (Group)

€’000

Receivables / (payables) balance at 31 December 2010 28 30

Receivables / (payables) balance at 31 December 2009 – 47

Amounts invoiced by Northern Petroleum Group in 2010:

– project billings under Joint Operating Agreements – 14

– other billings 97 –

Amounts invoiced by Northern Petroleum Group in 2009:

– project billings under Joint Operating Agreements – 5

There were no terms or conditions attached to the outstanding balances above and none of the balances are secured.

All related party transactions during the year were conducted on terms equivalent to those that prevail in arms lengths transactions. A summary of the Group’s related parties can be found in Investments, note 12.

No Director or member of senior management had, during or at the end of the year, a material interest in any other contract which was significant in relation to the Group’s business, except in respect of personal service agreements and warrants.

In addition there is a further loan to a joint venture, Northpet Investments Limited, which is disclosed in Trade and Other Receivables, note 14.

22. Financial InstrumentsThe overall policy with regard to the management of financial risks is set out in the Financial Review.

Financial instruments – Risk ManagementThe Group is exposed through its operations to the following risks:

• Credit risk• Cash flow interest rate risk• Foreign exchange risk• Liquidity risk• Price risk

In common with all other businesses, the Group is exposed to risks that arise from its use of financial instruments. This note describes the Group’s objectives, policies and processes for managing those risks and the methods used to measure them. Further quantitative information in respect of these risks is presented throughout these financial statements.

There have been no substantive changes in the Group’s exposure to financial instrument risks, its objectives, policies and processes for managing those risks or the methods used to measure them from previous periods unless otherwise stated in this note.



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22. Financial Instruments continuedPrincipal financial instrumentsThe principal financial instruments used by the Group, from which financial instrument risk arises are as follows:

• Loans and receivables• Trade and other receivables• Cash and cash equivalents• Short term investments• Trade and other payables

General objectives, policies and processesThe Board has overall responsibility for the determination of the Group’s risk management objectives and policies and, whilst retaining responsibility for them it has delegated the authority for designing and operating processes that ensure the effective implementation of the objectives and policies to the Group’s finance function. The Board receive regular updates from the Director of Finance, Legal & Corporate Affairs through which it reviews the effectiveness of the processes put in place and the appropriateness of the objectives and policies it sets. The overall objective of the Board is to set policies that seek to reduce risk as far as possible without unduly affecting the Group’s competitiveness and flexibility. Further details regarding these policies are set out below:

Credit riskCredit risk is the risk of financial loss to the Group if a customer or a counter party to a financial instrument fails to meet its contractual obligations. The Group is mainly exposed to credit risk from credit sales. It is Group policy, implemented locally, to assess the credit risk of new customers before entering contracts in accordance with best local business practices, and seek external credit ratings where applicable and when available. Potential customers that fail to meet the Group’s benchmark creditworthiness may transact with the business on a prepayment basis only. Credit risk of existing customers is assessed when deemed necessary.

Credit risk also arises from cash and cash equivalents and deposits with banks and financial institutions. For banks and financial institutions, only independently rated parties with an acceptable credit rating are accepted. This risk has obviously increased over the last few years given the global banking crisis, so the Group has more closely monitored the performance of its banks. With effect from early 2011 this monitoring is being supervised on a more formal basis by a newly formed Treasury Committee.

The Group does not currently enter into derivatives to manage credit risk, although in certain isolated cases may take steps to mitigate such risks if it is sufficiently concentrated.

Quantitative disclosures of the credit risk exposure in relation to trade and other receivables which are neither past due nor impaired are disclosed in note 14.

The Group has not historically suffered from defaults from its customers. In the event of any disputes, the Group will always attempt to resolve these in accordance with contractual default procedures, but if ultimately unsuccessful would then resort to legal proceedings.

The Group from time to time reviews whether a greater utilisation of credit ratings would be appropriate. However given that much of the Group’s trade receivables is effectively secured under joint venture agreements against the Group’s oil and gas assets it remains satisfied that this adequately mitigates any risk of default. At the reporting date the Group does not envisage any losses from non-performance of counterparties.

The maximum exposure to credit risk at the balance sheet date was €30,222,000 (2009: €29,496,000).

It is considered that there have been no significant changes in credit risk at the reporting date compared to the previous year end and that therefore this risk has had no material impact on earnings or shareholders’ equity.

Cash flow interest rate riskThe Group is exposed to cash flow interest rate risk from its deposits of cash and cash equivalents with banks. The cash balances maintained by the Group have historically been proactively managed in order to ensure that the maximum level of interest is received for the available funds but without affecting the working capital flexibility the Group requires. However in response to the 2008 banking crisis, and given significant reductions in interest rates, the current focus has switched more towards preservation of capital (see above). The Group has recently decided to more proactively seek to increase the returns on its cash and again this is being supervised by the newly formed Treasury Committee.

The Group is not at present exposed to cash flow interest rate risk on borrowings as it has no debt. No subsidiary company of the Group is permitted to enter into any borrowing facility or lease agreement without the prior consent of the Company.

Interest rates on financial assets and liabilitiesThe Group’s financial assets consist of cash and cash equivalents, loans, trade and other receivables. The interest rate profile at 31 December of these assets was as follows:

Financial assets on

which floating rate interest

is earned€’000

Financial assets on which no

interest earned€’000

Total€’000

2010

Euro 17,707 5,567 23,274

UK Sterling 5,599 518 6,117

US Dollar 784 47 831

24,090 6,132 30,222

2009

Euro 13,383 13,652 27,035

UK Sterling 1,204 669 1,873

US Dollar 410 178 588

14,997 14,499 29,496

The UK Sterling assets largely comprise cash on call accounts and placed on money markets on call and short term debtors. The US Dollar assets largely represent cash on call accounts and the Euro assets comprise cash on call accounts and placed on money markets on call and short term debtors. The Group earned interest on its interest bearing financial assets at rates between 0% and 2% (2009: 0% and 8.125%) during the year. All financial assets on which no interest is earned are considered immediately available to turn into cash on demand.

Had average interest rates (approximately 0.5%) in 2010 been 25% higher (i.e. 0.625%), the Group’s finance income of €17,000 would have been €2,000 higher. Had average interest rates in 2010 been 25% lower, the Group’s finance income would have been €2,000 lower.

It is considered that there have been no significant changes in cash flow interest rate risk at the reporting date compared to the previous year end and that therefore this risk has had no material impact on earnings or shareholders’ equity.

Foreign exchange riskForeign exchange risk arises because the Group has operations located in various parts of the world whose functional currency is not the same as the functional currency in which other Group companies are operating. Although its geographical spread reduces the Group’s operational risk, the Group’s net assets arising from such overseas operations are exposed to currency risk resulting in gains and losses on retranslation into Euro. Only in exceptional circumstances will the Group consider hedging its net investments in non-Euro operations as generally it does not consider that the reduction in foreign currency exposure warrants the cash flow risk created from such hedging techniques. It is the Group’s policy to ensure that individual Group entities enter into local transactions in their functional currency wherever possible and that only surplus funds over and above working capital requirements should be transferred to the Parent Company treasury. The Group considers this policy minimises any unnecessary foreign exchange exposure.

In order to monitor the continuing effectiveness of this policy the Board through their approval of both corporate and capital expenditure budgets, and review of the currency profile of cash balances and management accounts, considers the effectiveness of the policy on an ongoing basis.



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22. Financial Instruments continuedThe following table discloses the exchange rates of the major currencies utilised by the Group:

US Dollar UK Sterling

Foreign currency units to €1 Euro(rounded to two decimal places)

Average for 2010 1.33 0.86

At 31 December 2010 1.34 0.86

Average for 2009 1.39 0.89

At 31 December 2009 1.44 0.88

CurrencyexposuresThe monetary assets and liabilities of the Group that are not denominated in Euro are therefore exposed to currency fluctuations and are shown below. The amounts shown represent the Euro equivalent of local currency balances.

UK Sterling€’000

US Dollar€’000

Other€’000

Total€’000

Euro equivalent of exposed net monetary assets and liabilities

At 31 December 2010 5,599 784 – 6,383

At 31 December 2009 1,204 410 – 1,614

The Group made a small foreign exchange gain in the first half. However, during the second half of 2010, (1 July to 31 December), UK Sterling fell by 4.7%, (£0.82215 to £0.86075), against the Euro, resulting in an overall foreign exchange loss for the year of €348,000.

Had Sterling fallen by 10% against the Euro, the loss would have been €741,000. Had Sterling risen by 10% against the Euro, the gain would have been €741,000. Over the same period the net asset value of the Group’s subsidiaries which have retained Pounds Sterling as their functional currency fell by €193,000 on translation and presentation in Euro. Had Sterling fallen by 10% against the Euro, the rise in their net asset value would have been €19,000. Had Sterling fallen by 10%, the fall in their net asset value would have been €410,000.

A number of the Company’s subsidiaries use Sterling as their functional currency, so movements in the Euro / Sterling exchange rate affects the Group’s balance sheet, with exchange differences that arise on consolidation being taken to reserves. The majority of revenues and costs associated with the Group’s Dutch and Italian assets remain naturally hedged, however there is the likelihood that future Dutch oil revenues, as with the Group’s UK oil revenues, will be denominated in US Dollars, while the majority of costs incurred on the UK assets will be in Sterling, neither of which are the reporting or functional currency of the Company. Consequently exchange gains or losses will continue to be reported within future income statements.

Liquidity risk Liquidity risk arises from the Group’s management of working capital and the finance charges and principal repayments on its debt instruments. It is the risk that the Group will encounter difficulty in meeting its financial obligations as they fall due.

The Group’s policy is to ensure that it will always have sufficient cash to allow it to meet its liabilities when they become due. To achieve this aim, it seeks to maintain readily available cash balances (or agreed facilities) to meet expected requirements for a period of at least 60 days. The Group currently has no long term borrowings.

Cash forecasts identifying the liquidity requirements of the Group are produced frequently. These are reviewed regularly by management and the Board to ensure that sufficient financial headroom exists for at least a twelve month period. Therefore after taking into account the current business environments of the countries in which the Group has a presence, together with reviewing the Group’s budgets for 2011–2012 and its medium term plans (which include trading of assets, farmouts and reserve based lending), it is anticipated that the Group has, and will have access to, sufficient liquid resources to meet its obligations under all reasonable expected circumstances.

Given the global financial crisis is not far behind us, and the “austerity” measures in force in many First World economies, a considerable number of companies, especially consumer facing ones, continue to face liquidity risk. The Board is however comforted by the fact that the Group remains free of third party debt and has cash (€21.4 million) and other working capital balances (€2.4 million), giving a working capital position totalling approximately €23.8 million at year end. The Board considers this to be sufficient to meet the Group’s commitments and obligations and protect its assets from loss or harm given new Netherlands production recently brought on stream, bringing the Group production and revenue from six gas fields, and more to follow in 2012. Production levels are also deemed sufficient that the Group also has the possibility of entering into a reserved based lending facility when and if it deems it appropriate.

Price riskOil, gas and condensate sales revenue is subject to energy market price risk. The Group’s oil and gas sales revenue in 2010 comprised oil and gas on long term supply contracts, the vast majority of which is gas sales currently committed to GasTerra, from the Waalwijk, P12, Grolloo, Geesbrug, Brakel and Wijk en Aalburg fields. The GasTerra pricing formula (“NIP”) has typically in recent years been updated and agreed with Dutch producers annually during the second quarter of the year, with the new NIP generally taking effect from 1 January each calendar year.

Had average gas prices in 2010 been 20% higher, the Group’s gas revenue of €14,098,000 would have been €2,820,000 higher. Had average gas prices in 2010 been 20% lower, the Group’s gas revenue would have been €2,820,000 lower.

The UK Natural Gas Final Index determined and published by ICE futures on their website www.theice.com and an important component in the Gas Terra BV pricing formula was 58.475 on 31 December 2010 and 33.72 on 31 December 2009. The index was 62.432 on 7 April 2011 and 30.178 on 7 April 2010. The Final Index is calculated at close of trading on the calendar day that the front month contract expires (that is the last but one business day of each month). The final Index represents the un-weighted average of all settlement prices from the expiring “front month” contract. For more information see:

https://www.theice.com/marketdata/reports/ReportCenter.shtml?

Given current production levels and the Group’s commitments to GasTerra, it is currently not considered appropriate for the Group to enter into any hedging activities or trade in any financial instruments, such as derivatives. This strategy will be subject to continued review through 2011 and beyond given the Group’s more significant current cash flow, which will be further supplemented as more of its Netherlands development assets start to come on stream.

Financial liabilitiesThe Group’s financial liabilities consist of trade and other payables. The interest rate profile at 31 December of these liabilities was as follows:

Financial liabilities on

which interestis paid€’000

Financialliabilities on

which nointerest is paid

€’000

2010

Euro – 3,855

UK Sterling – 2,459

Canadian Dollar – 12

Other – –

– 6,326

2009

Euro – 5,867

UK Sterling – 1,483

Canadian Dollar – 739

Other – 14

– 8,103

The Group’s short term creditors are considered payable on demand. The Group’s decommissioning liabilities are considered likely to be payable in greater than one year from the balance sheet date, but given the numerous factors that can affect the timing of the abandonment of the Group’s oil fields, a maturity profile for these liabilities is not considered appropriate. Further details on the decommissioning liabilities are set out in note 16.



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22. Financial Instruments continuedFair value hierarchyIFRS 7 requires the classification of fair value measurements using a fair value hierarchy that reflects the significance of the inputs used to determine those fair values. The Group has no financial instruments whose fair value has been determined using a valuation technique required to be discussed by IFRS 7.

Capital management policiesAs described in note 18 the Group considers its capital to comprise of its ordinary share capital, share premium, distributable reserves and accumulated retained earnings.

In managing its capital, the Group’s primary objective is to ensure its continued ability to provide a consistent return for its equity shareholders, principally though capital growth, although the Company now has significant distributable reserves and has, and will continue to, consider paying dividends and / or the buyback of ordinary shares. In order to achieve and seek to maximise this return objective, the Group will in the future seek to maintain a gearing ratio that balances risks and returns at an acceptable level while also maintaining a sufficient funding base to enable the Group to meet its working capital and strategic investment needs. In making decisions to adjust its capital structure to achieve these aims, either through new share issues, increases or reductions in debt, or altering its dividend or share buyback policies, the Group considers not only its short term position but also its medium and longer term operational and strategic objectives.

The Group currently has no external debt, however your Board remains keen in the near term to have within its armoury an appropriate level of financing as highlighted above.

There have been no other significant changes to the Group’s capital management objectives, policies and processes during the year nor has there been any change in what the Group considers to be its capital.

23. Post Balance Sheet EventsSince the balance sheet date 31 December 2010 and the date that these financial statements have been signed, the following developments have been announced which have a material impact on the financial statements or the understanding of the financial statements.

25 March 2011 – New partner for Southern Adriatic PermitsThe Company announced that it has signed an agreement involving Italian permits F.R39.NP and F.R40.NP which contain the Rovesti and Giove oil discoveries and ten mapped prospects. The objective of the agreement is to work with Azimuth Limited (“Azimuth”) a specialist global E&P business, to define and delineate suitable appraisal and exploration drilling targets. Azimuth will become a 15% interest partner in both permits by funding a promoted share of future work programmes prior to the drilling phase. Upon completion of the agreement with Azimuth, Northern’s net Probable reserves in Italy will be reduced to approximately 45.2 million boe.

The future assignment of permit interests to Azimuth, and implementation of aspects of the agreement, are subject to receiving approvals from the Italian authorities.

Volumes – Group

Total

Oil Gas Petroleum

Millionbbl bcf

Millionboe

At 31 December 2009: 70.84 185.85 102.88Changes during the period:Revisions of previous estimates – (75.35) (12.99)Production (0.02) (2.44) (0.44)At 31 December 2010: 70.82 108.06 89.45

Volumes and categorisation by location – GroupTotal

Oil Gas Petroleum

Millionbbl bcf

Millionboe

At 31 December 2010:Proven reserves 6.52 86.10 21.36Probable reserves 64.30 21.96 68.09

70.82 108.06 89.45

At 31 December 2009:Proven reserves 6.54 109.24 25.37Probable reserves 64.30 76.61 77.51

70.84 185.85 102.88

United Kingdom Netherlands Italy

Oil Gas Petroleum Oil Gas Petroleum Oil Gas Petroleum

Millionbbl bcf

Millionboe

Millionbbl bcf

Millionboe

Millionbbl bcf

Millionboe

At 31 December 2010:Proven reserves 0.77 – 0.77 5.75 86.10 20.59 – – –Probable reserves 6.24 – 6.24 4.90 21.96 8.69 53.16 – 53.16

7.01 – 7.01 10.65 108.06 29.28 53.16 – 53.16

At 31 December 2009:Proven reserves 0.78 – 0.78 5.76 109.24 24.59 – – –Probable reserves 6.24 – 6.24 4.90 76.61 18.11 53.16 – 53.16

7.02 – 7.02 10.66 185.85 42.70 53.16 – 53.16


Unaudited Statement of Net Commercial Oil & Gas Reserve Quantities – Proven and Probable Reservesat 31 December 2010


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Notes:1. The Reserve estimates shown in this report are based upon the joint reserve and resource definitions of the Society of Petroleum Engineers, the World

Petroleum Congress, and the American Association of Petroleum Geologists.

2. Proven and probable reserves in the UK represent the Group’s reserves at year end as determined during 2010 by RPS Energy in an independent valuation of some of the Group’s oil and gas assets in the Weald Basin. Further information is given in note 11 to the 2010 Report & Accounts.

3. Proven and probable reserves for Brakel, Ottoland and Papekop represent reserves as determined during 2010 by RPS Energy in an independent valuation of some of the Group’s oil and gas assets in The Netherlands. Further information is given in note 11 to the 2010 Report & Accounts. These reserves, other than in respect of Papekop, were originally acquired as a result of the Group’s agreements with NAM. The reserves in The Netherlands which are held as a result of the Group’s agreements with NAM are subject to a 50% net profit interest after payback of 130% of the Group’s capital costs. The Papekop production licence is subject to a 0.6% gross overriding royalty over the Group’s interest.

4. Geesbrug, Grolloo and Wijk en Aalburg proven and probable reserves are the Group’s most recent estimates as announced on 27 May 2011, which supersede reserves as determined during 2010 by RPS Energy in an independent valuation of some of the Group’s oil and gas assets in The Netherlands. Further information is given in note 11 to the 2010 Report & Accounts. These reserves were originally acquired as a result of the Group’s agreements with NAM and are subject to a 50% net profit interest after payback of 130% of the Group’s capital costs.

5. Waalwijk proven and probable reserves are the Group’s most recent estimates.

6. P12 reserves are as determined by current operator’s most recent estimates.

7. Proven and probable reserves in Italy represent the Group’s reserves as determined by Blackwatch Petroleum Services in independent valuations of some of the Group’s oil and gas assets in that country during the fourth quarter of 2007.

8. Quantities of oil equivalent are calculated using a gas-to-oil conversion factor of 5,800 scf of gas per boe.

Notes2010

€’0002009

€’000

Fixed assetsIntangible assets 3 999 –Tangible assets 4 290 329Investments 5 16,034 15,439Total fixed assets 17,323 15,768

Current assetsDebtors – due within one year 6 32,477 27,459Debtors – due after more than one year 6 129 118

Total debtors 32,606 27,577

Cash at bank and in hand 16,295 12,80648,901 40,383

Creditors: amounts falling due within one year 7 (1,645) (2,668)

Net current assets 47,256 37,715

Total assets less current liabilities 64,579 53,483

Creditors: amounts falling due after more than one year 7 (30) (169)

Net assets 64,549 53,314

Capital and reservesCalled up share capital 8 5,768 4,983Share premium 9 11,501 194Merger reserve 9 10,289 10,289Special reserve (Distributable) 9 28,428 28,410Special reserve (Un-distributable) 9 155 173Share incentive plan reserve 9 3,964 3,865Profit and loss account 9 4,444 5,400Shareholders’ funds 10 64,549 53,314


These financial statements were approved and authorised for issue by the Board of Directors on 7 June 2011 and were signed on its behalf by:

D R Musgrove C J FossDirector Director

REGISTERED NO. 02933545

Unaudited Statement of Net Commercial Oil & Gas Reserve Quantities – Proven and Probable Reservesat 31 December 2010

Company Balance Sheetat 31 December 2010


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1. Accounting PoliciesThe principal accounting policies applied in the preparation of these financial statements are set out below. These policies have been consistently applied to all the years presented, unless otherwise stated.

Basis of preparationThe financial statements have been prepared under the historical cost convention and in accordance with applicable UK accounting standards.

The Company has taken advantage of Section 408(4) of the Companies Act 2006 in not presenting its own profit and loss account. The Company’s loss for the year was €1,363,000 (2009: loss of €1,562,000).

In accordance with the exemptions available under FRS 1 “Cash Flow Statements” the Company has not presented a cash flow statement as the cash flow of the Company has been included in the Consolidated Cash Flow Statement of Northern Petroleum Plc.

The Company has taken advantage of the exemption contained in FRS 8 (Related Party Disclosures) and has therefore not disclosed transactions or balances with wholly owned subsidiary entities. In addition the Company has also taken advantage of the exemption in FRS 29 (Financial Instruments: Disclosures) not to present Company only information as the disclosures provided in the notes to the Group consolidated financial statements comply with the requirements of this standard (see note 22 to the Group financial statements).

Going Concern Basis of preparationAfter making enquir ies, the Directors have a reasonable expectation that the Company has adequate resources to meet all its commitments and to continue in operational existence for the foreseeable future. Accordingly they continue to adopt the going concern basis in preparing the Annual Report and Accounts.

TurnoverTurnover comprises income charged, excluding value added and similar taxes, to other companies by the Company in respect of fees for acting as operator of both production and pre-production activities, and fees for other related services.

Income charged, excluding value added and similar taxes, to other companies by the Company in respect of fees for any other services are disclosed within other operating income.

Turnover and income is recognised on an entitlement basis once the significant risks and rewards of ownership have passed to the customer and receipt of future economic benefits is probable.

Share-based paymentsIn accordance with FRS 20 “Share-based payments”, the Company reflects the economic cost of awarding shares and share options to employees, Directors and key suppliers and consultants by recording an expense in the profit and loss account equal to the fair value of the benefit awarded. The expense is recognised in the profit and loss account over the vesting period of the award.

Fair value is measured by use of a Black Scholes model which takes into account conditions attached to the vesting and exercise of the equity instruments. The expected life used in the model is adjusted, based on management’s best estimate, for the effects of non-transferability, exercise restrictions and behavioural considerations.

DepreciationThe cost of fixed assets is written off by equal annual instalments over their expected useful lives, as follows:

• Leasehold improvements – over the term of the lease• Computer hardware and software – four years• Office equipment – four years• Motor vehicles – four years

The carrying values of tangible fixed assets are reviewed for impairment if events or changes in circumstances indicate the carrying value may not be recoverable.

Tangible fixed assetsTangible fixed assets are included in the balance sheet at cost, less accumulated depreciation and any provisions for impairment.

Intangible fixed assetsIntangible fixed assets are included in the balance sheet at cost, less accumulated depreciation and any provisions for impairment.

InvestmentsFixed asset investments are included in the balance sheet at cost, less any amounts written off.

Current asset investments are stated at the lower of cost and net realisable value.

Lease CommitmentsThe annual rentals under operating leases are charged to the profit and loss account on a straight-line basis over the term of the lease.

Foreign currenciesForeign currency transactions of the Company are translated into its functional currency at the rates ruling when the transactions occurred. Monetary assets and liabilities denominated in other currencies are retranslated at the rate of exchange ruling at the balance sheet date. All differences are taken to the profit and loss account.

The exchange rates of the major currencies utilised by the Company are disclosed in note 22 of the Group financial statements.

Deferred taxationDeferred tax is recognised in respect of all timing differences that have originated but not reversed at the balance sheet date where transactions or events have occurred at that date that will result in an obligation to pay more, or a right to pay less or to receive more, tax, with the following exceptions:

• provision is made for deferred tax that would arise on remittance of the retained earnings of overseas subsidiaries, associates and joint ventures only to the extent that, at the balance sheet date, dividends have been accrued as receivable;

• deferred tax assets are recognised only to the extent that the Directors consider that it is more likely than not that there will be suitable taxable profits from which the future reversal of the underlying timing differences can be deducted.

Deferred tax is measured on an undiscounted basis at the tax rates that are expected to apply in the periods in which timing differences reverse, based on tax rates and laws enacted or substantively enacted at the balance sheet date.

2. Directors’ Remuneration


2010€’000


2009€’000

Executive salaries including bonus 874 1,133

Non-Executive fees including bonus 152 223

Compensation for loss of office 219 –

Benefits in kind 48 41

Emoluments 1,293 1,397

Details for each Director’s remuneration and interests in warrants exercisable into the Company’s shares are set out in the tables below. This information can also be found on page 40 in the Report on Directors’ Remuneration in the Group’s consolidated financial statements. The total remuneration of the highest paid Director was €332,000 (2009: €462,000).



Bonus€’000

Compen-sation

for loss of office

€’000

Otherbenefits

€’000Total

€’000


Bonus€’000

Otherbenefits

€’000Total

€’000

Executive Directors (salaries):

C J Foss 247 – – 11 258 231 115 9 355

G L Heard 230 – – 9 239 223 115 9 347

D R Musgrove 317 – – 15 332 299 150 13 462

N Wright 80 – 219 2 301 – – – –

Non-Executive Directors (fees):

A N Brewer 42 – – 3 45 41 21 3 65

R H R Latham 65 – – 6 71 63 33 5 101

J M White 45 – – 2 47 43 22 2 67

1,026 – 219 48 1,293 900 456 41 1,397

Part of the bonus scheme in 2009 was settled in shares and accounted for under IFRS 2. Consequently €170,000 of the remuneration received by the Directors was excluded from the income statement in 2009 in line with applicable accounting standards.

On the exercise of warrants during the year the Directors made aggregate notional gains of £582,000 (€646,000) (2009: £55,000, €62,000); the highest single gain made by an individual director was £333,000 (€370,000) (2009: £55,000, €62,000).

Notes to the Company Accountsfor the year ended 31 December 2010


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3. Intangible Fixed Assets

Computersoftware

€’000

Cost:


Additions 999


Depreciation:


Charge for the year –

At 31 December 2010 –

Netbookvalue:


4. Tangible Fixed Assets


€’000

Computer and office equipment

€’000

Motor vehicles

€’000Total

€’000

Cost:

At 1 January 2010 303 535 – 838

Additions – 116 36 152

At 31 December 2010 303 651 36 990

Depreciation:

At 1 January 2010 178 331 – 509

Charge for the year 76 112 3 191

At 31 December 2010 254 443 3 700

Netbookvalue:

At 31 December 2010 49 208 33 290

At 31 December 2009 125 204 – 329

5. Investments

Unlisted Investments

€’000

Investments insubsidiaries

€’000

TotalInvestments

€’000

Cost:

At 1 January 2010 15 15,424 15,439

Additions – 595 595

At 31 December 2010 15 16,019 16,034

Provision:

At 1 January and 31 December 2010 – – –

Carrying value at 31 December 2010 15 16,019 16,034

Carrying value at 31 December 2009 15 15,424 15,439

Included in the above are the Company’s interests at the year end in the following material subsidiary undertakings which are included in the consolidated accounts:



of operation


shares held

NorthernPetroleum(GB)Limited England&WalesOilandgasexploration


of£1–100%

NorthernPetroleum(UK)Limited England&WalesOilandgasexploration

andproduction ItalyOrdinaryshares

of£0.001–100%

NPOffshoreHoldings(UK)Limited England&WalesHoldingcompanyandoilandgasexploration UK

Ordinarysharesof£1–100%

NPOil&GasHoldingsLimited England&Wales

Holdingcompanyandoilandgasexploration


of£1–100%

NorthernPetroleumE&PHoldingsLimited(formerlyATIOilLimited) England&Wales Oilandgasexploration Italy

Ordinarysharesof£0.0025–97.89%

The Company has accounted for its investments in subsidiaries at cost, less any amounts written off.

Included in the above are the Company’s interests at the year end in the following associated undertakings:



of operation


shares held

Oil&GasInvestmentsLimited England&Wales Oilandgasexploration UKOrdinaryshares

of£1–41.32%

The Company has accounted for its investments in associate undertakings at cost, less any amounts written off.



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6. Debtors

2010€’000

2009€’000

Trade debtors 272 264

Other debtors 15 4,047

Corporation tax – 144

VAT recoverable 200 81

Amounts due from subsidiary undertakings 31,625 22,791

Prepayments and accrued income 365 132

32,477 27,459

Other debtors – due in greater than one year – –

Loans – due in greater than one year 129 118

Total debtors 32,606 27,577

An interest bearing loan of $200,000 (€129,000 at fair value) at 2% per annum has been made to Northpet Investments Limited, the Group’s 50% joint venture with Wessex Exploration Plc, repayable following the drilling of a well on the Guyane licence.

7. Creditors

2010€’000

2009€’000

Amounts falling due within one year:

Trade creditors 232 172

Corporation tax – 335

Taxation and social security 133 318

Accruals and deferred income 1,280 1,843

1,645 2,668

Amounts falling due after one year:

Trade and other creditors 30 169

1,675 2,837

8. Share Capital

2010€’000

2009€’000

Authorised:

311,316,404(2009:311,316,404)ordinarysharesof5peach 19,648 19,648

Allotted, issued, called up and fully paid:

91,987,445(2009:78,987,248)ordinarysharesof5peach 5,768 4,983

Warrants:Disclosures concerning contingent rights to the allotment of shares in respect of outstanding warrants held by the Board are given in the Report on Directors’ Remuneration. Details of warrants issued, extended and exercised during the year, together with warrants outstanding at 31 December 2010 are as disclosed in note 18 of the Group financial statements.

Analysis of changes in share capital during the year:

2010€’000

2009€’000

At 1 January 4,983 4,488

Shares issued for cash as a result of exercise of warrants 43 6

Shares issued to staff in lieu of salary payments 27 2

Shares issued for cash as a result of placing 715 –

Shares issued as a result of an acquisition through business combination – 487

At 31 December 5,768 4,983

The following issues of new ordinary shares were made during the year:

Sharecapital€’000

Sharepremium

€’000Total

€’000

For cash as a result of exercise of warrants:

8 January 2010 – 37,500 ordinary 5p shares at 67p 2 26 28

26 January 2010 – 17,500 ordinary 5p shares at 67p 1 12 13

3 February 2010 – 37,500 ordinary 5p shares at 67p 2 27 29

26 February 2010 – 280,000 ordinary 5p shares at 11.25p 15 20 35


16 March 2010 – 100,000 ordinary 5p shares at 11.25p 6 6 12

25 June 2010 – 50,000 ordinary 5p shares at 67p 3 38 41

2 July 2010 – 25,000 ordinary 5p shares at 68.5p 2 19 21

6 July 2010 – 50,000 ordinary 5p shares at 67p 3 37 40

27 July 2010 – 12,500 ordinary 5p shares at 67p 1 9 10

1 October 2010 – 25,000 ordinary 5p shares at 68.5p 2 18 19

For cash as a result of exercise of placing:

25 June 2010 – 11,764,706 ordinary 5p shares at 85p 715 10,749 11,464

Issued to staff in lieu of salary payments:


26 October 2010 – 62,244 ordinary 5p shares at 88.875p 2 63 66

785 11,307 12,092

9. Reserves

Sharepremiumaccount

€’000

Mergerreserve

€’000

Specialreserve

(distributable)€’000

Specialreserve

(undistributable)€’000

Shareincentive

plan reserve€’000

Profitand lossaccount

€’000

At 1 January 2010 194 10,289 28,410 173 3,865 5,400

Share-based payments – – – – 799 –

Transfer between reserves for share warrants exercised during the year – – – – (407) 407

Issue of shares during the year – staff bonus 558 – – – (293) –

Transfer between special reserves – – 18 (18) – –

Premium on issue of shares during the year 11,437 – – – – –

Costs and fees associated with placing (688) – – – – –

Loss for the year – – – – – (1,363)

At 31 December 2010 11,501 10,289 28,428 155 3,964 4,444

The merger reserve is explained in the text below the Statement of Changes in Equity within the Group financial statements.



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10. Reconciliation of Movement in Shareholders’ Funds

€’000

Shareholders’ funds at 1 January 2009 42,465

Issue of shares during the year 10,899

Loss for the year (1,562)

Share-based payments 1,512

Shareholders’ funds at 1 January 2010 53,314

Issue of shares during the year 12,780

Costs and fees associated with placing (688)

Loss for the year (1,363)

Share-based payments 799

Issue of shares during the year – staff bonus (share incentive plan reserve) (293)

Shareholders’ funds at 31 December 2010 64,549

11. CommitmentsOperating leasesThe Company’s annual commitments for rental payments under non-cancellable operating leases payable during the year to 31 December 2010 are as follows:

2010 Other

Operatingleases €’000

2010Land and Buildings

€’000

2009 Other

Operatingleases €’000

2009Land and Buildings

€’000

Leases expiring:

Within that year 33 306 – 289

Within the second to fifth years inclusive 6 143 – –

In more than five years – – – –

39 449 – 289

All leases are “operating leases” and the relevant annual rentals are charged to the profit and loss account on a straight line basis over the lease term.

The UK office lease was signed in 2007. The UK office lease rental is subject to review every five years to take account of any changes in the economic climate. There are two break clauses, one for the Company after five years and for the landlord after four years and each subsequent year. No restrictions are imposed by the lease agreement other than a break clause after five years.

12. Contingent Liabilities Payments to DirectorsAdditional payments of two times basic salary or fees are due to Directors in the event that a single shareholder (or group of shareholders acting in concert) obtains control of more than 29.9% of the Company’s ordinary shares and exercises control over the Company or its Board, or seeks to remove the Director concerned from office. With effect from 1 January 2011 these payments amount to £514,440 (€597,665) for D R Musgrove, £394,640 (€458,484) for C J Foss, £394,640 (€458,484) for G L Heard, £111,600 (€129,654) for R H R Latham, £76,680 (€89,085) for J M White and £72,120 (€83,787) for A N Brewer.

13. Related Party TransactionsDuring the year there were no transactions with the Company’s related parties.

14. Post Balance Sheet Events There were no events between the balance sheet date of 31 December 2010 and the date of these financial statements which have a material impact on the financial statements, or the understanding of the financial statements, of the Company.

NOTICE IS HEREBY GIVEN that the Annual General Meeting of the Company will be held at Stationers’ Hall, Ave Maria Lane, London, EC4M 7DD on 29 June 2011 at 10.30am for the following purposes:

To consider and, if thought fit, pass the following resolutions to be proposed as Ordinary Resolutions:

1. To receive the report of the Directors and the audited accounts for the year ended 31 December 2010.

2. To re-appoint KPMG Audit Plc as auditors and to authorise the Directors to fix their remuneration.

3. To re-elect A N Brewer (who retires from office in accordance with Article 108 of the Company’s Articles) as a Director of the Company.

4. To authorise the Directors, pursuant to and in accordance with section 551 of the Companies Act 2006 (the “Act”) to exercise all powers of the Company to allot ordinary shares in the capital of the Company and grant rights to subscribe for or convert any security into ordinary shares up to a maximum aggregate nominal value of £1,162,500 (being approximately 25% of the Company’s issued share capital as at the date of this notice), provided that such authority shall expire at the conclusion of the next Annual General Meeting of the Company, except that the Directors may, before such expiry, make offers or agreements which would or might require ordinary shares to be allotted or rights to be granted after such expiry and allot ordinary shares or grant rights in pursuance of such offers or agreements.

To consider and, if thought fit, pass the following resolutions to be proposed as Special Resolutions:

5. To authorise the Directors, pursuant to and in accordance with section 570 and 573 of the Act, to allot equity securities (as defined in section 560 of the Act) for cash as if sub-section 561 of the Act did not apply to the allotment of equity securities pursuant to the authority conferred on them under section 551 of the Act up to the aggregate nominal value of £465,000 (being approximately 10% of the Company’s issued share capital as at the date of this notice), such power to expire on the earlier of the conclusion of the next Annual General Meeting of the Company and 15 months after the date of the resolution (but so as to enable the Company, before the expiry of such power, to make offers or agreements which would or might require equity securities to be allotted after such expiry and to enable them to allot equity securities for cash pursuant to such offers or agreements as if the power conferred thereby had not expired).

6. To authorise the Company, generally and unconditionally, to make market purchases (within the meaning of section 693(4) of the Act) pursuant to and in accordance with section 701 of the Act of fully paid ordinary shares in the capital of the Company upon and subject to the following conditions but otherwise unconditionally:

a) the maximum number of ordinary shares hereby authorised to be purchased is 4,650,000, which is approximately 5% of the ordinary share capital of the Company as at the date of this notice;

b) the maximum price which may be paid for each such ordinary share shall be an amount no more than 105% of the average of the middle market quotations for an ordinary share as derived from the Alternative Investment Market of the London Stock Exchange for the five business days immediately preceding the day on which such ordinary share is contracted to be purchased (excluding expenses) and the minimum price which may be paid for such ordinary share shall be the nominal value of such ordinary share at the time of such purchase (excluding expenses); and

c) unless previously varied, revoked or renewed, the authority conferred by this resolution shall expire on the earlier of the date 15 months after the passing of this resolution and at the conclusion of the next Annual General Meeting of the Company after the date on which this resolution is passed, provided that the Company may before such expiry date enter into a contract to purchase ordinary shares under this authority which will or may be completed or executed wholly or partly after the expiration of such authority and may make a purchase of ordinary shares in pursuance of such contract.

By order of the Board

C J FossSecretary

Registered Office:2nd Floor, Martin House5 Martin LaneLondon EC4R 0DP

Dated 7 June 2011


Notice of Annual General Meeting


Corporate

Accounts

Governance

Notes:1. A member of the Company entitled to attend and vote at the meeting convened by this Notice may appoint a proxy to attend and vote on a poll

in his stead. A proxy need not be a member of the Company. A member may appoint more than one proxy provided that such appointment is in respect of voting rights attaching to different shares.

2. To be valid, the enclosed Form of Proxy must be completed and lodged together with the Power of Attorney or any other authority (if any) under which it is signed, or a notarially certified copy thereof, at the offices of the Company’s Registrars, Neville Registrars Limited, Neville House, 18 Laurel Lane, Halesowen, West Midlands B63 3DA not less than forty eight hours before the time appointed for holding the meeting.

3. Completion of the proxy does not preclude a member from attending and voting at the meeting if they so wish.

4. The Company, pursuant to Regulation 41 of the Uncertificated Securities Regulations 2001, hereby specifies that only those shareholders registered on the Register of Members of the Company at 10.30am on 27 June 2011 shall be entitled to attend or vote at the meeting in respect of shares registered in their name at the time. Changes to entries on the relevant Register of Members after this time shall be disregarded in determining the rights of any person to attend or vote at the meeting, notwithstanding any provisions in any enactment, the articles of association of the Company or other instrument to the contrary.

Notice of Annual General Meetingcontinued

Governance

Accounts

Corporate

Form of Proxyfor use by members at the Annual General Meeting to be held on 29 June 2011

I / We,

(PLEASE COMPLETE IN BLOCK CAPITALS)

of

being a member / members of the Company hereby appoint the Chairman of the Meeting or (please see note 4 below)

of

as my / our proxy to vote for me / us and on my / our behalf at the Annual General Meeting of the Company to be held on 29 June 2011 at 10.30am and at every adjournment thereof and to sign on my / our behalf any consent to short notice relating thereto.

I / We direct my / our proxy to vote on the Resolutions set out in the notice convening the Annual General Meeting of the Company dated 29 June 2011 as follows and otherwise as he / she shall think fit:

For Against Vote withheld

Ordinary Resolutions:

1 Report & Accounts

2 Appointment of Auditors

3 A N Brewer as Director

4 Authority to allot

Special Resolutions:

5 Authority to allot

6 Authority to make market purchases of own shares

Signed

Full name and address (IN CAPITAL LETTERS)

1. To be valid for the Annual General Meeting or the adjourned Annual General Meeting, this proxy and the power of attorney (if any) under which it is signed, or a notarially certified copy thereof, must reach the offices of the Company’s Registrars, Neville Registrars Limited, Neville House, 18 Laurel Lane, Halesowen, West Midlands, B63 3DA not later than 10.30am on 27 June 2011.

2. In the case of a corporate shareholder this form of proxy may be given under its seal or signed on its behalf by a duly authorised attorney or officer of the corporate shareholder. In the case of joint holders, this form of proxy may be signed by the first named joint holder in the Register of Shareholders.

3. Instruction as to voting should be indicated by an “X” in the appropriate box. In the absence of instructions as to voting and on any other business that may properly be considered by the meeting the proxy will vote (or abstain from voting) as he / she thinks fit.

4. If it is desired to appoint a proxy other than the Chairman of the Meeting, the words “the Chairman of the Meeting” should be deleted and the name and address of the person to be appointed should be inserted in the space provided.

5. Any alteration to this Form of Proxy must be initialled.

6. Completion of this proxy does not preclude a member from attending and voting at the meeting should they so wish.

Dated

#

Neville Registrars LimitedNeville House 18 Laurel LaneHalesowenWest Midlands B63 3DA

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Glossary of Terms and Abbreviations

2D, 3D two / three dimensional (in relation to seismic surveys)

2P Proven plus Probable reserves

3P Proven, Probable plus Possible reserves

P50Reserves are with those with a notional 50% probability – “reasonably Probable” of being produced using current or likely technology at current prices, with current commercial terms and government consent.

€

Euro

£ British pound

$ US dollar

AGM Annual General Meeting

AIM Alternative Investment Market of the London Stock Exchange

API American Petroleum Institute

AzimuthAzimuth Limited

bbl barrel(s) of oil

B, b billion

bcf billion cubic feet

bcm billion cubic metres

Blackwatch Blackwatch Petroleum Services Ltd

boe barrel(s) of oil equivalent

boepd barrel(s) of oil equivalent per day

bopd barrel(s) of oil per day

cfcubic feet

cfd cubic feet per day

€ct/m3

Euro cents per metre cubed

d day

DBS Deferred Bonus Scheme

Dyas Dyas B.V.

EBN Energie Beheer Nederlandse B.V.

EBITDA Earnings Before Interest, Taxes, Depreciation and Amortisation

ENI Eni SpA

EU European Union

FPSO Floating Production and Storage Offloading Vessel

FRS Financial Reporting Standard

GAAP Generally Accepted Accounting Practice

Guyane EEL Guyane Maritime Permit

HSE Health, Safety and the Environment

IAS International Accounting Standards

IFRS International Financial Reporting Standards

ft feet

km, km² kilometre, square kilometres

KPI Key Performance Indicator

KPMG KPMG Audit Plc

m metres

M thousand (10^3)

MM million (10^6)

MMBBL million barrels

MMBO million barrels of oil

MMBOE million barrels of oil equivalent

mmcfd millions of cubic feet per day (of gas)

NAMNederlandse Aardolie Maatschappij B.V.: Netherlands joint venture between Shell and Exxon.

Net to NorthernNorthern Petroleum’s share

Northern or the Groupthe Company and its subsidiaries

NPNNorthern Petroleum Nederland B.V.: Dutch subsidiary of Northern Petroleum Plc.

Orca Exploration Orca Exploration Group Inc.

p pence

PetroCanada Petro-Canada Netherlands B.V.

Probable Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable in this context and when probabilistic methods are used, there should be at least at least a 50 per cent probability that the quant i t ies actual ly recovered will equal or exceed the sum of estimated proved plus probable reserves.

ProspectPotential drilling target that is well defined by seismic data.

ProvedProved reserves are those quantities of petroleum which, by analysis of geological and eng inee r i ng da ta , can be est imated wi th reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions.

Providence Providence Resources (GB) Limited

RPS RPS Energy

Shell Italia Shell Italia E&P S.p.A.

Shell Shell E&P France SAS

scf standard cubic feet

Star Energy Star Energy Group plc

million stb million Stock Tank Barrels

T, t trillion (10^12)

the Company Northern Petroleum Plc

Total Total E&P Guyane Francaise SAS

TSR Total shareholder return

Tullow Tullow Oil Plc

UITF Urgent Issues Task Force

UK United Kingdom

US United States

Wessex Wessex Exploration

Corporate

Governance

Accounts

North

ern P

etroleum

Plc A

nnual Report and A

ccounts 2010





Italy

Belgium

Republic of Ireland

Luxembourg

Germany

Slovakia

Poland

Czech Republic

Denmark

Norway

Sweden


Kingdom

France

Spain

Portugal

Switzerland

AlgeriaMorocco

Gibraltar

Tunisia

Malta

Slovenia

Croatia


Albania

Montenegro

Greece

Austria Hungary


Suriname

Guyana

Venezuela

Brazil

ColombiaGuyane

AnnualReportandAccounts2010

Northern Petroleum Plc

Addingandrealisingshareholdervalue

NorthernPetroleumPlcMartin House5 Martin LaneLondon EC4R 0DPTelephone: 020 7469 2900Facsimile: 020 7469 2901E-mail: [email protected]: www.northpet.com

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