Annual Report and Accounts 2011 - Cabot Energy Plc · 13Northern Petroleum Plc The Context of our...

North

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

© Northern Petroleum PlcJune 2012

Designed and produced by SampsonMaywww.sampsonmay.com

2 Performance highlights3 Progress4 Chairman’s Statement7 Northern’s Business Model9 Delivering on our Strategy10 Case Studies13 The Context of our Operations15 The Group at a Glance16 Review of Operations25 Corporate Statement – Health, Safety and the Environment 26 Risk Management28 Financial Review 34 Directors and Advisers 37 Directors’ Report40 Statement of Directors’ Responsibilities41 Report on Directors’ Remuneration 45 Independent Auditors’ Report

46 Consolidated Income Statement47 Consolidated Statement of Comprehensive Income 48 Consolidated Statement of Financial Position49 Consolidated Statement of Cash Flows 50 Consolidated Statement of Changes in Equity51 Notes to the Accounts 82 Unaudited Statement of Reserves 84 Company Balance Sheet 85 Notes to the Company Accounts92 Notice of Annual General Meeting95 Form of Proxyibc Glossary of Terms and Abbreviations

Northern Petroleum manages operations in the Netherlands, Italy, the United Kingdom and has a licence interest in Guyane.

Northern Petroleum PlcAnnual Report and Accounts 2011

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

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53.16 million*Oil million bbl: Net probable reserves 53.16 Total net reserves boe: 53.16* 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 The Netherlands see p16

For more information on Northern’s operations in the UK see p19For more information on Northern’s operations in Italy see p23 For more information on Northern’s operations in Guyane see p21

Licence Status Interest OperatorOnshore – ExplorationPo ValleySavio Permit 80.00% NorthernLongastrino Permit 30.00%* NorthernLa Sacca Permit 100.00% NorthernPunta Marina Permit 100.00% NorthernCascina Alberto Application 100.00% NorthernOffshore – Exploration

Sicily Channel, West of Sicily Thrust BeltG.R17.NP Permit 45.00%** NorthernG.R18.NP Permit 45.00%** NorthernG.R19.NP Permit 45.00%** NorthernG.R20.NP Permit 30.00%** NorthernG.R21.NP Permit 30.00%** NorthernG.R22.NP Permit 30.00%** NorthernD362C.R-.NP† Application 100.00% NorthernD21G.R-.NP Application 100.00% NorthernD25G.R-.NP Application 100.00% NorthernD26G.R-.NP Application 100.00% NorthernSicily ChannelC.R146.NP Permit 100.00% NorthernD351C.R-.NP Application 100.00% NorthernSicily Channel Offshore SicilyD347C.R-.NP Application 100.00% NorthernD358C.R-.EL Application 50.00% PetrocelticD29G.R-.NP Application 50.00% NorthernD30G.R-.NP Application 100.00% NorthernIonian Sea, Offshore Sicily D63F.R-.NP Application 100.00% NorthernD77F.R-.NP Application 100.00% NorthernD75F.R-.NP† Application 100.00% NorthernD78F.R-.NP† Application 100.00% NorthernSouthern AdriaticF.R 39.NP Permit 85.00%^ NorthernF.R 40.NP Permit 85.00%^ NorthernD149D.R-.NP Application 100.00% NorthernD60F.R-.NP Application 100.00% NorthernD61F.R-.NP Application 100.00% NorthernD65F.R-.NP Application 100.00% NorthernD66F.R-.NP Application 100.00% NorthernD71F.R-.NP Application 100.00% NorthernD72F.R-.NP Application 100.00% Northern

* 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

9 Offshore permits20 Offshore applications

4.35 millionOil million bbl: Net proven reserves 0.63; Net probable reserves 3.72 Total net reserves boe: 4.35

Exploration phase

Licence Interest* OperatorOffshore – ExplorationGuyane EEL 1.25% Shell

* 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 126 50.00% NorthernPEDL 155 50.00% NorthernPEDL 233 50.00% ProvidencePEDL 240 62.50% NorthernPEDL 256 50.00% NorthernOffshore – ExplorationP1916 62.50% NorthernOnshore – ProductionPL211 (Horndean Oilfield) 10.00% Star EnergyPEDL 070 (Avington Oilfield) 5.00% Star Energy

United Kingdom9 Exploration and production licences2 Producing oil fields

Guyane

Where We Operate: Licences and Applications

18.04 millionOil million bbl: Net proven reserves 3.17; Net probable reserves 1.03 Gas bcf: Net proven reserves 61.67; Net probable reserves 18.60 Petroleum million boe: Net proven reserves 13.80; Net probable reserves 4.24 Total net reserves boe: 18.04

Licence Status Interest OperatorOnshore – Exploration Engelen Licence 60.00% NorthernOosterwolde Licence 60.00% NorthernUtrecht Licence 60.00% NorthernAndel V 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 V (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, 3Dtwo / 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.

$US dollar

AGMAnnual General Meeting

AIMAlternative Investment Market of the London Stock Exchange

APIAmerican Petroleum Institute

AzimuthAzimuth Limited

Barrels of oil equivalent (BOE)A term used to summarise the amount of energy that is equivalent to the amount of energy found in a barrel of crude oil. There are 42 gallons (approximately 159 litres) in one barrel of oil, which will contain approximately 5.8 million British Thermal Units (MBtus) or 1,700 kilowatt hours (kWh)

bbl barrel(s) of oil

B, bbillion

bcfbillion cubic feet

bcmbillion cubic metres

BlackwatchBlackwatch Petroleum Services Ltd

boebarrel(s) of oil equivalent

boepdbarrel(s) of oil equivalent per day

bopdbarrel(s) of oil per day

cfcubic feet

cfdcubic feet per day

€ct/m3

Euro cents per metre cubed

DBSDeferred Bonus Scheme

DyasDyas B.V.

EBNEnergie Beheer Nederlandse B.V.

EBITDAEarnings Before Interest, Taxes, Depreciation and Amortisation

ENIEni SpA

EUEuropean Union

FPSO Floating Production and Storage Offloading Vessel

FRSFinancial Reporting Standard

GAAPGenerally Accepted Accounting Practice

Guyane EELGuyane Maritime Permit

HSEHealth, Safety and the Environment

IASInternational Accounting Standards

IFRSInternational Financial Reporting Standards

km, km²kilometre, square kilometres

KPIKey Performance Indicator

KPMGKPMG Audit Plc

m metres

MMBBLmillion barrels

MMBO million barrels of oil

MMBOEmillion barrels of oil equivalent

mmcfdmillions of cubic feet per day (of gas)

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

Net to NorthernNorthern Petroleum’s share

Normal cubic metreMetric expression of gas volume at European standard conditions for temperature and pressure.

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.

PetroCanadaPetro-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.

ProvidenceProvidence Resources (GB) Limited

RPSRPS Energy

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

ShellShell E&P France SAS

scfstandard cubic feet

Star EnergyStar Energy Group plc

million stbmillion Stock Tank Barrels

T, ttrillion (10^12)

the CompanyNorthern Petroleum Plc

TotalTotal E&P Guyane Francaise SAS

TSRTotal shareholder return

TullowTullow Oil Plc

UITFUrgent Issues Task Force

Unconventional energyUnconventional reserves can be defined as reserves which are not commercially recoverable at current prices using conventional technology being situated in rocks of low permeability, which makes the oil gas difficult to access.

WessexWessex Exploration

Working interestRefers to investment in oil and gas drilling operations in which the investor is directly liable for a portion of the ongoing costs associated with exploration, drilling and production and participates on an agreed basis in the profits of any successful wells.

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1Northern Petroleum Plc Annual Report and Accounts 2011

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Northern Petroleum is a full cycle oil and gas exploration and production company with interests in Europe and the newly discovered offshore oil province of major potential in Guyane, off-shore South America.

We have over 50 licences and application for licences, the majority of which are under our management. They cover two producing oil fields, six producing gas fields and a number of exceptional high-quality, exploration projects, all sited in areas of low risk and obtained without high entry costs.

This asset base holds excellent growth opportunities and with a clear long-term strategy we have the objective of bringing significant added-value returns to our shareholders. We will achieve this through exploration, production and trading. The trading element enables us to manage exposure and risks through astute commercial deals and asset sales as our preferred alternative to new equity financing.

Northern Petroleum is a UK public company listed since 1995 on the London Stock Exchange’s Alternative Investment Market, AIM. We have our headquarters in London.

Our strategy is carried out through:

• Identifying and building a pipeline of low entry cost projects• Identifying new opportunities • Identifying early exit routes that will enable us to realise value and either quickly

recycle capital back into our project pipeline or provide finance for future projects

• Sustaining an exemplary standard of safety and environmental practices making the Company a good and welcomed neighbour. This is supported by an open and informative approach to local residents and stakeholders

• Implementing cost-saving efficiencies • Maintaining strong relationships with major industry partners to enable us to

‘punch above our weight’

About Northern Petroleum

2 Northern Petroleum Plc Annual Report and Accounts 2011

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Licences and applications

0 60453015

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2003

2004

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2007

2008

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2011

Licence distribution Production Development Exploration

Reserves by region UK The Netherlands Italy

Performance highlightsEnhancing and expanding our asset base

Some of 2011’s key achievements include:

• Profits before tax of €10.5 million against break-even in 2010• Closing the year with cash of €29.8 million, up from €21.4 million• Achieving on forecast a 31% increase in our daily production rate

even after a downward reserve adjustment• Participating in the discovery of a major new petroleum province

offshore Guyane • Identifying and progressing a new shale oil province in

The Netherlands

• Recognition of near term production optimisation projects for The Netherlands

• Pursuing high impact exploration projects in Italy• Strengthening the management team through the appointment

of a leading international energy executive to your Board of Directors

Financial Operational

€24.5 millionRevenue 2011 up 64%

0 lost time incidents

2 oil fields in productionUK production from Horndean and Avington

€18.25 millionEBITDA 2011 up 259%

Zaedyus oil discoveryNew basin discovery offshore Guyane

600 km 2D seismic acquisitionIn Italy conducted a survey over two permits in the Southern Adriatic

€31.30 million2011 year end working capital up 31%

0.58 million barrels2011 production in oil equivalent

1,545 km² 3D seismic reprocessingIn The Netherlands over the fields, discoveries and exploration prospects

26%Average increase in gas prices achieved in the year

6 gas fields in productionNetherlands gas fields, 5 operated

960 km 2D seismic reprocessingIn The Netherlands over discoveries and exploration prospects


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Progress

2001 DenmarkOffshore $50,000 in shares

2002 Denmark Project terminated

2006 ItalyFarmout to Stratic for seismic

2010 ItalyFarmout to Orca to drill La Tosca

2001 ItalySavio and Longastrino licence applications onshore

2007 ItalyBlackwatch Reserve Report attribution of 53.2 million barrels of oil in 2 fields

2008 Italy• 6 permits farmed out to Shell

for back costs of €1.93 million plus 2D and 3D seismic

• Farmout Avobone to drill Savio well

2004 GuyaneStage 1 $17,500, Stage 2 £40,000, Stage 3 $200,000 loan

2001 IrelandSeven Heads field 4% purchased for £225,000 paid in shares 2000 UK

Licence awards Wessex basin

2003 UK 10% of Horndean field purchased £200,000

2003 UK Farmin to Avington well

2005 UKFarmout of 2 wells on Isle of Wight

2003 UKAvington oil discovery

2010 UKMarkwells Wood oil discovery

2005 The NetherlandsNAM acquisition of 5 fields for nil cost

2007 The NetherlandsWaalwijk field purchase €500,000

2007 Italy2 permits awarded Southern Adriatic

2005 ItalyFirst 3 of 6 permits awarded offshore West Sicily

2008 The NetherlandsSold Waalwijk gas storage project for £7 million

2002 SpainInterest in Ayoluengo field $56,250 net

2005 SpainAyoluengo field sold £300,000

2004 RussiaArbitrated settlement with Lukoil (amount confidential)

1995 RussiaLegacy project

2007 The NetherlandsSold 25% of deal for €32 million + interests in two gas producing fields

2002 IrelandSeven Heads field 4% sold £2 million + £1 million in shares

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2011

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2005

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2002

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Realisation of added value

Entry Costs and Losses controlled

2002 ItalyFirst offshore applications CR146 and CR147

2011 The NetherlandsSale of Vinkega interest for €3.2 million

2011 GuyaneZaedyus oil discovery

2011 ItalyAdriatic farmout to Azimuth for 2D and 3D seismic


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For the 2011 financial year Northern achieved much good progress against our objectives. Most notable has been our exploration success with the ground-breaking Zaedyus oil discovery in Guyane, potentially opening up a new oil province offshore of South America. We have made progress in Italy, and also in The Netherlands where the shale oil potential of our licences on which we have embarked on seeking a divestment or partner to develop the potential, is giving us encouragement. In 2012 and continuing through 2013, a programme of development and exploration wells will start to provide renewed growth taking advantage of our strong asset base. We have the management team and strengthened financial resources from operating activities to ensure that we deliver.

The year was not without its challenges, all of which were dealt with decisively by management and the Board. Despite these challenges, we made significant headway.

Our total annual production was up 31 per cent on 2010, even though in The Netherlands our operations on four new gas fields were at the initial stages, with production to be enhanced following further development drilling. Dutch gas volumes from other fields were maintained and the gas and oil prices we received were higher. The average unit gas price received in The Netherlands in 2011 was €0.264 per normal cubic metre against €0.21 in 2010. This enables us to report robust financial results with revenue up by €9.5 million at €24.5 million, operating cash flow rising to €15.0 million and profit before tax reaching €10.5 million, a material improvement on the 2010 break-even position.

Throughout 2011 we focused on seeking to realise the large upside potential of our portfolio and on continually improving productivity and efficiency at our operations, while reviewing opportunities for new sources of value to enhance growth. We invested a total of €8.7 million in the current asset base of the Group, including the Zaedyus oil discovery in late 2011 which demonstrated the prospectivity of offshore Guyane. Having made this investment we closed the year with €29.8 million cash, against €21.4 million at the end of 2010.

These cash balances are providing us with the strategic flexibility we need to grow the business. Our objectives remain to optimise, expand and grow, underpinning the Company’s long-term future and delivering on our commitment to realise value for our shareholders. In line with our strategy of trading, we will also continue to review whether we should realise any assets in order to fund the building of existing or new opportunities elsewhere.

The review process of our Netherlands fields announced last year continues. All our 3D seismic coverage is being reprocessed and some initial re-interpretations are available on fast track volumes. Preliminary reservoir study results have been assessed and on balance indicate the need for downward revision. However, the results available so far have encouraged us to move forward the plans to drill two new development wells in the Geesbrug gas field. Each will be located on existing sites, those of Geesbrug-1 and Tiendeveen-1, avoiding the time normally required for application for local planning consents. These should boost production revenues next year.

Although we sold our small interest in the Vinkega gas discovery for €3.2million, this has led to recognition of on trend exploration prospects on our licence and these are among plans for drilling being finalised in discussion with our partners.

We have continued to work on our existing production wells and on planning new ones, ensuring that our assets are positioned to generate long-term, more reliable operating performance. To this end we have maintained our absolute commitment to operating in a responsible manner with our host communities and to ensuring that we embed the culture of health and safety in all our operations and activities.

Our industry is becoming an increasingly expensive one in which to operate. Against a backdrop of rising cost pressures we continued to keep a tight rein on out-goings and to operate economically. Given our plans for new exploration and drilling in The Netherlands and the programme in Guyane we have also continued to actively pursue new partnerships so as to be able to deliver progress elsewhere without diluting shareholders’ equity.

Competition for good assets is becoming more and more competitive. However, Northern has established a track record with government authorities as a trusted manager of both onshore and offshore projects, acting with high integrity. However, there has been a heightening of environmental concerns and in consequence it has not always been possible for us to move as fast as we would like.

R H R Latham, Chairman

Chairman’s Statement

WaalwijkGrolloo

GeesbrugBrakel

Wijk en AalburgTTF Price

24

26

28

30

32

AMFJDNOSAJJMAMFJ

Gas price since 1 January 2011Price in €ct/m3


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West of Sicily, we have recognised that Shell is not undertaking to drill a well and we are in discussion with prospective new partners whilst undertaking measures to extend our permits. I would make clear to shareholders that so far this has been a successful deployment of Northern‘s strategy of low entry cost and this post 3D seismic stage has been achieved at little cost to us. We have retained the operatorship and are already in talks on partnership with one large company.

On licence C.R147.NP, offshore Pantelleria, we took the decision to surrender the permit after assessing the full effects of the 2010 decree aimed at protecting the near shore environment. Although it did not affect our current interests directly, the offshore limits set by this decree impacted the potential to discover sufficient associated and primary gas reserves to achieve our target of exceeding our economic threshold requirement for a pipeline to Sicily.

A Memorandum of Understanding has been reached with a gas company, with the prospect of an alliance that could provide finance for gas exploration projects. Discussions on the details are proceeding on a strictly confidential basis so as to better protect the business interests of both parties.

Our onshore Italian projects are no longer considered core, but we are preparing to drill the La Tosca well on a 43bcf gas target after our farm out to Orca Exploration. Drilling operations are expected to commence in August 2012.

In the UK, we have recently suspended our extended production test of the Markwells Wood oil discovery in the South Downs National Park Authority area. I believe our conduct of operations, recognising the interests of the local community and the specific environment in which we are located, has been exemplary. Indeed, our conduct of operations has received many plaudits and we have recently been granted a one year extension of the planning consent.

This appl ies notably in Italy, where Northern has exciting and significant long term opportunities in a large portfolio of assets. Escalation of our operations there continued to be delayed by the slowness of processing application documents through the Italian system, notwithstanding the country’s intense needs for energy industry investment.

The success in Guyane justif ies the Board’s strategy of reviewing and obtaining opportunities for new sources of value. It was as long ago as 2004, ahead of Tullow, Total and Shell that Northern obtained an interest in the Guyane Maritime Licence and for many years it was not regarded in the industry as having any great potential. Now it is recognised as being one of the world’s more exciting new prospects, with the potential of multiple billion barrels of oil. The joint venture, now operated by Shell, will be commencing a 3-4 well programme in the next few months and success can be expected to be followed by a larger programme in order to dril l as many prospects as possible before the end of the licence period in 2016. Northern holds a 1.25% interest via its 50% interest in Northpet Investments Limited.

The project, which pre-Zaedyus was considered high risk, now offers proven potential, though it is too early to be able to accurately assess the risk and reward.

We are continuing to press forward on our Italian portfolio. We are focusing on our offshore core areas around Sicily and in the even more prospective southern Adriatic Sea where our first infill 2D seismic survey has recently been recorded. We still await the requisite permissions there for our planned pre-drilling 600km2 3D seismic survey (which will largely be at our 15% partner Azimuth’s cost). This is the part of our overall Italian portfolio assessed as offering the greatest potential and so is at the forefront of our endeavours. We recognise that to move forward our planned multiple well drilling programme it would be prudent for us to seek a new funding partnership. This summer we will open a data room for interested parties.

TTF PriceGas Price

25

27

29

31

AMFJDNOSAJJMAMFJ

Gas price development – average all fieldsPrice in €ct/m3

US DollarsEuros

80

100

120

140

AMFJDNOSAJJMA

Brent oil prices 2011/12Price in US$ and €/bbl


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Chairman’s Statementcontinued

The results of this test were below expectations. The possibilities for further action will now be examined with our partners, but we have decided to react to the increased risks and uncertainty by reducing our net 2P reserve estimates by 1.35 million barrels of oil until results prove otherwise.

At Hedge End, we have not been able to locate, rent or acquire a suitable drilling location, therefore the licence will shortly lapse so we can no longer carry 1.29 million barrels of oil of net 2P reserves.

However, the reduced reserves are more than balanced by our exciting exploration potential in the UK and elsewhere. Northern has applied for acreage offshore in the UK 27th Round, a move vindicated by the unprecedented number of applications compared to the last few decades. Despite the acute uncertainty about the European economies, prospects for energy prices in Europe are likely to be supported by the continuing heavy reliance on imports.

In respect of the Netherlands the Board has taken the prudent step to reduce its Dutch 2P reserves by 10.67 million boe, 0.43 million boe (2.51 Bscf) of which was taken at the mid year in respect of Wijk en Aalburg, comprising a net reduction of 6.43 million barrels of oil in respect of Ottoland and Papekop and 24.58 Bscf in respect of our gas fields. These further revisions have led to some additional immaterial accelerated DD&A charges in respect of the other producing fields.

Despite awaiting the final reprocessed seismic data in The Netherlands to update in place oil and gas volumes, the Board is required as part of the audit process to provide best estimates of reserves as at year end. As a consequence we advise an overall reduction on the previously reported net 2P reserves estimates for the Group from 88.5 to 75.6 million barrels of oil equivalent, allowing for production in 2011. The net 2P reserves do not include any contribution from the large oil discovery in Guyane, which are yet to be classified as reserves.

We are on target to meet our first half 2012 production target of 1,040 barrels of oil equivalent per day, and can advise that our working production forecast for 2012 is 1,000 barrels of oil equivalent per day. The average unit gas price received in The

Netherlands during the first four months of 2012 has been €0.297 per normal cubic metre. Following possible workovers, interventions and new development wells we anticipate a significant increase in production levels for 2013.

Globally, urbanisation and industrialisation in the populous parts of the world will provide a strong platform for increased demand for energy and support for prices. Although long term fundamentals for growth are strong, there are downside risks in the short term, and the potential for volatility due to persistent economic imbalances and the fragility of the world’s financial systems.

We have strengthened the Board to ensure the most appropriate balance of skills and experience, and to drive effective decision making. We believe we are well prepared for the key challenges facing the energy industry, including the technical challenges that will arise as we move into unconventional energy sources.

To assist the Board’s efforts Dr Rex Gaisford CBE has joined as a new Non-Executive Director of the Company. During his career to date he has been CEO, MD, director, project manager, engineer and negotiator, with many large international oil companies and led major multi-billion dollar exploration, development and production operations world-wide as well as opened up new business opportunities in the UK, US, Denmark, Norway and Brazil.

We have also appointed to the Board Maurice Eaton, Northern’s Director of Group Operations. He has over 30 years experience as a petroleum engineer and economist and substantial international experience with major petroleum companies. This marks the first appointment for some time that we have made to the Board from our existing talented staff, which gives me great pleasure, as well as underlining the quality of the professional team we have at Northern.

On behalf of the Board, I would like to thank all of our staff for their commitment, enthusiasm and hard work during the past year in developing our business and delivering on our potential. I would also like to congratulate them on our excellent safety record. At the Waalwijk gas field, the crew exceeded one million work hours without a lost time incident, a tremendous achievement of which we are extremely proud. Our thanks also go to our

shareholders, whose continued support of Northern has encouraged us in the delivery of these excellent results.

I have great confidence as we advance through 2012 about our prospects and believe that Northern is well placed to deliver on the potential of our asset base and will reward our shareholders for their loyalty in 2011. The coming year will have its challenges, but I am expecting to be able to bring you a strong flow of good news from Guyane, The Netherlands and in Italy where we hope that the new government will help us to expedite our plans. I am convinced that we have the elements in place, including our increasingly strong cash position, which benefited from an accrual of operating cash flow to achieve our objectives.

I look forward to reporting again in twelve months time that we have made yet more progress.

R H R LathamChairman of the Board7 June 2012

Cash Reserves

Acquiring

Trade

Trade Farm out

ExploringDeveloping

Producing


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Northern’s Business Model

Adding value and the trading option

Northern generates cash from al l phases of i ts business cycle; farm-outs, trading after asset-enhancing exploration and development and from production.


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Acquiring

The Northern strategy for acquisition is that our entry into new projects should be at a sufficiently low price that the project may be cancelled without material detrimental effect upon the Company. In an industry where there are more dry holes or failures than successes, this improves the qual i ty of our management of financial risk.

• Our licences offshore Italy fall within this concept. Applications are allowed at anytime, so we were able to act as soon as exploration ideas matured, thereby taking the initiative over any competitors. From 2003 to 2010 we la id down world class exploration assets offshore to the West of Sicily, which were farmed out to Shell, and in the Southern Adriatic Sea.

• The interest in Guyane Maritime permit was also acquired then at low cost. In the Netherlands, the low cost of the Utrecht exploration licence covers the cost of a high quality shale oil play.

• Northern is currently concentrating its endeavours on its existing high impact areas that have little or no historic costs attached to them. Our targeting may need in future to be adapted as the rising oil price has brought higher licence prices.

Developing

Northern deploys a team with considerable experience and which have developed four new gas fields. This is key when seeking new opportunities in low risk countries where growth prospects and reserve base meet our criteria.

• An excellent example was our low-cost investment in Spain’s Ayoluengo oil field (for which we paid only the value of a work-over rig and vehicles). Finding it difficult to mobilise our junior partners to develop the field, in 2005 we sold our interest and refocused our efforts on The Netherlands.

• In The Netherlands we were able to acquire five discoveries from NAM at no cost, although there were commitments to drilling several exploratory farmin wells. After this acquisition we were able to sell on a quarter of our position, plus the Papekop licence, for a substantial profit which more than covered our exploration commitments.

Exploring

Northern occupies a well-defined n i c h e , e x p l o r i n g r e g i o n s predominant ly wi th proven petroleum systems and of low political risk, where business is transparent and which offer the growth potential to attract strong partners so that we can generate profit from trading or development.

• Securing such explorat ion opportunities is becoming more difficult as higher energy prices are pushing up the cost of licences. However, our management’s experience and our history of working with long-term industry partners and local authorities combine to place us well.

• Guyane has been a major exploration success. It has taken time to justify our confidence that this exploration would prove a new oil province. As is typical we are exploring with strong partners.

• Our size means we can work economically and enables the first phase cost to be kept low whilst a c q u i r i n g d a t a t h a t w i l l subsequently attract strong partners to cover the costs of f u r t h e r e x p l o r a t i o n a n d development as with Shell and Orca.

Producing

Northern’s production continues on an underlying growth trend, although the numbers fluctuate from year to year. In 2011 we produced less than anticipated in 2010 but the figures greatly exceeded those of previous years. New wells at Geesbrug and elsewhere will now provide the increase.

• Applying our technical skills we are able to continue to extract from our licence areas using the latest methods, thanks to the experience and knowledge of our production team.

• Northern has proven that in taking fields from major operators we can successfully extend field life beyond the previously predicted abandonment date. Reappraising field operations and commercial arrangements has been key to improving performance and gaining considerable uplift in value from that paid for the asset. The Waalwijk field continues to outperform annually compared to budget through a continuous programme of optimisation by the field operations team.

• A theme of all our production operations is our maintenance of the highest health and safety standards and respect for the environment.

Trading

In Northern, trading is a core activity. To understand this is at the heart of understanding our full-cycle business model, the key of which is protection of shareholders’ capital.

• Trading is vital to minimise calls on shareholders for new funding. Trading for an early realisation of added asset value is a tool to balance the sometimes slow pace of project approvals in core areas of operations when the proceeds are recycled to enhance returns.

• Our business model assumes confidence that the Northern management team have highly competitive skills in new project generation and the seizure of opportunities. The team must be adept at selling-on assets. This is important as at the time of acquisition, our requirement being that we must identify possible early exit routes.

Northern’s Business Modelcontinued


Corporate

Governance

Accounts

Key Performance Indicators are used to measure our performance on a regular basis against our targets in the areas of growth through exploration, development and production, maintaining our financial strength and safe and responsible operations in order to continue to create value for shareholders.

Delivering on our Strategy

• Aim to acquire assets at low cost

• Identify opportunities where our skills will enable us to unlock previously unexploited potential

• Use the long experience of our team to ensure that we maintain a focused and disciplined approach to the acquisition process to maximise results

• Manage our portfolio of assets on a basis that optimises the returns, whether from further development or via trading

• Apply judgment and timing to realising and developing maximum value from our portfolio, assessing the opportunities that can be taken at every stage in the life of our assets through sales or joint ventures

• Maintain a commitment to being a responsible member of the communities in which we operate and a contributor to the socio-economic health of the communities within which we work

• Utilise KPI’s to monitor the meeting of our objectives

2011 2010 Change:

Lost time injuries frequency rate (LTIFR) 0 1 We have improved upon our prior year result

Net 2P Reserves (mmboe) 75.55 89.45 Adjusted for production and in light of current reservoir performance

Net production (boepd) 1,585 1,205 The consequence of bringing new fields in stream in late 2010

Cash flow from operating activities (€ million) 15.0 8.8 A satisfactory increase given production and gas price increases

Operating cost (€ per boe) 9.16 11.10 The result of increased production and good management of costs

Realised Netherlands average gas price (€/nm3) 0.264 0.210 The consequence of being in a strategically positioned European gas market

Safe operationsAim: Northern is committed to operating responsibly in all parts of our business: by doing so we protect our assets, revenue streams and our reputation. Northern Petroleum considers that the health and safety of its employees, contractors and general public is fundamental to its success and believes that all incidents are preventable. In all of our activities we demand a responsible approach to health, safety and protection of the environment by never accepting performance lower than “our expectations” whilst striving for continuous improvement.

Our production baseAim: The replacement and increase of reserves is a key goal in the growth of our production potential. Reserves for each field are reviewed regularly and reported upon in the event of significant new data or a material change.

ProductionAim: We aim to achieve production in line with the annual budget and market guidance. Production is monitored regularly and reported to senior management and forecast updates are prepared regularly in the year.

Cash flow from operations Aim: We aim to ensure that our capital expenditure can be met from a strong operating cash flow. Cash flow is reported monthly with regular forecasting for longer periods to support long term planning and investment decisions.

Operating costsAim: We aim to maintain operational costs within budgeted limits. A comprehensive annual budgeting process covers all expenditure to be undertaken and is approved by the Board. Monthly reporting highlights any variance and corrective action are taken.

Realised gas prices The average unit gas price received during 2011 in the Netherlands was €0.264 per normal cubic metre. Forecasts are regularly reviewed in light of the monthly prices received.

Northern’s strategy has been developed to increase shareholder value and overcome the duration of downturns.

Northern Petroleum Plc Annual Report and Accounts 201110

Corporate

Governance

Accounts

La ToscaLa Tosca – Early low cost entry, low risk and the financial exposure limited.The Savio and Longastrino permits were obtained to build a ground floor entry gas exploration position in the productive Italian Po Valley basin. Seismic data, an expensive item in Italy, acquired from Eni and was paid for under a farm-out agreement with Stratic Energy Plc. Stratic subsequently did not drill and their earned interest reverted to Northern. Part of the permit interests were then farmed out to Avobone to cover part of the cost of the Savio exploration well.

In 2009, Northern, at no cost, received from Eni new 3D seismic coverage over the southern part of the Longastrino permit acquired in support for their nearby gas storage project on the Alfonsine field. This enabled re-mapping and upgrading of the La Tosca prospect. In 2010 Northern farmed this out to Orca Exploration on the basis that that they will acquire up to a 75% interest in the Longastrino permit in return for paying for drilling and testing of the well planned to commence in August 2012.

Northern Petroleum Plc Annual Report and Accounts 2011 11

Corporate

Governance

Accounts

Geesbrug Gas FieldNorthern’s strategy at the Geesbrug Gas Field: low cost traded for enhanced value and placed into production.Geesbrug, the largest of the fields received from NAM in 2005, was acquired without cost. Northern sold 25% of its interest in the field to cover much of its share of the development costs. The field was connected by pipeline to existing nearby gas facilities. A low project cost was achieved by our highly experienced team. The pipeline was re-routed to protect archaeological discoveries in accordance with our ethical environmental standards.

Initial production from the field and gas delivery rates and pressures have been monitored and used to plan the new development wells. The 3D seismic coverage over the field is being reprocessed prior to re-mapping to enable new reservoir assessments to be made before the trajectories of additional wells are decided. Careful planning will keep costs low and reduce the time expended to obtain planning permissions. For the next two wells, this will be achieved through re-using existing well sites to minimise delays and allow us to accord with our environmental ethics.

Corporate

Governance

Accounts

Northern Petroleum Plc Annual Report and Accounts 201112

Waalwijk Gas FieldNorthern’s strategy in the Waalwijk Gas Field: Low entry cost and early value realisation from partial sale.Northern analysed that with only about two remaining years of planned productive life the gas field could be purchased from Wintershall at a low price. The field came with an underground gas storage project that within a short timeframe Northern sold at several multiples of the acquisition cost to a previously analysed potential buyer. Northern also negotiated a higher sales price for the liquid by-products production.

The highly experienced Waalwijk field operations team accepted a transfer to Northern and they have under Northern’s guidance and at minimal cost devised and implemented a number of cost reductions, extended the life of the field and reduced the decline in production rates.

The field compression equipment has now been re-configured and will further extend the field life. They now also play a vital role in remotely managing four other gas fields from the Waalwijk control room.


Corporate

Governance

Accounts

The Context of our Operations

CurrenciesCurrencies were buffeted in 2011 by a wide range of dramatic events; the continuing Eurozone debt crisis to US polit ical gridlock, Japanese disasters, inflation and monetary tightening in Asia. Although the Euro declined by three per cent against the dollar over the course of 2011 – beginning at around US$1.33 and closing at around US$1.29, there was considerable volatility as European policy makers failed to conceive or implement a comprehensive solution to the crisis. The US dollar appears to have held its place as the world’s major “safe haven” currency as the US economy improved despite the downside risks caused by the pre-election impasse blocking decisions on budgets, debts and taxes. The UK faced fewer problems than its European partners and Sterling rose around 2.5 percent against the Euro over the year as investors bought UK government bonds as an alternative to Eurozone debt. Helped by its retention of Triple-A credit status and by decent year-end economic data, Sterling rose in 2011 by 0.4 per cent against the dollar.

1.061.081.101.121.141.161.181.201.22

DNOSAJJMAMFJ

1.20

1.25

1.30

1.35

1.40

1.45

1.50

DNOSAJJMAMFJ

Historic Currency Rates 2011

British Pounds Sterling/Euros

Euros/US Dollars

Oil prices Brent oil prices were up by about 16 per cent in 2011. Markets are now watching for developments in Europe’s financial crisis in order to make judgments on potential future demand. On the supply side, geo-political events were seen as driving the direction of prices, notably the situation in Iran and potential US and European sanctions on the country. However in early 2012 some economists considered the later price increases to have been led by demand. The Organization of Petroleum Exporting Countries (OPEC) has now trimmed its forecasts for oil demand in 2012 and warns that it may cut its demand outlook should the global economy continue to stagnate. Still, oil demand is expected to rise by 900,000 barrels a day this year from its figure for 2011 daily global consumption of an average of 87.8 million barrels.

US Dollars

80

100

120

140

AMFJDNOSAJJMAMFJ

Brent oil prices 2011/12Price in US$

European gas marketsEuropean gas demand is forecast by the Commission in its “The Energy Roadmap 2050” to rise over the coming years. Gas represents the default solution for an energy system committed to less greenhouse gas emission and as great value to back-up intermittent renewable power generation. Last year in Europe there was an abundance of gas due to the expansion of US shale gas output, the economic crisis and the mild winter. European gas prices fell in most countries. However, looking forward at the markets individually, Germany’s decision to close nuclear facilities is encouraging for gas producers, although consumption is expected to be restricted by the ambitious policies on energy efficiency. In the UK imports will increase massively because of the projected sharp decrease in national production. Gas is expected by the Commission to remain a key component in Italy’s energy mix as it too has excluded the nuclear option. Prices in Italy remain among the highest in Europe and given the dependence on Russian imports (40%) Italy is expected to encourage new sources of production.

20.521.021.522.022.523.023.524.024.5

DNOSAJJMAMFJ

52

54

56

58

60

62

DNOSAJJMAMFJ

TTF Gas Prices – 2011 Monthly Averages(EUR/mwh)

NBP Gas Prices – 2011 Monthly Averages(GBp/therm)

In 2011 the global economic recovery was slow and uneven, with strongly predicted risks of sovereign default. These fears have buffeted the Euro zone. Emerging economies demonstrated some recovery and supported world energy markets, a trend continuing into 2012.


Corporate

Governance

Accounts

Asset ShortageAt a time when it is increasingly difficult to build a valuable portfolio of tradable assets in low-risk areas, the early deployment of Northern’s strategy is paying off. Key to Northern’s success is its front-running in recognising future value in low-risk hydrocarbon basins ahead of competitors, in both existing and frontier territory. Evidence for this are the licences it obtained at economic costs for core positions in low-risk countries where the prospects are now recognised as exciting. Thus it is now well-placed, with a comprehensive portfolio of licences secured early in the cycle, and is able to offer partnerships in a wide range of opportunities with realisable value. A good example of this is Guyane, where Northern was an early partner in the offshore Guyane licence, only later recognised by Shell, Total and Tullow to be an exciting opportunity. It has now been proven to be a new petroleum province. The prospect facing the industry is a future of dependency on areas of geological and political uncertainty, environmental difficulties and high cost development. The interest in developing unconventional resources has been a response to this shortage, and to improving technology and rising prices. Northern has secured a European project portfolio.

Shale oil and gasAt a time when the European Union is eager to embrace a low-carbon economy, there would seem to be enormous potential for unconventional energy developments. The view is that with rising fuel prices, concern about reliance on Russian gas and the nuclear option, shale may be seen by the Commission as making sense for Europe. The path to unleashing Europe’s volumes will not be easy, not least because of the probably unwarranted fear that pollution and geological instability will be the result of shale drilling and completion. More recently the pro-lobby seems to be making progress. France is revisiting the debate and the new President, Francois Hollande, has indicated a policy shift from the party’s previous unequivocal opposition. The UK government has said that it believes shale gas fits into the country’s potential energy mix. The Dutch parliament has asked the energy minister to examine the environmental issues related to shale oil and gas. Italy is in favour, seeing shale gas as a way to reduce the need for imports, hence lowering prices and improving its economy.

The Context of our Operationscontinued

The fracking process

Shale

Fissures

Sandparticles

Wellturnshorizontal

2

3

4 Fracking fluid made from water, sand and chemicals injected at high pressure into a well up to 3,000 metres deep

Pressurised mixture causes natural fissures and layers in rock to crack

1

2

1

Sand particleshold fissures in shale open allowing natural gas to flow up the well

3 Gas is separated into ‘dry gas’ for power generation and industrial uses, and ‘natural gas liquids’ used as chemical feedstocks

4 Fracking fluid recoveredand taken for reprocessing

5

5

From the Financial Times © The Financial Times Limited 2012. All Rights Reserved.


Corporate

Governance

Accounts

Operation locations

Production

Key features

Key priorities Key priorities

Key features

Exploration

The Group at a Glance

Northern continues to build and expand its portfolio of producing assets, executing incremental development and realising gains as a full cycle oil and gas group to invest in future growth. We have a clearly defined and consistent strategy and a long-term perspective on how we grow our business. We protect our reputation, manage our business carefully, invest in people and partnerships and exercise prudence in managing and mitigating the risks.

United Kingdom:

We have built a useful and tradable portfolio of performing assets and are ready to realise its value.

To commercialise and expand our resource base and fast-track production growth.

To deliver participation in a world-class quality prospects in a new petroleum basin.

To build a producing and tradable asset portfolio at low cost.

To realise the value of our vast Italian potential.* On completion of the agreement with Azimuth,

Northern’s net Probable Reserves will be 45.2 million boe

Italy:

We have potential high-impact exploration prospects in four core areas.

The Netherlands:

The 31% per cent rise in production in 2011 came largely from our six producing Netherlands gas fields.

Guyane:

We have a game-changing stake in a world-class oil discovery off-shore Guyane.

The Netherlands GuyaneUnited Kingdom Italy

18.0 million boe of net 2P reserves

10 licences

Zaedyus oil discovery

1 licence

4.3 million barrels of net 2P reserves

9 licences

53.2 million barrels* of net 2P reserves

13 licences and

20 applications


Corporate

Governance

Accounts

Review of Operations The Netherlands

Overview

Net proven and probable reserves: Gas 80.27 billion cubic feet; Oil 4.20 million barrels

6 gas fields in production

1 oil field extended well test

1 oil field awaiting development drilling

2 further development wells 2012/13

Partners

Strategy

The Netherlands is both a current source of production income and a valuable and growing portfolio of opportunities for future revenues. We are applying our strengths in two key areas to fully exploit this asset base.

The first is our strong established partnerships and relationships within the energy industry and excellent standing with the authorities there.

The second is our considerable international technical expertise on how to maximise production from our established fields and develop additional prospects for drilling.

We have built a good acreage position in two core areas and are seeking to acquire more. We currently have six gas fields on-stream and have performed an extended production test on one oil field. We have under licence considerable shale oil potential.

To improve both the performance of NPN and that of the industry we are engaging with the government as a catalyst for change to the administrative procedures that have previously delayed our progress on field developments.

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. Dyas B.V. interest sold to The Parkmead Group Plc, subject to completion.

Energie 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.

Reserves by region

The Netherlands

Germany

P12

Papekop

Oosterwolde (Haazen)

Andel V (Brakel, Ottoland & Wijk en Aalburg)

Zuid Friesland III (Oppenhuizen, Woudsend)

Drenthe III (Lhee, Lhee North, Boterveen)

BelgiumWaalwijk

Drenthe III (Geesbrug)

Drenthe IV (Grolloo)

Engelen (Kerkwijk South)

Utrecht (Vlist, Willeskop,

Everdingen South, Kerkwijk)

ProductionTesting on developmentExploration


Corporate

Governance

Accounts

Creating value in 2011

The current phase of our plan

Grolloo and Geesbrug: These fields show the realisation of value from five years of focused geotechnical, engineering and operational efforts in the development work. Both the Grolloo and Geesbrug gas fields first came on stream in 2009. The gas from both these fields is being transported via dedicated pipelines to processing facilities operated by NAM (the joint Shell / ExxonMobil company, Nederlandse Aardolie Maatschappij) the country’s largest producer of natural gas and oil.

Gas production was originally enhanced by a successful programme of hydraulic fracturing of the reservoirs which reflects the high level of skills of Northern’s technical team. This new production is an important factor in Northern’s progression towards an increasing production base. It is making a positive impact on Northern’s cash flow and enables the Group to increase the pace of development on other prospects in The Netherlands and elsewhere.

On Geesbrug, preparation is being made for an additional well which we plan to drill late in the second half of 2012 with a third well in early 2013 in order to increase production.

Wijk en Aalburg and Brakel: Following successful completion of the first stage of the development projects at Geesbrug and Grolloo, Northern has installed its own independent gas processing plants at the Wijk en Aalburg and Brakel gas fields which export via dedicated pipelines into the gas network.

Ottoland and Papekop: The development of the oil fields at Ottoland and Papekop will proceed as the next stage of enhancing production.

At Ottoland we completed an extended well test of the oil discovery from the horizontal sidetrack drilled in 2007 and hydraulically fractured in 2009. Permission was received to conduct the test using a “jet pump” to assist the flow of oil. Northern’s analysis of the test results will provide a determination of predictable oil and gas production rates. Production facilities can then be designed to meet the potential for both oil and associated gas. At the same time, work will also be undertaken on an oil marketing plan.

Progress and priorities

Our objectives

To commercialise and expand our resource base and fast-track production growth.

What we delivered in 2011

Northern made considerable progress in the Netherlands. The Group’s 31 per cent rise in production in 2011 came from our six producing Netherlands gas fields. Additional cash revenues are being generated from the four new operated fields now on production and these will provide the funding for future development and exploration work.

We also extended our understanding of the geology and succeeded in expediting progress on exploration and the design, approval and enhancement of field developments.

As part of our preparation for a programme to boost production in 2012, we have expanded our operational and management capacity. This enhancement of our technical skills will help us to unlock unexploited potential across our fields in the Netherlands.

Another important and extremely exciting move has been assessment of a very promising potential shale oil project in the West Netherlands Basin.

The progress we have made in 2011 year compensates for the disappointment of the adjustments to reserve estimates for Geesbrug, Grolloo and Wijk en Aalburg we announced during 2011. These downgrades were made in the interest of prudence and will be re-assessed when fuller data become available.


Corporate

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Accounts

Review of Operations The Netherlandscontinued

Waalwijk and P12: In the Waalwijk and P12 fields further improvements to operations have also been made, extending the life of the fields. At Waalwijk modifications to compressor configuration will shortly go into operation. This will allow a further two years of economic operation of a field that was originally scheduled for abandonment in 2008. This extension has added benefit to Northern because it also serves as the remote operating control centre for four of the new fields now on production.

The Oosterwolde Exploration Licence has been mapped and integrated into Northern’s subsurface evaluation. Northern’s mapping has identified a low risk exploration prospect with potential to contain significant gas volumes. Additional geological and geophysical work is being undertaken to mitigate the exploration risk ahead of a drilling programme.

Sale of Interest in Vinkega Gas Field Northern’s interest in the Vinkega gas field was sold for €3.2 million to Vermilion Oil & Gas Netherlands B.V. (“Vermilion”). This field had been mapped as underlying both part of Vermilion’s Gorredijk Licence and part of our Drenthe III Licence.

This will make a useful financial contribution to our hopefully successful exploration activities on the Drenthe III licence in the near future.

West Netherlands Basin: A study undertaken by US consultants NuTech Energy Alliance into the potential of a shale oil resource present across the areas of our licenses shows highly encouraging results. While there remains considerably uncertainty as to the recovery rates, and more work is needed to assess the shale’s commercial potential, NuTech advise us that the gross resource of oil in place potential is estimated to be 20-30 billion barrels. In their view there is greater productivity potential than in such formations in Canada and even the US, where shale oil drilling has helped reverse a decades-old decline in crude output.

2012 and our long-term programme

Well intervention and the benefits of fuller data on our fields are helping design future development options for production. We are able to plan for production increases through additional development wells and sidetracks of existing development wells.

To counter the natural decline in production for our existing wells and to increase production across our Netherlands licences we plan a programme of intervention. This includes installing compression, lifting assistance and possible re-perforation or sidetracks. Subject to official approvals of this work programme, we anticipate that the effects will begin to show results towards the end of the second half of the year.

The next stage of adding to production will be infill drilling on existing fields, developing discoveries in the portfolio that resulted from a technical reappraisal of the well results and a large programme of reprocessing of 2D and 3D seismic data utilising a larger database of information.

Ottoland: Data from the 2011 long-term test is being examined for development.

Geesbrug: After a second phase of development, Geesbrug is moving foward with a new production well planned for late in the second half of this year, with a further well planned for early 2013.


Corporate

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Review of Operations United Kingdom

Overview

Net 2P reserves: 4.35 million barrels9 licences

1 further offshore application

Partners

Strategy

Northern’s strategy has been to build a portfolio of licences with a dominant position in the southwest area of the Weald Basin of Southern England, which contains ten oil fields. The primary reservoir objective is the Great Oolite carbonate and Northern has interests in the Horndean and Avington fields, which both produce oil of excellent quality from the Great Oolite. These fields were obtained at low-cost and production has been providing a stable level of economic cash flow, which should continue for a numbers of years.

However, as industry interest in the area is growing, as the industry benefits from UK government policy, we are considering whether the value created within the portfolio should be realised and better utilised elsewhere. This is in line with Northern’s well developed strategy and strong track record of building value then realising it to redeploy cash and resources where even greater shareholder value can be created.

The government is keen to ensure Britain’s remaining oil and gas reserves are tapped and it has unveiled plans to boost investment in the North Sea and other UK prospects. This is against a background of falling domestic production and rising imports and energy costs. UK oil output peaked at more than 2.7 million bopd in 1999 and has been on a downward trend since 2000. As well as a drop of 17 per cent in oil output, the figures showed production of natural gas in 2011 fell even more sharply, declining by 20.8 percent. As a result, gross imports of natural gas were greater than gross production for the first time since 1967.

Egdon ResourcesAIM-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 240 and P1916.

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.

Star Energy Group plc Previously a wholly owned subsidiary of Petronas, recently purchased by IGas Energy Plc in December 2011.

Reserves by region

UK

PEDL 240

PEDL 069

PEDL 256

PEDL 155

PEDL 126

PEDL 233

PL211 (Horndean Oilfield)

Production / developmentExploration

P1916

PEDL 070


Corporate

Governance

Accounts


Our objectives

To build a portfolio of producing and strategically placed assets at low cost.

Delivered

We have two producing UK fields, undeveloped discoveries and a number of exploration possibilities – an attractive portfolio of assets. They are sited in an area in which the government is encouraging production.

We continued to enhance the value of our UK licences, conducting an extended test of the Markwells Wood-1 discovery by utilising an innovative linear reciprocating pump in order to assess the reserve potential of the discovery. Encouraging news came from our focus on the Wessex Basin on the Isle of Wight where we have one onshore licence and one offshore licence. We have mapped a prospect that is considered primarily prospective for gas and as the evaluation of potential drilling sites for this prospect continues it may be added to a future drilling programme.

Review of Operations United Kingdomcontinued



Horndean and Avington: We continued to receive revenue from our interests in the Horndean (10 per cent) and Avington (five per cent) fields, which are operated by IGas Energy.

Markwells Wood: This area was recognised as a possible extension of the Horndean oil field and encouraging confirmation came from drilling indicating that the entire Great Oolite reservoir sequence in Markwells Wood-1 is oil bearing above the Horndean Field oil water contact. The well has undergone flow test operations in order to confirm its commercial viability for field development. We have drawn up plans, in the event that evaluation justifies this, to seek consent for the installation of low-cost production facilities.

Baxters Copse: we are working with Providence Resources for the drilling of this discovery, potentially from the Singleton oil field production site. If successful the well could be placed on production rapidly using the existing production facilities.

Blocks 98/13 and 98/14, adjacent to our Isle of Wight licence: Award of a long awaited licence P1916 for parts of Blocks 98/13 and 98/14 came in the 26th Licensing Round. The new licence is located offshore adjacent to Northern’s Isle of Wight onshore licence, PEDL 240, awarded in May 2008. The part blocks 98/13 and 98/14 cover the offshore extension from PEDL 240 of a prospect that has been mapped prior to 2008 using both seismic and well data and is located in the same petroleum basin as the Wytch Farm oil field.


We will be holding discussions with various interested parties to see if the value created within the portfolio can be realised and bring better value to shareholders if utilised elsewhere. However, we will be continuing our programme of enhancing our UK assets by development and securing new licences.

Horndean and Avington: We expect to continue to receive ongoing revenues from these fields which continue to show a slow decline in production. Our forecast share of production from Horndean and Avington for 2012 is put at 17 bopd.

Wessex Basin: Northern holds two licences extending from the Isle of Wight to the offshore. These licences cover a large prospect that has been mapped from seismic; Northern hopes to engage in planning permission discussions to secure a surface location from which the prospect can be drilled.


Corporate

Governance

Accounts

Partners

ShellThrough its French subsidiary, Shell France.

TotalThe fifth largest publicly-traded integrated international oil and gas company and a world-class chemicals manufacturer, Total operates in more than 130 countries and has 92,855 employees.

TullowA FTSE 100 organisation that is one of the leading global independent exploration and production companies with a focus on Africa and South America.

Strategy

Guyane has been a great success story for Northern, a strategic move that has really come up trumps. We are working with major companies as long-term partners in a country of low risk being a Department of France.

We spent a relatively small amount of money and took a 1.25 percent interest in the licence, held through our 50 percent holding in Northpet Investments. We have modest financial exposure, and have won a part in a play that offers disproportionately high exploration potential.

OverviewExploration phase Guyane Maritime Licence (Northern 1.25% net beneficial interest)

Review of Operations Guyane

Exploration

Guyane GM-ES-1

Brazil

Guyane

Suriname

Guyane Maritime

Guyana

North Atlantic Ocean


Corporate

Governance

Accounts


Our objectives

To deliver to shareholders participation in world-class exploration play at relatively low cost and risk.

Delivered in 2011

Northern has proved a highly valuable stake in an extremely exciting new world-class oil frontier off the northeast coast of South America, discovered by the successful drilling of the Zaedyus exploration well offshore Guyane. The P10 estimate by Tullow Oil for the discoveries gross reserves has been increased to 840 million barrels of oil, up from last September’s forecast of 700 million barrels when the discovery was announced. The partners in this project, Royal Dutch Shell Plc and Tullow Oil plc along with Total SA and Northpet Investments, spent more than $250 million last year drilling to achieve this discovery.

This could be just the start, as the Zaedyus well encountered oil in a fan system similar to that found along the West African coast, in Tullow’s Jubilee field offshore Ghana. There are good expectations that the Ghana success can be replicated or improved upon. There is much to play for, with the scale of the remaining prospects likely to match current upper estimates for Zaedyus. Many other fans have been mapped within the basin and the licence.

Our net 1.25% interest may seem small but it is corporately significant considering the very considerable potential target sizes. Both exploration and eventual development costs due from us are considered well within our financing capabilities.

Review of Operations Guyanecontinued


There should be good positive news flow throughout 2012 as the joint venture group is now planning an aggressive exploration and appraisal programme. Shell, as operator, has secured a drillship to commence operations in midyear and continue through to 2013 and beyond. The first well will appraise the discovery made by Zaedyus-1 and explore for deeper objectives, followed by an exploration wildcat well.

Planning is also on-going to acquire two large 3D seismic surveys; these are a 4700 sq. km Eastern Slope survey and a 620 sq. km Cebus survey either side of the Cingulata fan system containing Zaedyus and other mapped turbidite fans.


Corporate

Governance

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Review of Operations Italy

Overview

Net 2P oil reserves: 53.16 million barrels13 licences

20 applications

Strategy

In Italy Northern now has an asset base that epitomises our key growth strategies. We have built and are still expanding a portfolio of highly valuable exploration permits to develop as attractive farm-ins for large industry players. Our potential for achieving superior shareholder value is huge as our permit and application area ranks after only that owned by Eni, the Italian state-controlled energy company.

We were a front-runner in recognising the potential of Italy as a base on which to build a company. While our rate of progress is very much slower than we would like, we have assets farmed out at different stages. We have already been successful in attracting one major player, with Shell Italia taking an interest in six of our licences. We expect to attract others to the three core areas we have still to trade as the new government in Italy eases the bureaucratic hurdles.

The geology of Italy is highly complex but has enabled the formation of large and extensive hydrocarbon fields, within numerous oil provinces that are important, even though their areal extent is not great. Our licences are well distributed in core areas through the most important Italian provinces, the Southern Area of the Adriatic, the Ionian Sea, offshore Sicily Channel and also in the Po Valley.

The opportunity for us is tremendously exciting as the country currently produces only nine per cent of its oil and gas requirements and voters have rejected the nuclear option. Italy has suffered a succession of winters with energy crises, as it is heavily reliant on gas supplies from Gazprom. Our view is that the new government policies will not only have a material impact on investment flows but will enhance the attraction of the farm-in opportunities we are offering.

Partners

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

Orca Exploration Group IncA Canadian exploration and production group.

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

Reserves by region

Italy

Exploration

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

Longastrino

Savio

CascinaAlberto

Punta Marina

La Sacca


Corporate

Governance

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Our objectives

To continue to push forward on our priority objective of realising our vast Italian potential on a basis that will deliver value to our shareholders.

Delivered

We kept up the pace, albeit not fast given Italy’s environmental concerns, regulations and legislative processes, of obtaining the data we need for successful future drilling programmes and to derisk our exploration potential. This was against the background of increasing hope that a new government would take a more encouraging stance to expediting exploration – and our view seems to be justified.

The priority in 2011 was to concentrate on our highly valuable Italian assets in the Southern Adriatic, which hosts the Giove and Rovesti discoveries. We agreed a farm-out of 15 percent of the permits which contain the Giove and Rovesti discoveries with Azimuth, a global specialist in exploration and development, to speed up work on delineating suitable appraisal and exploration drilling targets.

We also continued to seek new licences in key promising areas of Italy to expand our asset base and have applications pending that will enhance the portfolio within our core areas.



There were a growing number of signs that gave us encouragement that we shall be able to move more quickly in 2012. We can see from our close contact with the Italian authorities that the country’s energy policy is shifting on all fronts. Italy’s government is seeking to calm public protests over high energy prices through announcing higher domestic hydrocarbon production and reduced subsidies for renewable energy. The plan is to double domestic production of oil and gas. Then, speaking at a conference in March this year, Industry Ministry Undersecretary Claudio De Vincenti told delegates that “relaunching national hydrocarbons output is one of the four main pillars of the new energy plan”.

While there was good news in 2011 that there was no impact on our reported net 2P reserves of 53.2 million boe in Italy from the 2010 Italian environmental law placing tighter restrictions on near shore oil and gas exploration, we welcome signs that this law could be amended as part of the government’s proposed Quarto Conto Energia (the “Fourth Energy Bill”).

Southern Adriatic: A 600km 2D seismic survey was acquired in November 2011 in permits F.R39.NP and F.R40.NP to add additional coverage of the Rovesti field and exploration targets including Cygnus, a large basin margin fan system up dip of the Aquila field operated by Eni. Northern signed an agreement with Azimuth, a specialist global E&P company 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

Review of Operations Italycontinued

agreement is to work with Azimuth to define and delineate suitable appraisal and exploration drilling targets. Azimuth will become a 15 percent interest partner in both permits by funding a promoted share of future work programmes prior to the drilling phase.

Giove and Rovesti oil fields: these have previously been independently assessed by Blackwatch Petroleum Services to have 53.2 million barrels of net 2P oil reserves. In addition, as a result of work undertaken to date, Northern recognises the potential both for oil prospects with a mean of over 3 billion barrels of oil in place and gas prospects with a mean of over 2 Tcf of gas in place, which is over 1 billion barrels oil equivalent of prospective resource, in the two permits and split approximately equally between oil and gas prospects. Our confidence in these fields has been reinforced by the moves by Eni to redevelop the neighbouring Aquila field, which produced approximated 24 million barrels of oil over eight years.

Po Valley: preparations for the drilling of the La Tosca prospect in the onshore Po Valley Longastrino licence were made. At its closest the prospect is less than 2 km from the large Alfonsine gas field and well defined by a recent 3D seismic survey. Orca Exploration is our farm-in partner in the well and will be paying all costs to the budgeted level for our 25 per cent retained interest in this 43 bcf prospect.

West of Sicily Thrust and Fold Belt: Shell Italia, our partner, has taken over the role as the representative before government for six permits offshore west of Sicily; G.R17.NP, G.R18.NP, G.R19.NP, G.R20.NP, G.R21.NP and G.R22.NP. This move was initiated to progress work required to apply for drilling approvals in advance of the final decision as to whether an exploration well was to be drilled in the permits. We have recognised that Shell is not undertaking to drill a well and we are in discussion with prospective new partners whilst undertaking measures to extend our permits.

Sicily Channel areas: Work was on-going to seek partners with whom we will be able to progress exploration and development of these areas.

Ionian Sea: This area was only recently opened for exploration and applications have been submitted. The area contains the extension of the geology of the prolific onshore Val d’Agri oil province and has the potential to be a significant future resource.


Sicily Channel: Progress in Italy, where our prospects are so exciting, is a priority. Our objective remains to enter into agreements to bring new partners into the Sicily Channel areas.

Southern Adriatic: A 3D seismic survey is planned in 2012 in the Southern Adriatic, although timing will depend on the necessary approvals from all the relevant authorities. The survey will be designed to define drillable appraisal targets for the Rovesti and Giove fields as well as exploration targets including the large Cygnus prospect.

La Tosca: Preparations are underway for the drilling of the 43 Bcf La Tosca prospect, which neighbours the large Alfonsine gas field and is well-defined by a recent 3D seismic survey. Orca Exploration is our farm-in partner in the well and they will be paying all associated costs to the budgeted level.


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Embracing Social Responsibility is a fundamental requirement for all Northern staff. Being socially responsible is a key and basic component of our business and its achievements. This includes, not only adherence to government legislation and company policies, but must extend to acceptance that the Company is, in all its projects, a new “neighbour” in established communities and environments. Like Safety in the Work Site, this requires establishing a belief and commitment in our personnel in addition to building good organisational procedures.

EnvironmentNorthern accepts all local and government environmental legislation and seeks to improve upon it. The Company works to identify risks to the environment and to implement procedures to avoid or mitigate these. The protection of the environment must be given highest priority. All of us are part of the same community, enjoying the same environment.

Close attention is paid to the prevention and control of pollution, control of all waste generated, maintenance and the repair of facilities, testing equipment and our rules exceed governing regulations. Any unintentional discharges are promptly contained, reported and dealt with.

Northern, as a good responsible neighbour, goes beyond that which is officially required. For example, before undertaking the approved clearing of the area of the well site at Markwells Wood, a visit to the site by a leading expert from The Royal Botanical Society (Kew) was arranged. For the Company’s own compliance standards, this provided confirmation that our planned operations would not a be in Ancient Woodland or effect Ancient Soil that could contain 400 year old seeds that we could move to save. Only after these checks drew a blank were instructions given for the careful removal and storage of soil taken from the site.

Health and SafetyAs Health and Safety is a core priority for the Company, Northern employees are trained to focus on teamwork, communication and having the highest regard for Health and Safety procedures. Performance reviews are undertaken annually alongside risk assessment reviews. In 2011 we celebrated 10 years without a lost-time incident at the Waalwijk gas production facility in The Netherlands. This significant milestone was achieved because of the commitment and dedication of all Northern personnel and contractors.

CommunityNorthern and its operations are part of the community. This understanding governs our thoughts and actions. Northern is committed to being good, responsible neighbours providing transparency and open communications wherever we operate.

Public consultations are held to aid and improve our operations and enable us to minimise disruption to local schools, businesses, residents and other impacts. Having the informed support of the community is at the forefront of our ongoing and future operations.

PeopleOur strategy is simply to attract the best people and support them with the wide range of tools and resources necessary for success. Building on success remains a key priority for the Board of Directors.

An atmosphere of high moral values and a fundamental respect for human rights, safety, and non-discrimination is required. Respect for others and commitment to knowledge is engrained within our modus operandi.

Personal development is actively pursued and training opportunities are encouraged across the Group. A culture of personal accountability and responsibility is imperative to improving workplace efficiency.

RiskThe Company adheres to strict internal risk management policies which identify, monitor and manage risks within the business. Early identification is the best tool for Northern to reduce, remove or mitigate risks. Northern assesses acceptable levels of risk associated with any operation.

Associated hazards and risks are the subject of formal Risk Assessment Procedures. Risk reduction measures are identified and undertaken before any operation commences and an emergency response plan is developed and implemented. All emergency systems are tested in advance of any operation that may require their use.

When an unplanned, operational event occurs our rules are that the operation should be made safe and suspended until such time that a forward plan can be been developed and the risks associated assessed to ensure they are acceptable.

Risk management is an integral part of each employee’s duties and rights. Any risks, lost time, injury, potential safety or environmental incidents are reported directly to managers within 24 hours and communicated to the Directors through the Health and Safety Committee in a timely manner. Updates to risk management control are communicated at each Board meeting. All staff are instructed that they can by-pass line management to report safety matters.

We have recently implemented specific internal procedures and staff training covering areas of fraud, bribery and corruption that are deemed unacceptable by law.

Corporate StatementHealth, Safety and the Environment


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Northern Petroleum is an international business which has to face and manage a variety of strategic, operational and external risks. In early 2011, primarily as an initial reaction to the Bribery Act 2010, the Board formally established a Risks and Ethics Committee which is chaired by Jerry White and includes representatives both in respect of all the countries where we operate and from across all functional disciplines. Northern undertakes regular comprehensive risk reviews and 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 2011 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 experienced operations and technical teams, 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, technical 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.

Risk Management


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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.

When negotiating material contracts, the Group ensures that the best possible balance between the parties is struck in the wording of Force Majeure and similar clauses.

Northern has access to both very competent in-house experienced professionals and, where required, external insurance and other advisers.

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 to foster and maintain successful relationships with government authorities through the adherence to the highest standards of working practices, transparency and 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 focussed and continual improvement in risk mitigation throughout the Group.

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Financial Review

In terms of reported production, revenue and gross profit it has again been a record year, reflecting the impact of a first full year of production operations at the Brakel and Wijk en Aalburg gas fields that commenced production in September and December 2010 respectively.

The Company entered 2011 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. The Group has continued to use this balance sheet to invest during 2011 across its full cycle asset base, this investment being spectacularly successful given the Zaedyus-1 discovery announced towards the end of the year. With a first full year of production operations at two fields brought on stream in late 2010, the results for 2011 do show the fruits of the Group’s investments of 2009 and 2010 in pre-production activity. Significant further capital investment was undertaken on pre-production well test activity in 2011, and is also planned in late 2012 and into 2013, predominantly on additional production wells on the largest of our gas fields, Geesbrug.

However, the income statement for the year does not totally mirror this operational progress, with the Group ultimately reporting a significantly lower profit than it might otherwise have done given a rise year on year in depletion and amortisation charges of €3.78 million. The material items given rise to this increased charge were the charge of approximately €4.38 million in respect of the accelerated depletion following the mid year reserves reduction at the Wijk en Aalburg gas field, plus the impact of a full year’s depletion in respect of the Brakel gas field, offset by the €2 million impact of the decrease in the second half in depletion charges following downward adjustments to the estimates for Dutch field abandonment costs in respect of Geesbrug, Grolloo, Brakel and Wijk en Aalburg, following comprehensive, third party, abandonment studies.

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

Results summary

Year ended31 December

2011€’000


2010€’000

Revenue 24,531 14,968Gross profit 12,117 6,697EBITDA (i) 18,251 5,083Adjusted EBITDA (ii) 18,971 6,475Profit / (loss) for the year 6,231 (1,155)

Basic earnings / (loss) per share on result for the year 6.7 € cents (1.3) € cents

Capital expenditure (iii) 9,966 13,688Cash and cash equivalents 29,794 21,430Other working capital 1,509 2,466Net assets 93,280 85,371Total Group distributable reserves 61,568 54,039

Production (million boe) 0.58 0.44

Average revenue, in currency of receipt, per boe:Gas €41.20 €32.69Oil $103.42 $73.58

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

75.55 89.45

(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.(iii) Includes increase in investment in Northpet Investments Limited ((i.e. financing Zaedyus-1 well) during the year.

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The review process of our Netherlands fields announced last year continues. All our 3D seismic coverage is being reprocessed and some initial re-interpretations are available on fast track volumes. Preliminary reservoir study results have been assessed and on balance indicate the need for downward revision. Therefore the Board has taken the prudent step to reduce its Dutch 2P reserves by 10.67 million boe, 0.43 million boe (2.51 Bscf) of which was taken at the mid year in respect of Wijk en Aalburg, comprising a net reduction of 6.43 million barrels of oil in respect of Ottoland and Papekop and 24.58 Bscf in respect of our six producing gas fields. These further revisions have led to some additional immaterial accelerated DD&A charges in respect of the other producing fields.

The results for the Group for the year ending 31 December 2011 show a profit before tax of €10.49 million compared with a loss before tax of €0.02 million for the year ended 31 December 2010. The basic earnings per share are 6.7 € cents, compared to a loss of 1.3 € cents in 2010.

The major components of the year on year increase in the pre-tax profit of €10.50 million have been:

• anincreaseof€5.42millioningrossprofit,asaresultofincreasedrevenuesmorethanoffsettingincreasesinproductioncosts,andinnon-cash charges for both depreciation and amortisation and asset impairments (even after taking into account the additional charges resulting from the impairment and accelerated DD&A charges referred to above in respect of the Wijk en Aalburg gas field);

• theoneoffprofitof€3.11millionfromthedisposaloftheVinkegagasfield;• adecreaseof€1.05millioninnetfinancecosts;and• adecreaseof€0.9millioninadministrativeexpenses.

The pre-tax profit results in a tax charge for the year of €4.26 million, principally in respect of our profitable Dutch operations, compared to a tax charge of €1.14 million for 2010.

Most of the increase of €5.42 million in gross profit can be put down to higher comparative production from two new gas fields put on stream in September and December 2010. A revised price formula was introduced for 2011 which gave greater weight to the spot gas price. Average gas prices achieved were 26% higher than in 2010.

The income statement has also benefited in the second half from reductions in DD&A charges of approximately €2 million, following downward adjustments to the estimates for Dutch field abandonment costs in respect of Geesbrug, Grolloo, Brakel and Wijk en Aalburg, following comprehensive abandonment studies, comprising sites, surface facilities, subsurface wells and pipelines, carried out by experienced external engineering consultants in late 2011.

Aoneoffprofitondisposalofassetsofapproximately€3.1millionaroseduringtheyearonthesaleofaninterestintheVinkegagasfield,whichwasdiscoveredbyVermilionandwasmappedasunderlyingbothpartoftheGorredijkLicenceandpartoftheDrentheIIILicence,operatedbyNorthern’sDutchsubsidiary,NorthernPetroleumNederlandB.V.(“NPN”).SeventypercentofthepurchasepricewaspaidtoNPN on signing of the Sale and Purchase Agreement in December 2011, with the remaining thirty percent being paid in May 2012 following completion. It should be noted that the retention of the sale proceeds is contingent on NPN earning its share of the Drenthe III exploration licence under the terms of the agreement with NAM signed August 2005 by drilling a second exploration well on the permit.

After adjusting for the effect of the accelerated DD&A charges referred to above in respect of the Wijk en Aalburg gas field, and the one offprofitondisposalofVinkega,theoverallresultfortheyearisinlinewithbudgetwiththeeffectofhigherthananticipatedgaspricescompensating for the reduced production guidance as announced on 27 May 2011.

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 €10.0 million including Guyane during the year, a small decrease over 2010 when capital expenditure totalling €13.7 million was incurred across the full E&P cycle.

Production ActualproductionnettoNorthernwas0.58millionbarrelsofoilequivalent(“boe”),comprising3.21bcfofgas(2010–2.44bcf),19,481barrels of gas condensate (2010 – 7,975 barrels) and 6,602 barrels of oil (2010 – 7,062 barrels), with an average price received for gas and oil during 2011 of €41.20 per boe (2010 – €32.69 per boe) and US$103.42 per barrel (2010 – US$ 73.58 per barrel) respectively.

Gas production from the P12 and Waalwijk operations decreased by 23% (2010 – decreased by 29.3%), but overall production was enhanced by a full year of 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 6% (2010 – decreased by 15.4%), with Avington production increasing by 2.8% compared to a 8.3% decline seen at Horndean. Horndean especially, with its low operating costs, and despite the production decline, remains highly profitable and a useful contributor to cashflow. Avington generated a small profit for the Group despite its modest production.

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Accounting Policies These financial statements have been prepared by the Board using accounting policies consistent with 2010, 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:

• IFRS3–BusinessCombinations;

ThefollowingnewandrevisedStandardsadoptedduringtheyear,IAS1–PresentationofFinancialStatements,IAS24–RelatedPartyDisclosuresandIFRS7–FinancialInstruments:Disclosures,havesolelyresultedinchangestopresentationanddisclosurewithinthe2011financial statements.

Furtherdetailsonthesenewpoliciesareincludedwithintheaccountingpolicynotesstartingonpage51(Group)andpage85(Company).

Taxation The Group has reported a tax expense of €4.26 million for the year. This tax expense is almost entirely related to the Group’s profitable operationsinTheNetherlands,withlittlecreditbeingtakenonlossesincurredintheUKandItaly,(seenote2“Segmentalinformation”for further details).

Northern’s effective tax rate in The Netherlands is less than the usual 50% for 2011. This has arisen because of the effect of deemed CorporateIncomeTax(“CIT”)calculatedonStateProfitShare(“SPS”)arisingfromthecalculationofNetherlandsCITandSPSwherethetwo taxes are offset or deducted against each other, and also because for 2011 the Company‘s SPS loss utilisation was significantly higher than its CIT loss utilisation.

Taxable profits were offset by losses, mainly in the UK. UK and Italian losses, however, are not expected to be utilised for at least a year and with Markwells Wood not expected to go into production until 2013 at the earliest, no net deferred tax credits have been recognised in the 2011 accounts in respect of either the UK or Italy. Once Markwells Wood production has been fully established, a tax credit will be recognised in respect of the prior year UK losses then available to offset against future UK profits.

In the2010AnnualReport, theGroupnotedtheproposedfurtheramendmentsbyTheMinistryofFinanceofTheNetherlands(“TheMinistry”)totheRegulationforDepreciationAtWill2001(“DAW”).IampleasedtoreportthattheGroupnowhaselectedtofullyutiliseDAWforqualifyingcapitalexpenditurebyitsDutchsubsidiary,NorthernPetroleumNederlandB.V.(“NPN”),inboth2010and2011,beingthe second and final available period. 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 2009-2011 qualifying period. This use of DAW has therefore resulted in additional Dutch tax losses for these years, which were therefore available to be carried back in respect of profits from years prior to 2009. These elections clearly have been 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.

Whilst the introduction of DAW was designed to stimulate capital investment by Dutch companies, clearly the announcement by the British ChancellorlastyeartoincreasetherateofUKSupplementaryChargetoCorporationTax(“SCT”)willhavetheoppositeeffectonE&Pcompanies with UK assets. It is some consolation therefore that in his 2012 budget the Chancellor proposed changes that would reduce the main corporation tax rate by one percent per annum to 23% by 1 April 2014, and announced improved allowances and reliefs available for certain types of UKCS fields. Let us hope that these recent concessions help improve the UKCS investment climate. Neither of these recent changes will have any immediate detrimental effect on the Group given existing UK production levels.

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.

FormoredetailedinformationontheGroup’staxpositionshareholdersarereferredtonotes9and18.

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

Financial Reviewcontinued

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Shares and WarrantsThe net effect of the share issues during 2011 was to raise the total number of ordinary shares in issue by 1,530,715, approximately 1.7% year on year. Of that increase, 1,508,600 were in respect of warrants exercised for cash, raising a total of approximately €0.92 million, while a further 22,115 shares were issued to staff and Directors at 133.5p per share in lieu of salary payments.

At the year end there were approximately 5.98 million warrants in issue, which represented 6.4% of issued share capital and which had exercise prices in the range of 11.25p to 252p. A total of approximately 0.29 million warrants with exercise prices ranging from 69.9p to 133.75p were issued during the year to new and existing 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 23.5% (2010 – decrease of 5.6%) year on year in the number of warrants in issue.

Sinceyearendatotalof1,847,500warrantsthatwereduetoexpireon29February2012havebeenexercised,whileafurther1,125,000warrants have lapsed.

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 reasonable and appropriate security. Production levels are such that the Group, together with its reserve base, is in a position to, as and when it deems fit, enter into a reserved based lending facility.

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

AdditionaldetailsonthefinancialriskstheGroupfacesaregiveninnote23tothefinancialstatements,whichcoversIFRSdisclosureson financial instruments.

Oil And Gas Price RiskOil and gas sales revenue is subject to energy market price risk – calendar year 2011 saw a continuation of the 2010 trend of gradual, but significant, upward momentum in prices compared to the wild swings experienced during the financial crisis of 2008 and 2009. Given events in the Middle East since the turn of the year, which have continued to reinforce the emphasis given to the security of supply debate, it is not surprising that hydrocarbon prices have remained relatively robust despite the backdrop of slowing growth or even recession inmostFirstWorldcountries.

The Group’s oil and gas sales revenue in 2011 comprised oil and gas on long term supply contracts, the vast majority of which is gas sales committedtoGasTerraB.V.(Waalwijk,P12,Grolloo,Geesbrug,BrakelandWijkenAalburg).TheGrouphasasyet,anddoesnotcurrentlyplan to, enter into any hedging activities, although as production levels are further supplemented as more Netherlands’ based production comesonstreamin2013andbeyondthispositionwillcomeundermoreregularscrutiny.Formore informationseethe“FinancialInstruments”sectionbelow.

Liquidity, Credit and Interest Rate Risks Given the ongoing financial and Eurozone crises 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 cash and working capital balances totalling €31.3 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 a first full year of production operations in 2011 at Brakel and Wijk en Aalburg, as described above the Group is well positioned to, and highly likely to, expand its armoury with an appropriate level of debt when it deems fit.

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 direct and indirect capital expenditure of €10.0 million in 2011, principally on pre-production activity, the year end cash balance of €29.8 million was €8.4 million higher than at the end of 2010, as a result of cash flow from record annual production.

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Financial Reviewcontinued

Liquidity, Credit and Interest Rate Risks continuedIn 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,andinresponseto,the2008bankingcrisis,andtheresultingsignificantreductionsininterestrates,thefocushadswitchedmoretowards preservation of capital.

Credit risk has obviously increased over the last few years given the global banking crisis, so the Group has continued to more closely monitor the performance of its banks. Indeed, in response to the Eurozone crisis, the Group has also made conscious decisions to both spread its deposits across a wider range of banks and to reduce the amount of Euros it holds. An example of this is that during 2011 the Company’s Dutch subsidiary moved its primary banking relationship to Rabobank, a AA rated bank largely unaffected by the banking crisis.

Alongside the widening of its banking relationships the Group has also recently decided to more proactively seek to increase the returns on its cash which is being supervised by its 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.

Currency Risk As in previous years the majority of capital expenditure in the year was denominated in Euro, then US Dollars with the balance being in Sterling. 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.

As a consequence of the above, few significant foreign currency dealings were therefore required during 2011. Going forward the Group will have a greater requirement to exchange currency on a more regular basis, especially from Euro to US Dollar. Indeed, and partly as a response to the current Eurozone crisis and the Board’s concern over the longevity of the Euro, 2012 to date has seen the Group exchange a significant amount of Euros into US Dollars, and to a lesser extent, Sterling.

FollowingthechangeinfunctionalandpresentationalcurrencytotheEuroduring2008,theGroupnowhasfoursubsidiaries,plustheItalianbranch of Northern Petroleum (UK) Limited, which maintain accounting records denominated in Euro, in line with the Company’s current functional currency. With effect from 1 January 2011, Northpet Investments Limited, the joint venture company through which our 1.25% interest in the Guyane offshore is held, determined that its functional currency had changed from Sterling to the US Dollar, with the triggering event for the change being the decision to drill the first exploration well, which was costed and paid for in US Dollars, on the licence. Followingsuccess,allfutureexplorationanddevelopmentexpenditureisalsoexpectedtobeinUSDollars.

The remainder 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 overall to have the welcome consequence of ensuring the impact of currency movements is relatively modest: in 2011 the exchange difference on translation of foreign operations shown in the Consolidated Statement of Comprehensive Income was a €527,000 credit, compared to a €164,000 credit in 2010.

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 oftheCompany.FollowingtheZaedyus-1discoverywellasreferredtoabove,theGroupisnowexpectedtohavemoresignificantUSDollar capital expenditure requirements going forward, so 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 €0.24 million profit on exchange for 2011 (2010: €0.35 million loss 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.

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Operational RiskOperational risks include equipment failure, well blowouts, pollution, fire and the consequences of bad weather. These risks cannot be understated, especially given the Deepwater Horizon incident in the Gulf of Mexico remains fresh in the memory and continues to attract significant column inches.

The Deepwater Horizon incident has obviously continued to result in 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 on an ongoing basis closer and more regular liaison with the Group’s insurance advisers, especially given our involvement as a partner in the complex and challenging Zaedyus-1 discovery well during 2011.

The Group remains justifiably proud of its continued claim free record.

As members of the Group remain project operator of the vast proportion of our oil and gas interests, we are required to take increased responsibility, as part of that role for our 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 normalrisksanduncertaintiesassociatedwiththeexploration,developmentandproductionofhydrocarbons.Further informationonsome of the key judgements/assumptions can be found within 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 ResolutionsFinallyIwouldliketobrieflyaddressoneofthespecialresolutionstobeproposedbytheBoardforthenextAnnualGeneralMeeting(“AGM”)whichthisyearistobeheldon29June.

Shareholders have approved at each of the last four AGMs a resolution to make market purchases in the Company’s own shares. Whilst the Board has to date 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 4,768,300 shares, which will represent approximately 5% of the share capitalexpectedtobeinissueasatthedateoftheAGM.Thisisthesameinpercentagetermsassetlastyear.Furtherinformationontheterms under which the Company seeks such authorisation is contained within resolution 8 of the AGM Notice.

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

I hope that shareholders will, as in previous years, feel able to support this year’s resolutions, and look forward to there being the usual excellent level of attendance at the AGM.

C J FossDirector of Finance, Legal & Corporate Affairs7 June 2012

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Board of Directors

Derek MusgroveManaging Director Derek 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.

Chris FossDirector of Finance, Legal & Corporate Affairs and Company Secretary ChrisFosswasappointedtothispositioninSeptember2010andhas served as an Executive Director since August 2005. Chris is a member of the Institute of Chartered Accountants in England and Wales. Between 1998 and his joining the Company in 2003 asGroupFinancialControllerandCompanySecretary,Chrisheld 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.

Graham HeardExploration and Technical Director Graham Heard was appointed 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.

Maurice EatonGroup Operations Director Maurice Eaton was appointed as Director of Group Operations in June 2011, joining the Board in September 2011, having been Technical Manager – Operations since October 2009 and first employed in 2007 as a Principal Petroleum Engineer. He has over 30 years experience and holds a Masters in Petroleum Engineering from Imperial College. Starting his career as a Consultant with ERC, he gained international experience with Enterprise Oil, Amerada Hess and Svenska Petroleum. Maurice has had managerial roles that have been highly commercial with involvement in new ventures activity and negotiations with government authorities.

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Richard LathamChairman Richard 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 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.

Jeremy WhiteNon-Executive Director Jeremy White is currently a Non-Executive Director and is Chairman of the Audit, Health and Safety, Risks and Ethics and Remuneration and Nomination Committees, having previously beenFinanceDirectoruntilAugust2005.He isaFellowoftheInstitute of Chartered Accountants in England and Wales. He has worked in the oil industry for over 30 years, and immediately before joiningNorthernhewasUKGroupTaxControllerforPetroFina’sUKoperations.

Anthony BrewerNon-Executive Director Anthony Brewer was appointed as a Non-Executive Director during August 2006 and is currently 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.

Dr Rex Gaisford CBENon-Executive Director Rex Gaisford has worked in oil and gas businesses worldwide for over 35 years, and was appointed to the Board in August 2011. He has been CEO, MD, director, project manager of many large oil companies and led major multi-billion dollar exploration, development and production operations world-wide as well as opened up new business opportunities in the UK, US, Denmark, Norway and Brazil. HehasbeenManagingDirector&ExecutiveVicePresident forAmerican Independent Oil Company, Amerada Hess International, and Project Director & General Manager Engineering for Britoil Plc. Rex is CEO of consulting company RCM Consulting Limited.

Non-Executive Board members

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DirectorsR H R LathamChairman

D R MusgroveManaging Director

C J FossDirectorofFinance,Legal&CorporateAffairs

G L HeardExploration and Technical Director

M L EatonDirector of Group Operations

J M WhiteNon-Executive

A N BrewerNon-Executive

Dr R W Gaisford CBENon-Executive

SecretaryC J Foss, ACA

Registered officeMartin House5 Martin LaneLondon EC4R 0DP

Telephone: 020 7469 2900Facsimile:02074692901E-mail: [email protected]

Registered no.02933545

Legal FormPublic limited company

Country of Incorporation of Parent CompanyEngland

Office LocationsNorthern Petroleum London OfficeMartin House5 Martin LaneLondonEC4R 0DP

Our office in London is the Corporate headquarters where Northern’s Directors as well as head office finance team, technical teams, administrative support and investor and public relations are based.

Regional Office, The NetherlandsLangeVoorhout86,unitS2b2514 EJThe HagueNetherlands

The Netherlands company is situated in The Hague where the local Managing Director, Operations management, administrative support and finance team are based. Control of production is based at the Waalwijk gas field.

Regional Office, ItalyVialeTrastevere24900153RomeItaly

Our office in Rome is the primary interface with the Italian government and Ministry officials, accounting, legal and engineering activities are also undertaken in Rome.

Independent AuditorKPMG Audit Plc15 Canada Square London E14 5GL

BankersRabobank Den Haag LangeVijverberg22513 AB The Hague The Netherlands

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

Lloyds Banking Group 10 Gresham StreetLondonEC2V7AE

HSBC Bank Plc 8 Canada SquareLondonE14 5HQ

Barclays Bank Plc One Churchill PlaceLondonE14 5HP

Coutts & Co. 440 Strand LondonWC2R 0QS

UniCredit BancaPiazza Cavour BRomeItaly

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

Joint BrokerWesthouse Securities LimitedOne Angel CourtLondonEC2R 7HJ

SolicitorsBerwin Leighton PaisnerAdelaide HouseLondon BridgeLondon EC4R 9HA

Gordons22 Great James StreetLondon WC1N 3ES

RegistrarsNeville RegistrarsNeville HouseLaurel Lane HalesowenWest Midlands B63 3DA

Investor RelationsFTI Consulting Holborn Gate26 Southampton BuildingsLondon WC2A 1PB

Public RelationsBishopsgate Communications 3 London Wall BuildingsLondon WallLondon EC2M 5SY

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Directors’ Report

The Directors present their report together with the accounts for the year ended 31 December 2011.

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 FinancialReview.

Results and DividendsThe Group has reported a net profit for the year of €6,231,000 (2010 loss: €1,155,000).

The Directors do not recommend payment of a dividend (2010: €Nil).

Going ConcernThe Directors consider the use of the going concern basis of accounting is appropriate for the Company and the Group because there are 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.

The Group’s strategy, business activities, together with the factors likely to affect its future development, performance and position are set out in the Chairman’s Statement and the Review of Operations. The management team are experienced in forecasting and when assessing either projects relating to existing assets, or new business opportunities, for sanction ensure that they are not over committing the Group. The Directors intentionally committed, with the exception of the high impact Zaedyus-1 discovery well, much of the Group’s 2011 capital spend on development projects so as to focus on delivering enhanced near and medium term revenues, whilst leaving a reasonable cash balance of €29.8 million at the 2011 year end. The Board has processes in place to ensure that no significant 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.

TheFinancialReviewdescribestheoilandgaspricingrisks, liquidityandinterestraterisks,currencyrisksandoperationalriskstheCompany faces and some of the actions the Company has in place to manage these risks.

Note 23 to the accounts also describes, and where appropriate quantifies, a number of the risks the Group is exposed to, some of the more material ones being inter alia:

• creditriskresultingfromthefailureofacustomerorcounterpartytomeetitscontractualobligations;

• foreignexchangeriskresultingfromcostsandrevenuesbeingindifferentcurrencies;

• liquidityriskresultingfromtheinabilityoftheCompanytomeetitscontractualobligationswhentheyfalldue;and

• priceriskfromreductionsinproductpricesresultinginareductioninincome. The Group had cash resources of approximately €29.8 million (2010: €21.4 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 a production and reserve base to allow it to obtain debt and the Board is likely to seek to use this capacity in the future to fund some projects as it sees fit. 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.

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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.

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 2011(ordinary 5p shares)

At 31 December 2010(ordinary 5p shares)

A N Brewer 81,391 81,391M L Eaton (appointed 20 September 2011) 48,091 n/aC J Foss 107,565 107,565Dr R W Gaisford (appointed 30 August 2011) 12,500 n/aG L Heard 587,497 587,497R H R Latham 962,477 962,477D R Musgrove 1,037,260 1,037,260J M White 145,071 145,071

2,981,852 2,921,261

TheDirectorshavebeengrantedwarrantsexercisableintosharesoftheCompany.FurtherdetailsoftheseinterestsareshownintheReport 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 2011 or at 31 December 2010.

Mr G L Heard 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.

Dr R W Gaisford and M L Eaton retire from office in accordance with Article 113 of the Company’s Articles and, being eligible, offer themselves for 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 the disabled 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.

Directors’ Reportcontinued

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Substantial InterestsThe following interests appeared in the register as at 30 May 2012:

Name Shares % of issued

Nutraco Nominees Limited 6,068,291 6.36%Pershing Nominees Limited 5,418,453 5.68%The Bank Of New York (Nominees) Limited 5,159,450 5.41%TD Direct Investing Nominees (Europe) Limited 5,152,996 5.40%Nortrust Nominees 4,730,907 4.96%Barclayshare Nominees Limited 4,707,771 4.94%The Royal Bank of Scotland NV 3,968,727 4.16%Hargreaves Lansdowne (Nominees) Limited 3,315,445 3.48%L R Nominees Limited 3,212,387 3.37%

In addition, as at 31 May 2012, 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

BlackRock Investment Management (UK) Limited 9,928,260 10.41%Barry James Lonsdale 5,558,661 5.83%The Royal Bank of Scotland Group Plc 4,637,501 4.86%Majedie Asset Management Limited 3,689,100 3.87%

Financial InstrumentsDetails of the financial risk management objectives and policies, and details on the use of financial instruments by the Company and its subsidiaryundertakings,areprovidedintheFinancialReviewandinnote23tothefinancialstatements.

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 2011, the Group had an average of 34 (2010: 14) 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.

Political and Charitable ContributionsThe Company made €3,682 (2010: €1,872) of charitable contributions during the year. No political donations were made during the year.

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 upcoming AGM.

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 2012

C J Foss (Secretary to the Board)

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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 theAIMRulesoftheLondonStockExchangetheyarerequiredtopreparetheGroupfinancialstatementsinaccordancewithIFRSsasadopted 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:

• selectsuitableaccountingpoliciesandthenapplythemconsistently;• makejudgementsandestimatesthatarereasonableandprudent;• fortheGroupfinancialstatements,statewhethertheyhavebeenpreparedinaccordancewithIFRSsasadoptedbytheEU;• fortheParentCompanyfinancialstatements,statewhetherapplicableUKAccountingStandardshavebeenfollowed,subjecttoany

material departures disclosed and explained in the financial statements; and• preparethefinancialstatementsonthegoingconcernbasisunlessit is inappropriatetopresumethattheGroupandtheParent

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’ Remuneration

Remuneration and Nomination CommitteeThe Company’s Remuneration and Nomination Committee is chaired by J M White and the Committee’s other members are R H R Latham and D R Musgrove, these members having been appointed post year end following A N Brewer’s decision to step down from the Committee. The Committee meets at least twice a year, with other directors often attending meetings by invitation but not being involved in any matter relating to themselves.

Theinformationinthisreporthasbeengivenonavoluntarybasis,astheCompanyislistedonAIMratherthantheFullList,andisthereforenot 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:

• basicannualsalaryorfees;• benefitsinkind;• bonusscheme;and• longtermincentiveplan,whichhastodatebeenrepresentedbythegrantingofwarrants.

Notice PeriodsThe notice period of Executive Directors is eighteen months, except for M L Eaton whose notice period is nine months, while that of Non-Executive Directors is nine months with the exception of Dr R W Gaisford whose notice period is six 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, at their election, can 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 2012. As in previous years the mechanism used has two parts – a performance related bonus based on a percentage of each individual Director’s average annual salary for 2012, and a further percentage of salary based on share price performance. Other than M L Eaton, none of the Directors received a bonus in respect of either 2010 or 2011.

Any bonus will be settled in January 2013, part in cash and part in new shares (subject to close period rules). 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 medium and long term success. To date this has been carried out by the granting of warrants to Directors, which 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 and appropriateness of the current scheme, especially in light of the recent all too regular changes in tax legislation.

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Report on Directors’ Remunerationcontinued

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

Presented in Euro Year ended 31 December 2011 Year ended 31 December 2010

Salaryor fees

€’000Bonus€’000

Otherbenefits

€’000Total€’000

Salaryor fees€’000

Bonus€’000

Compen- sation

for loss of office

€’000

Otherbenefits

€’000Total

€’000

Executive Directors (salaries):M L Eaton* 61 – 3 64 – – – – –CJFoss 245 – 11 256 247 – – 11 258G L Heard 227 – 10 237 230 – – 9 239D R Musgrove 314 – 32 346 317 – – 15 332N Wright – – – – 80 – 219 2 301

Non-Executive Directors (fees):A N Brewer 41 – 5 46 42 – – 3 45R W Gaisford 12 – – 12 – – – – –R H R Latham 64 – 7 71 65 – – 6 71J M White 44 – 3 47 45 – – 2 47

1,008 – 71 1,079 1,026 – 219 48 1,293

Presented in GBP (settlement currency)

Year ended 31 December 2010 Year ended 31 December 2011

Salaryor fees

£’000Bonus£’000

Otherbenefits

£’000Total£’000

Salaryor fees£’000

Bonus£’000

Compensa-tion

for loss of office

£’000

Otherbenefits

£’000Total

£’000

Executive Directors (salaries):M L Eaton* 53 – 3 56 – – – – –CJFoss 212 – 9 221 212 – – 9 221G L Heard 197 – 9 206 197 – – 8 205D R Musgrove 272 – 28 300 272 – – 13 285N Wright – – – – 69 – 188 1 258

Non-Executive Directors (fees):A N Brewer 36 – 4 40 36 – – 3 39R W Gaisford 11 – – 11 – – – – –R H R Latham 56 – 6 62 56 – – 5 61J M White 38 – 3 41 39 – – 2 41

875 – 62 937 881 – 188 41 1,110

* The total remuneration, excluding notional gains on warrants, for 2011 for M L Eaton was £177,914 (€212,944) (2010: £244,870 (€273,110)).

The remuneration of Non-Executive Directors includes fees set, with effect from 1 January 2012, at £2,376 (€2,844) 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, (M L Eaton one and a half times), 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 2012thesepaymentsamountto£566,280(€677,960)forDRMusgrove,£441,720(€528,880)forCJFoss,£441,000(€527,954)forG L Heard, £307,890 (€368,598) for M L Eaton, £111,360 (€133,318) for R H R Latham, £65,520 (€78,438) for J M White, £65,520 (€78,438) for A N Brewer.

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Warrants held by Directors serving at 31 December 2011 were as follows:

At 1 January

2010’000s

Issued’000s

Exercised’000s

At 1 January

2011’000s

Issued’000s

Exercised’000s

Lapsed’000s

At 31 December

2011’000s

A N Brewer:At117.0p(exercisableby29February2012)* 150 – – 150 – – – 150At 68.5p (exercisable by 31 December 2013) 105 – – 105 – – – 105

255 – – 255 – – – 255M L Eaton:At 67.0p (exercisable by 31 December 2012)** 38 – – 38 – – – 38At 68.5p (exercisable by 30 June 2014)** 25 – – 25 – – – 25

63 – – 63 – – – 63C J Foss:At12.5p(exercisableby29February2012)* 200 – – 200 – – – 200At130.0p(exercisableby29February2012)* 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

730 730 – – – 730G L Heard:At 11.25p (exercisable by 31 July 2011) 100 – (100) – – – – –At 130.0p (exercisable by 30 June 2011) 125 – – 125 – – (125) –At 138.5p (exercisable by 31 December 2012) 100 – – 100 – – – 100At 68.5p (exercisable by 31 December 2013) 175 – – 175 – (19) – 156

500 – (100) 400 – (19) (125) 256R H R Latham:At 15.625p (exercisable by 31 July 2011) 120 – (120) – – – – –At 11.25p (exercisable by 31 July 2011) 280 – (280) – – – – –At130.0p(exercisableby29February2012)* 150 – – 150 – – – 150At 68.5p (exercisable by 31 December 2013) 105 – – 105 – – – 105

655 – (400) 255 – – – 255D R Musgrove:At15.625p(exercisableby29February2012)* 250 – – 250 – – – 250At11.25p(exercisableby29February2012)* 660 – – 660 – – – 660At130.0p(exercisableby29February2012)* 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

1,652 – – 1,652 – – – 1,652J M White:At15.625p(exercisableby29February2012)* 120 – – 120 – – – 120At11.25p(exercisableby29February2012)* 280 – – 280 – – – 280At130.0p(exercisableby29February2012)* 150 – – 150 – – – 150At 68.5p (exercisable by 31 December 2013) 105 – – 105 – – – 105

655 – – 655 – – –

Total 4,510 – (500) 4,010 – (19) (125) 3,866

* Warrants due to expire during 2011 were extended on 29 July 2011.** Warrants held on date of appointment.

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Report on Directors’ Remunerationcontinued

Detailsofwhenthewarrantsaboveweregrantedaredisclosedinnote19“ShareCapital”;onpage72.

On the exercise of the Company’s warrants during the year the Directors made aggregate notional gains of £10,916 (€12,578) (2010: £582,000, €645,000); the highest single gain made by an individual Director was £10,916 (€12,578) (2010: £333,000, €370,000). The closing mid-market price of the shares on 31 December 2011 was 71.2p (2010: 109p) and the range of closing mid-market prices during the year was 66.75p to 140p (2010: 84p to 152.5p).

This report was approved by the Board on 7 June 2012 and signed on its behalf by:

J M WhiteChairman of the Remuneration and Nomination Committee

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We have audited the Group financial statements of Northern Petroleum Plc for the year ended 31 December 2011 set out on pages 46 to 81 and the Company financial statements on pages 84 to 91. The financial reporting framework that has been applied in the preparation oftheGroupfinancialstatementsisapplicablelawandInternationalFinancialReportingStandards(IFRSs)asadoptedbytheEU.Thefinancial 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 40, 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:

• thefinancialstatementsgiveatrueandfairviewofthestateoftheGroup’sandoftheParentCompany’saffairsasat31December2011and of the Group’s profit for the year then ended;

• theGroupfinancialstatementshavebeenproperlypreparedinaccordancewithIFRSsasadoptedbytheEU;• theParentCompanyfinancialstatementshavebeenproperlypreparedinaccordancewithUKGenerallyAcceptedAccountingPractice;• thefinancialstatementshavebeenpreparedinaccordancewiththerequirementsoftheCompaniesAct2006.

Opinion on other matter 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:

• adequateaccountingrecordshavenotbeenkeptbytheParentCompany,orreturnsadequateforouraudithavenotbeenreceivedfrom branches not visited by us; or

• theParentCompanyfinancialstatementsarenotinagreementwiththeaccountingrecordsandreturns;or• certaindisclosuresofdirectors’remunerationspecifiedbylawarenotmade;or• wehavenotreceivedalltheinformationandexplanationswerequireforouraudit.

J Lowes (Senior Statutory Auditor)for and on behalf of KPMG Audit Plc, Statutory AuditorChartered Accountants15 Canada SquareLondon E14 5GL7 June 2012

Independent Auditors’ Report to the members of Northern Petroleum Plc

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Notes


2011€’000


2010€’000

Revenue 2 24,531 14,968

Production costs (5,298) (4,884)Depletion and amortisation – property, plant & equipment (7,116) (3,387)

Cost of sales 2 (12,414) (8,271)

Gross profit 12,117 6,697

Pre-licence costs (521) (593)

Administrative expenses – other (3,876) (4,246)Administrative expenses – share incentives 3 & 19 136 (359)

Administrative expenses – total (3,740) (4,605)

Profit on disposal of assets 4 3,108 –

Profit from operations 2 & 3 10,964 1,499

Finance costs 7 (1,033) (1,524)Finance income 8 579 17Share of operating loss of joint ventures & associates (23) (8)

Profit / (loss) before tax 10,487 (16)

Tax expense 9 (4,256) (1,139)

Profit / (loss) for the year 6,231 (1,155)

Basic earnings per share on profit / (loss) for the year 10 6.7 cents (1.3) cents

Diluted earnings per share on profit / (loss) for the year 10 6.5 cents (1.3) cents

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

The notes on pages 51 to 81 form part of these financial statements.

Consolidated Income Statementfor the year ended 31 December 2011

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2011€’000


2010€’000

Profit / (loss) for the year 6,231 (1,155)

Exchange differences on translation of foreign operations 527 164

Other comprehensive income for the year, net of income tax 527 164

Total comprehensive profit / (loss) for the year 6,758 (991)

All amounts are attributable to equity shareholders of the parent.


Consolidated Statement of Comprehensive Incomefor the year ended 31 December 2011

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Consolidated Statement of Financial Positionat 31 December 2011

Notes2011

€’0002010

€’000

AssetsNon-current assetsIntangible assets 11 34,694 31,810Property, plant and equipment 12 47,513 58,123Investments in joint ventures 13 3,568 579Investments in associates 13 15 15Loans and other receivables 15 – 129

85,790 90,656Current assetsInventories 14 70 124Trade and other receivables 15 10,608 8,668Cash and cash equivalents 29,794 21,430

40,472 30,222

Total assets 126,262 120,878

LiabilitiesCurrent liabilitiesTrade and other payables 16 6,278 6,326Corporation tax liability 16 2,891 –

9,169 6,326Non-current liabilitiesTrade and other payables 24 30Provisions 17 9,437 16,286Deferred tax liabilities 18 14,352 12,865

23,813 29,181

Total liabilities 32,982 35,507

Net assets 93,280 85,371

Capital and reservesShare capital 19 5,855 5,768Share premium 12,366 11,501Merger reserve 10,289 10,289Special reserve (Distributable) 28,583 28,428Special reserve (Un-distributable) – 155Share incentive plan reserve 3,020 3,964Foreign currency translation reserve 182 (345)Retained earnings 32,985 25,611Total equity 93,280 85,371

All amounts are attributable to equity shareholders of the parent. The notes on pages 51 to 81 form part of these financial statements.

These financial statements were approved and authorised for issue by the Board of Directors on 7 June 2012 and were signed on its behalf by:

G L Heard C J FossDirector Director

REGISTERED NO. 02933545

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Consolidated Statement of Cash Flowsfor the year ended 31 December 2011


2011€’000


2010€’000

Cash flows from operating activitiesProfit / (loss) before tax 10,487 (16)Depletion and amortisation 7,116 3,387Depreciation – non-oil and gas property, plant and equipment 194 205Profit on disposal of property, plant and equipment (3,108) –Foreign exchange (gain) / loss (244) 348Finance income (335) (17)Finance charges 1,033 1,176Share-based payments 199 799Expenses settled by issue of shares 29 65Share of operating loss in associate 23 8Net cash inflow before movements in working capital 15,394 5,955

Decrease / (increase) in inventories 56 (26)(Increase) / decrease in trade and other receivables (2,427) 8,247Increase / (decrease) in trade and other payables 36 (2,539)Net cash inflow from changes in working capital (2,335) 5,682

Taxes refunded / (paid) 1,913 (2,857)

Net cash inflow from operating activities 14,972 8,780

Cash flows from investing activitiesInterest received 335 17Interest paid (312) (6)Purchase of property, plant and equipment (3,579) (9,526)Expenditure on exploration and evaluation assets (2,191) (2,835)Purchase of other intangible assets (1,184) (999)Investment in joint venture company (3,012) (328)Sale of property, plant and equipment 2,154 –Net cash outflow from investing activities (7,789) (13,677)

Cash flows from financing activitiesIssue of ordinary shares net of fees associated with placing – 11,464Proceeds from the exercise of equity warrants 923 270Net cash inflow from financing activities 923 11,734

Net increase in cash and cash equivalents 8,106 6,837Cash and cash equivalents at start of year 21,430 15,002Effect of exchange rate movements 258 (409)Cash and cash equivalents at end of year 29,794 21,430

There have been no significant non-cash transactions during either year.


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Consolidated Statement of Changes in Equityfor the year ended 31 December 2011

Sharecapital

€’000

Sharepremiumaccount

€’000

Mergerreserve

€’000

Special reserves

€’000

Shareincentive

planreserve

€’000

Foreigncurrency

translationreserve

€’000

Retainedearnings

€’000Total

€’000

At 1 January 2010 4,983 194 10,289 28,583 3,865 (509) 26,359 73,764Total 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 85,371Total comprehensive profit for the year – – – – – 527 6,231 6,758 Issue of shares during the year – warrants and staff bonus 87 865 – – – – – 952 Equity share warrants exercised – – – – (1,143) – 1,143 – Share-based payments – – – – 199 – – 199At 31 December 2011 5,855 12,366 10,289 28,583 3,020 182 32,985 93,280

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 retained 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.

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Notes to the Accountsfor the year ended 31 December 2011

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 84 to 91. 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 37, the Directors consider the use of the going concern basis of accounting is appropriate for the Company and the Group because there are 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.

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, some of which are described in note 23 to the financial statements.

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 IFRS 3 – Business Combinations The IASB issued amendments to IFRS 3 in May 2010. This was

effective for annual periods beginning on or after 1 July 2010. The amendments are as follows:

• tolimittheaccountingpolicychoicetomeasureNon-ControllingInterests (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

• toextendthescopeoftheguidanceonhowtoapportionthemarket-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.

(ii) Standards affecting presentation and disclosure

IFRS 7 – Financial Instruments: Disclosures This standard was amended to: • includeastatementdetailing that the interactionbetween

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

• requireadditionaldisclosuresabout the transferof financialassets to enable users to understand the possible effects of any risks that may remain with the transferor.

These amendments were effective for annual periods beginning on or after 1 January 2011 and 1 July 2011 respectively.

IAS 1 – Presentation of Financial Statements 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. This amendment was effective for annual periods beginning on or after 1 January 2011.

IAS 24 – Related Party Disclosures In July 2010 the IASB introduced changes to IAS 24, making an

amendment to the definition of a related party. The amendments stated that two parties were related to each other whenever a person or a third party had joint control over one entity and that person (or a close member of that person’s family) or a third party had joint control or significant influence over the other entity. This amendment was effective for annual periods beginning on or after 1 January 2011.

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:

IFRS 7 – Financial Instruments: Disclosures Amendments were made to require additional disclosures about

transfers of financial assets and should enable users to understand the possible effects of any risks that may remain with the transferor. The amendments also require additional disclosures if a disproportionate amount of transfer transactions are undertaken around the end of a reporting period.

IFRS 9 – Financial Instruments This standard will replace IAS 39 – Financial Instruments:

Recognition and Measurement. The standard contains two primary measurement categories for financial assets: amortised cost and fair value. Financial assets are classified into one of these categories on initial recognition.

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1. Accounting Policies continued IFRS 10 – Consolidated Financial Statements This standard will replace the existing accounting for subsidiaries

and joint ventures, and making limited amendments in relation to associates.

IFRS 11 – Joint Arrangements This standard will replace the existing accounting for subsidiaries

and joint ventures, and making limited amendments in relation to associates. All parties to a joint arrangement are within the scope of IFRS 11.

IFRS 12 – Disclosure of Interests in Other Entities This standard will replace the existing accounting for subsidiaries

and joint ventures, and making limited amendments in relation to associates.

IFRS 13 – Fair Value Measurement This is a new standard that will replace the existing guidance on fair

value measurement in different IFRSs with a single definition of fair value, a framework for measuring fair values and disclosures about fair value measurements.

IAS 1 – Presentation of Financial Statements The amendments require that an entity present separately the items

of Other Comprehensive Income that may be reclassified to profit or loss in the future from those that would never be reclassified to profit or loss. They also preserve the existing option to present the profit or loss and other comprehensive income in two statements.

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 2011.

SubsidiariesSubsidiaries are entities over whose financial and operating policies the Group has the power to exercise control, and 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.

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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% (2010: 10% and 15%) 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% (2010: 4.5% 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 five 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 51).

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.

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.

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1. Accounting Policies continuedIf 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:

• Leaseholdimprovements–overthetermofthelease• Computerhardwareandsoftware–fourtofiveyears• Officeequipment–fouryears• Motorvehicles–fouryears

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.

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 23.

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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 movements in deferred tax.

Current tax, including UK Corporation and any overseas tax, is provided for at amounts expected to be paid (or recovered) using the tax rates and laws that have been enacted, or substantially enacted, by the Statement of Financial Position 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 12);Carrying value of intangible exploration and evaluation assets (Note 11);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 an 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 82. 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 17);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. For the Geesbrug, Grolloo, Brakel and Wijk en Aalburg fields, the amounts recorded for asset retirement obligations are based on third party engineering reviews that were carried out in late 2011.

Share-based payments (Notes 3 and 19);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 2011

United Kingdom

€’000Italy

€’000Netherlands

€’000Other EU

€’000Total

€’000

Revenue from external customers

Gas & gas condensate – – 23,805 – 23,805

Oil 489 – – – 489

Project operator fees 75 43 119 – 237

564 43 23,924 – 24,531

Cost of sales

Production costs 155 – 5,143 – 5,298

Depletion and amortisation 77 – 7,039 – 7,116

232 – 12,182 – 12,414

Gross profit 332 43 11,742 – 12,117

Pre-licence costs – (352) (31) (138) (521)

Administrative expenses (2,229) (301) (1,102) (108) (3,740)

Profit on sale of tangible assets – – 3,108 – 3,108

(Loss) / profit from operations (1,897) (610) 13,717 (246) 10,964

Finance charges (9) (3) (1,021) – (1,033)

Finance income 275 3 301 – 579

Share of operating loss in associates – – – (23) (23)

(Loss) / profit before tax (1,631) (610) 12,997 (269) 10,487

Income tax (charge) / credit – – (4,378) 122 (4,256)

Net (loss) / profit for the financial year (1,631) (610) 8,619 (147) 6,231

The Group has one major customer; of the €23,805,000 sales of gas and gas condensate in The Netherlands, (2010: €14,098,000), €23,070,000 comprises sales to GasTerra B.V. (“GasTerra”), (2010: €13,709,000).

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 productuion and country of customer.


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Assets and liabilities at 31 December 2011United

Kingdom€’000

Italy€’000

Netherlands€’000

Other EU€’000

Total€’000

Segment assets 12,826 31,084 48,823 3,735 96,468Cash and cash equivalents 14,408 850 14,536 – 29,794Total assets 27,234 31,934 63,359 3,735 126,262

Segment liabilities (2,357) (2,056) (11,325) – (15,738)Current tax liabilities – – (2,892) – (2,892)Deferred tax liabilities – (3,333) (11,019) – (14,352)Total liabilities (2,357) (5,389) (25,236) – (32,982)

Other segment itemsCapital expenditure 2,550 1,708 2,481 5 6,744Depreciation, depletion and amortisation (238) – (7,072) – (7,310)

Exchange differences on translation of foreign operations 527 – – – 527Share-based payments 199 – – – 199Other non-cash expenses 29 – – – 29

Included in segment assets aboveInvestment in joint venture and associates 15 – – 3,568 3,583

Exploration, development and production 2010 comparative

UnitedKingdom

€’000Italy


€’000Other EU

€’000Total

€’000

Revenue from external customersGas & gas condensate – – 14,098 – 14,098Oil 387 – – – 387Project operator fees 83 215 185 – 483

470 215 14,283 – 14,968

Cost of salesProduction 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 – 6,697Pre-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) 1,499Finance charges (341) (1) (1,182) – (1,524)Finance income 6 – 11 – 17Share 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)

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2. Segmental Information continued

Assets and liabilities at 31 December 2010United

Kingdom€’000

Italy€’000


Other EU€’000

Total€’000

Segment assets 9,813 28,521 60,245 869 99,448

Cash and cash equivalents 16,295 736 4,399 – 21,430

Total assets 26,108 29,257 64,644 869 120,878

Segment liabilities (2,939) (362) (19,341) – (22,642)

Current tax liabilities – – – – –

Deferred tax liability – (3,333) (9,532) – (12,865)

Total liabilities (2,939) (3,695) (28,873) – (35,507)

Other segment items

Capital expenditure 2,947 847 9,565 1 13,360

Depreciation, depletion and amortisation (260) – (2,755) – (3,015)

Impairment loss – – (577) – (577)

Exchange differences on translation of foreign operations 164 – – – 164

Share-based payments 799 – – – 799

Other non-cash expenses 65 – – – 65

Included in segment assets above

Investment in joint venture and associates 15 – – 579 594

Long term receivables – – – 129 129

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


2011€’000


2010€’000

Depreciation of non-oil and gas property, plant and equipment (note 12b) 194 205

Operating lease rentals – land and buildings 675 734

Operating lease rentals – other 116 81

Share-based payments – National Insurance (335) (440)

Share-based payments – IFRS 2 199 799

Administrative expenses – share incentives (136) 359

Auditors’ Remuneration


2011€’000


2010€’000

Audit fees payable to the Company’s auditor for the audit of the Company’s financial statements 61 55

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

– the audit of the Company’s subsidiaries 41 71

– taxation services 3 6

– other services pursuant to such legislation 32 37

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


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4. Profit on Disposal of AssetsYear ended

31 December2011

€’000


2010€’000

Sale proceeds 3,188 –

Cost of assets disposed of – –

Disposal expenses (80) –

Profit on disposal of property, plant and equipment 3,108 –

The profit on disposal of assets arises on the sale of an interest in the Vinkega gas field. The Vinkega gas field was discovered when Vermilion Oil & Gas Netherlands B.V. (“Vermilion”) drilled the Vinkega-1 well (spudded in November 2009) on its Gorredijk Licence. The field was mapped as underlying both part of the Gorredijk Licence and part of the Drenthe III Licence, held by Northern Petroleum Nederland B.V. (“NPN”), a wholly owned subsidiary of Northern Petroleum Plc, Nederlandse Aardolie Maatschappij B.V. (“NAM”) and Dyas B.V. All the Drenthe III Licence interest holders agreed to the sale of their respective Drenthe III interests in the Vinkega field to Vermilion. Seventy percent of the purchase price was paid on signing of the Sale and Purchase Agreement in December 2011, with the remaining thirty percent being paid in May 2012 following completion. In addition, the retention of the sale proceeds is contingent on NPN earning its share of the Drenthe III exploration licence under the terms of the agreement with NAM signed August 2005 by drilling a second exploration well on the permit.

5. Directors’ RemunerationYear ended

31 December2011

€’000


2010€’000

Executive salaries including bonus 847 874

Non-Executive fees including bonus 161 152

Compensation for loss of office – 219

Benefits in kind 71 48

Emoluments 1,079 1,293

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 €346,000 (2010: €332,000).

Year ended 31 December 2011 Year ended 31 December 2010

Presented in Euro

Salaryor fees

€’000Bonus €’000

Otherbenefits

€’000Total

€’000

Salary or fees €’000

Bonus €’000

Compen-sation

for lossof office

€’000

Otherbenefits

€’000Total

€’000

Executive Directors (salaries):

M L Eaton* 61 – 3 64 – – – – –C J Foss 245 – 11 256 247 – – 11 258G L Heard 227 – 10 237 230 – – 9 239D R Musgrove 314 – 32 346 317 – – 15 332N Wright – – – – 80 – 219 2 301Non-Executive Directors (fees):

A N Brewer 41 – 5 46 42 – – 3 45R W Gaisford 12 – – 12 – – – – –R H R Latham 64 – 7 71 65 – – 6 71J M White 44 – 3 47 45 – – 2 47

1,008 – 71 1,079 1,026 – 219 48 1,293


On the exercise of the Company’s warrants during the year the Directors made aggregate notional gains of £10,916 (€12,578) (2010: £582,000, €645,000); the highest single gain made by an individual Director was £10,916 (€12,578) (2010: £333,000, €370,000).

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

31 December2011

€’000


2010€’000

Salaries 4,514 4,899

Social security costs 741 620

Defined contribution pension costs 42 27

Other benefits in kind 166 143

5,463 5,689

Charge for share-based payments (note 3) 1,496 799

National insurance accrual release on share-based payments (335) (440)

6,624 6,048

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 €1,638,000 (2010: €1,838,000).

The 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 €42,000 (2010: €27,000). There were no outstanding or prepaid contributions at either the beginning or end of the financial year. Excluding the Directors, there were 31 (2010: 36) full time members of staff at the end of the year. In addition, during the year NPN employed 8 fixed term contractors (2010: 6).

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

2011 2010

Technical 8 10

Professional 6 6

Operations 7 9

Administration 13 12

34 37

7. Finance ChargesYear ended

31 December2011

€’000


2010€’000

Foreign exchange losses – 348

Other interest payable 300 673

Bank interest payable 12 6

Unwinding of discount on decommissioning provisions 721 497

1,033 1,524

8. Finance Income and other Finance GainsYear ended

31 December2011

€’000


2010€’000

Interest receivable 335 17

Foreign exchange gains 244 –

579 17


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9. Tax Expense / (Credit)

a) Analysis of tax expense / (credit)


2011€’000


2010€’000

Current tax:

UK tax – current year – –

Tax on overseas operations on profits for the year – current year 2,891 –

Current tax – adjustment in respect of prior years (122) (2,578)

2,769 (2,578)

Deferred tax:

UK tax – –

Overseas tax – origination and reversal of temporary differences (480) 1,876

(480) 1,876

Adjustment to prior year deferred tax 1,967 1,841

Total tax expense (note 9b)) 4,256 1,139

The Regulation for Depreciation At Will 2001 (“DAW”) was updated in early 2009 to be applicable for both Dutch Corporate Income Tax (“CIT”) and for State Profit Share (“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, (2009 expenditure), and 2010 and 2011, (2010 expenditure), at up to 50% in each year, rather than on a unit of production basis. Investment in new fixed assets qualified if the investment was made in 2009 or 2010 and as long as the assets subject to a DAW claim were in use before 1 January 2012. NPN has elected to utilise DAW for capital expenditure for the years 2009 to 2011.

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 2012 – for analysis of the tax charge by country of operation please see note 2, “Segmental Information”.

b) Factors affecting tax expense / (credit)The tax expense for the year is higher than the standard rate of corporation tax in the UK of 26.5% (2010: 28%). The difference is explained below:


2011€’000


2010€’000

Group loss before taxation 10,487 (16)

Tax on Group loss before taxation at an effective rate of 26.5% (2010: 28%) 2,779 (4)

Effects of:

Expenses not deductible for corporate income tax purposes (84) 28

Capital allowances for period in excess of depreciation (1,526) (1,414)

Utilisation of brought forward tax losses (538) –

Current tax losses not utilised and carried forward 1,801 1,747

Uncrystallised capital allowances not utilised and carried forward 45 65

Effects of higher supplementary charges to corporation tax 3,201 760

Effects of different corporate tax rates on UK and overseas earnings (275) (119)

Adjustment in respect of prior years – current tax (122) (38)

Adjustment in respect of prior years – deferred tax – 114

Effects of overseas deferred tax – origination and reversal of temporary differences (1,025) –

Total current tax expense for year 4,256 1,139

Northern’s effective tax rate in The Netherlands is less than the usual 50% for 2011. This has arisen because of the effect of deemed CIT calculated on SPS arising from the calculation of Netherlands CIT and SPS where the two taxes are offset or deducted against each other, and also because for 2011 NPN’s SPS loss utilisation was significantly higher than its CIT loss utilisation.

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9. Tax Expense / (Credit) continuedc) Factors that may affect future tax expenseThe Group has corporate income tax and supplementary hydrocarbon tax losses of €33.33 million (2010: €29.71 million), and uncrystallised capital allowances of approximately €1.34 million (2010: €1.17 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:

UK:In the 23 March 2012 budget, the Chancellor proposed changes that would reduce the main corporation tax rate by one percent per annum to 23% by 1 April 2014, and improved allowances and reliefs available for certain types of UKCS fields.

Other countries of operation:Since 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 in the near term a material effect on the Group’s tax position in those jurisdictions.

10. Basic Earnings / (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.

2011€’000

2010€’000

Net profit / (loss) attributable to equity holders used in basic calculation 6,231 (1,155)

Net profit / (loss) attributable to equity holders used in dilutive calculation 6,231 (1,155)

Number’000

Number’000

Basic weighted average number of shares 93,013 86,094

Dilutive potential of ordinary shares:

Warrants exercisable under Company schemes 2,227 –

Diluted weighted average number of shares 95,240 86,094

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


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11. Intangible Assetsa) 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.

UnitedKingdom

€’000Italy


€’000Other EU

€’000Total

€’000

Cost:

At 1 January 2011 5,335 10,218 15,236 191 30,980

Additions 214 1,012 750 5 1,981

Transfers (419) – – – (419)

Exchange movement 140 – – (1) 139

At 31 December 2011 5,270 11,230 15,986 195 32,681

Exploration expenditure written off:

At 1 January 2011 42 – 99 28 169

Exchange movement 1 – – – 1

At 31 December 2011 43 – 99 28 170

Net book value:

At 31 December 2011 5,227 11,230 15,887 167 32,511

The comparative tables for 2010 are detailed below:United

Kingdom€’000

Italy€’000


Other EU€’000

Total€’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

Exploration expenditure written off:

At 1 January 2010 42 – 99 28 169

Exchange movement – – – – –

At 31 December 2010 42 – 99 28 169

Net book value:

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

The Group’s share of the exploration and evaluation assets of joint venture and associate companies at 31 December 2011 is analysed as follows:

Total€’000

United Kingdom 13

Other EU 3,742

3,755

At the year end the contractual commitments for capital expenditure in respect of intangible assets was €916,000 (2010: €143,000), of which the Group’s share was €494,000 (2010: €86,000).

The 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 one of which is 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.

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11. Intangible Assets continuedb) IT systems

Computer software

€’000

Cost:

At 1 January 2011 999

Additions 1,184

At 31 December 2011 2,183

Depreciation:

At 1 January 2011 –

Charge for the year –

At 31 December 2011 –

Net book value:


The additions of €1,184,000 above comprise software and implementation costs for a new IT system. The first IT system modules went live in March 2012 and therefore no depreciation has been charged in 2011 (2010: Nil). The final forecast cost of the IT system is approximately €3.0 million, including the future implementation of budgeting, forecasting and contract management software.

12. Property, Plant and Equipment

a) Oil and Gas AssetsNetherlands –

Developed€’000

Netherlands – Undeveloped

€’000

UK –Developed

€’000

UK –Undeveloped

€’000

Italy –Undeveloped

€’000Total

€’000

Cost:

At 1 January 2011 41,583 7,421 781 1,839 16,610 68,234

Additions 909 773 49 995 696 3,422

Transfers – – – 419 – 419

Adjustments (7,362) – – – – (7,362)

Exchange movement – – 19 66 – 85

At 31 December 2011 35,130 8,194 849 3,319 17,306 64,798

Depletion and amortisation:

At 1 January 2011 9,931 – 526 – – 10,457

Charge for the year 7,039 – 77 – – 7,116

Exchange movement – – 19 – – 19

At 31 December 2011 16,970 – 622 – – 17,592

Net book value:

At 31 December 2011 18,160 8,194 227 3,319 17,306 47,206


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At the year end the contractual commitments for capital expenditure in respect of property, plant and equipment was €1,078,000 (2010: €3,555,000), of which the Group’s share was €477,000 (2010: €1,671,000).

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.

Further assets are included within the “Undeveloped” category which are continuing to be progressed and are expected to come into production in 2013 and beyond.

Adjustments in the year relate to changes in estimates, following third party reviews, in abandonment costs in respect of the Geesbrug, Grolloo, Brakel and Wijk en Aalburg gas fields. Further detail is provided in note 17. As a consequence of these adjustments, the depletion, depreciation and amortisation charge for the year is lower by €2,001,000.

At Wijk en Aalburg, which started production in late 2010, higher than expected levels of water ingress were encountered and the well was shut-in in September 2011 for further evaluation. Well intervention activities took place in April 2012 and the well has subsequently been brought back into production. However, the Directors judge for the purposes of these financial statements that the chances of successfully maintaining production over the long term are still uncertain and have decided to be cautious and write down the reserves resulting in an accelerated depletion charge for the year of €4,381,000.

The review process of our Netherlands fields announced last year continues. All our 3D seismic coverage is being reprocessed and some initial re-interpretations are available on fast track volumes. Preliminary reservoir study results have been assessed and on balance indicate the need for downward revision. Therefore the Board has taken the prudent step to reduce its Dutch 2P reserves by 10.67 million boe, 0.43 million boe (2.51 Bscf) of which was taken at the mid year in respect of Wijk en Aalburg, comprising a net reduction of 6.43 million barrels of oil in respect of Ottoland and Papekop and 24.58 Bscf in respect of our six producing gas fields. These further revisions have led to some additional immaterial accelerated DD&A charges in respect of the other producing fields.

The carrying value of Brakel, Geesbrug, Grolloo, Waalwijk and Wijk en Aalburg have been updated on the basis of revised management reserve estimates issued within the Group’s 2011 Report & Accounts dated 7 June 2012, which supersede as applicable reserves as determined previously by management or during 2010 by RPS Energy in an independent valuation of some of the Group’s oil and gas assets in The Netherlands. The carrying value of the P12 field is based on the most recent estimate by the field’s operator.

The carrying value of Ottoland and Papekop, the Group’s proven undeveloped oil and gas assets in The Netherlands, have been updated on the basis of revised management reserve estimates issued within the Group’s 2011 Report & Accounts dated 7 June 2012, which supersede reserves determined during 2010 by RPS Energy in an independent valuation of some of the Group’s oil and gas assets in The Netherlands.

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

• a10%interestintheproducingHorndeanfieldownedbytheCompany’swhollyownedsubsidiaries,NorthernPetroleum(GB)Limited,NorthernPetroleum (UK) Limited and NP Oil & Gas Holdings Limited; and

• a5%interestintheproducingAvingtonfieldownedbytheCompany’swhollyownedsubsidiary,NorthernPetroleum(GB)Limited.

Markwells Wood (PEDL 126) proven and probable reserves are the Company’s most recent estimates as announced within the Group’s 2011 Report & Accounts dated 7 June 2012, which supersede reserves as determined during 2010 by RPS Energy. Otherwise the carrying value of the Group’s proven developed and undeveloped oil in the UK at year end are 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.

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 in respect of all of the above is given in the unaudited Report on Net Commercial Oil & Gas Reserve Quantities.

Corporate

Governance

Accounts


12. Property, Plant and Equipment continuedThe comparative tables for 2010 are detailed below:

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

Depletion and amortisation:

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

Net book value:

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

b) Non-Oil and Gas Assets

Leasehold improvements

€’000

Computerand office

equipment€’000

Motor vehicles

€’000Total

€’000

Cost:

At 1 January 2011 303 748 36 1,087

Additions – 157 – 157

Disposals – (7) – (7)

At 31 December 2011 303 898 36 1,237

Depreciation:

At 1 January 2011 254 484 3 741

Charge for the year 48 137 9 194

Disposals – (5) – (5)

At 31 December 2011 302 616 12 930

Net book value:

At 31 December 2011 1 282 24 307


Corporate

Governance

Accounts


The comparative table for 2010 is detailed below:


€’000

Computer and office

equipment€’000

Motor

vehicles€’000

Total€’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


At 31 December 2010 254 484 3 741

Net book value:

At 31 December 2010 49 264 33 346

13. InvestmentsUnlisted

Investments€’000

TotalInvestments

€’000

Cost:

At 1 January 2011 594 594

Additions 3,012 3,012

Share of losses of associates (23) (23)

At 31 December 2011 3,583 3,583

Carrying value at 31 December 2010 594 594

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 €202,000 (2010: €263,000), Non-Current Assets €3,742,000 (2010: €1,200,000), Current Liabilities €377,000 (2010: €158,000) and Non-Current Liabilities €Nil (2010: €148,000).

Corporate

Governance

Accounts


13. 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

2011

Northpet Investments Limited 31 December 2011 7,888 754 7,134 – (47)

Oil & Gas Investments Limited 31 March 2011 52 30 22 – –

2010

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

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

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 2011. At 31 December 2011 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 two of the UK onshore licences and one UK offshore licence 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 audited accounts as at 31 December 2011. At 31 December 2011 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

Northern Petroleum (GB) Limited England & WalesOil and gas exploration

and production UKOrdinary shares

of £1–100%

Northern Petroleum Nederland B.V. The NetherlandsOil and gas exploration,

development and production NetherlandsOrdinary shares

of €10–100%

Northern Petroleum (UK) Limited England & WalesOil and gas exploration

and production ItalyOrdinary shares

of £0.001–100%

NP Netherlands Limited England & Wales Holding company UKOrdinary shares

of £1–100%

NP Offshore Holdings (UK) Limited England & WalesHolding company andoil and gas exploration UK

Ordinary sharesof £1–100%

NP Oil & Gas Holdings Limited England & Wales

Holding company and oil and gas exploration


of £1–100%

NP Solent Limited England & Wales Oil and gas exploration UKOrdinary shares

of £1–100%

NP Weald Limited England & Wales Oil and gas exploration UKOrdinary shares

of £1–100%

Northern Petroleum E&P Holdings Limited England & Wales Oil and gas exploration UK

Ordinary sharesof £0.0025–100%

The comparative table for 2010 is detailed below:Unlisted


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


Corporate

Governance

Accounts


14. Inventories 2011

€’0002010

€’000

Crude oil 1 1

Condensate 37 55

Spare parts 32 68

70 124

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 (2010: €Nil).

15. Trade and Other Receivables 2011

€’0002010

€’000

Non-current assets

Loans – 129

– 129

Current assets

Trade receivables 3,711 1,833

Other receivables 1,157 95

Loans 154 –

Corporation tax 628 2,540

VAT recoverable 189 347

Prepayments and accrued income 4,769 3,853

Total trade and other receivables 10,608 8,797

A loan of $200,000 (€154,000 net of fair value discount of €Nil, (2010: €148,000 net of fair value discount of €19,000) has been made to Northpet Investments Limited to be used to fund drilling expenditure incurred on the Guyane licence.

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 (2010: €Nil) and no amounts have been written off during the year (2010: €Nil).

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

2011€’000

2010€’000

Euro 9,731 8,108

UK Sterling 681 516

US Dollars 196 173

Total trade and other receivables 10,608 8,797

Of the €10,608,000 owing at 31 December 2011, €1,707,000 was overdue (2010: €1,220,000). The Group considers that this amount will be recovered in full and has not impaired it.

In May 2012 the Group issued a claim for an amount of €1,281,203 plus interest in the High Court in London against both Avobone Italy S.r.l. and Avobone Italy B.V., subsidiaries of the Indofin Group (together “Avobone”), relating to Avobone’s failure to meet in full its contractual obligations in respect of the Savio 1x well.

The ageing analysis of the overdue amount is as follows: 2011

€’0002010

€’000

0–3 months 155 42

4–6 months 173 14

6–12 months 134 261

1 year or more 1,245 903

Total overdue trade and other receivables 1,707 1,220

Corporate

Governance

Accounts


16. Trade and Other Payables 2011

€’0002010

€’000

Non-current liabilities

Accruals and deferred income 24 30

24 30

Current liabilities

Trade payables 2,704 1,938

Corporation tax liability 2,891 –

Taxation and social security 375 190

VAT payable 130 –

Other payables 590 205

Accruals and deferred income 2,479 3,993

Total trade and other payables 9,193 6,356

Trade and other payables are measured at amortised cost and their book value approximates to fair value at 31 December 2011 and 2010.

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

2011€’000

2010€’000

Euro 8,713 3,885

UK Sterling 413 2,459

Other 67 12

Total trade and other payables 9,193 6,356

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

17. Provisions 2011

€’0002010

€’000

At 1 January 16,286 9,564

Additions – 5,992

Utilised (210) –

Adjustments (7,362) 231

Unwinding of fair value discount 721 497

Exchange movement 2 2

At 31 December 9,437 16,286

The amount provided at 1 January 2011 represents the Group’s share of decommissioning liabilities in respect of the producing P12, Waalwijk, Geesbrug, Grolloo, Brakel and Wijk en Aalburg gas fields in The Netherlands and the producing Horndean and Avington fields in the UK and the Savio well in Italy. 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 Dutch oil and gas field abandonment costs in respect of the Geesbrug, Grolloo, Brakel and Wijk en Aalburg gas fields following comprehensive abandonment studies, comprising sites, surface facilities, subsurface wells and pipelines, carried out by experienced external engineering consultants in late 2011.

NPN operates the Brakel, Grolloo, Geesbrug and WIjk en Aalburg gas fields. It currently estimates that these provisions will become payable in approximately fourteen years for Grolloo, twenty nine years for Geesbrug, three years for Wijk en Aalburg and ten 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 eight 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 two to three years’ time. The Savio well site was abandoned during 2011.


Corporate

Governance

Accounts


18. Deferred Taxation 2011

€’0002010

€’000

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

Deferred tax liability recognised in income statement (593) (15,797)

Deferred tax asset recognised in income statement (894) 12,080

Balance at end of year (14,352) (12,865)

Comprising:

Tax losses 11,186 12,080

Other temporary differences (25,538) (24,945)

Deferred tax liability (14,352) (12,865)

Of the €25,538,000 other temporary differences, €22,205,000 arises on accelerated allowances received for oil and gas asset expenditure still held at cost within fixed assets, plus some other minor timing differences, while €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:

2011€’000

2010€’000

Timing differences on fixed assets – –

Other timing differences 1,525 4,298

Tax losses 10,954 5,548

Gross unrecognised temporary differences 12,479 9,846

19. Share Capital 2011

€’0002010

€’000

Authorised:

311,316,404 (2010: 311,316,404) ordinary shares of 5p each 19,648 19,648

Allotted, issued, called up and fully paid:


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 23.

Corporate

Governance

Accounts


19. 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 2011 are as follows:

Issue date

Final

exercisedate

Exercise price pence

At 1January

2011’000s

New issues’000s

Exercised ’000s

Lapsed or cancelled

’000s

At 31December

2011’000s

13 November 2001 29 February 2012* 15.625p 370 – – – 370

1 October 2002 29 February 2012* 11.25p 1,040 – – – 1,040

22 May 2003 29 February 2012* 12.5p 400 – – – 400

16 August 2004 31 July 2011 31.25p 250 – (250) – –

24 October 2005 30 June 2011 35.5p 250 – (250) – –

5 December 2005 30 June 2011 43.5p 150 – (150) – –

13 February 2006 30 June 2011 66.0p 150 – (150) – –

13 July 2006 30 June 2011 137.5p 125 – – (125) –

27 July 2006 29 February 2012* 130.0p 975 – – – 975

28 July 2006 31 July 2011 130.5p 150 – – (150) –

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

3 November 2006 29 February 2012* 117.0p 150 – – – 150

17 July 2007 31 January 2011 197.0p 10 – – (10) –

1 August 2007 31 January 2011 173.5p 10 – – (10) –

23 October 2007 30 April 2011 176.0p 20 – – (20) –

19 December 2007 31 December 2012 138.5p 100 – – – 100

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

12 December 2008 30 June 2011 67.0p 75 – (62.5) (12.5) –

12 December 2008 31 December 2011 67.0p 47.5 – (47.5) – –

12 December 2008 29 February 2012* 67.0p 37.5 – – – 37.5

12 December 2008 30 June 2012 67.0p 165 – (140) – 25

12 December 2008 31 July 2012 67.0p 75 – (25) – 50

12 December 2008 31 December 2012 67.0p 160 – (10) – 150

12 December 2008 30 June 2013 67.0p 192.5 – (147.5) – 45

12 December 2008 31 July 2013 67.0p 75 – – – 75

12 December 2008 30 June 2014 67.0p 55 – (10) – 45

31 December 2008 30 June 2012 68.5p 199 – (120) – 79

31 December 2008 30 June 2013 68.5p 208 – (90) – 118

31 December 2008 31 December 2013 68.5p 962.5 – (18.6) – 943.9

31 December 2008 30 June 2014 68.5p 233 – (10) (55) 168

12 January 2010 30 June 2013 77.5p 100 – – – 100

20 February 2010 30 September 2012 73.5p 40 – – – 40

20 February 2010 30 September 2013 73.5p 30 – – – 30

20 February 2010 30 September 2014 73.5p 30 – – (30) –

27 April 2010 31 December 2012 118.0p 25 – – – 25

24 June 2010 31 July 2011 200.0p 25 – – (25) –

24 June 2010 30 April 2013 80.0p 150 – (10) – 140

24 June 2010 16 June 2013 252.0p 156.3 – – – 156.3

24 June 2010 1 July 2014 252.0p 31.3 – – – 31.3

24 June 2010 1 July 2015 252.0p 31.3 – – – 31.3

6 October 2010 31 December 2011 152.0p 10 – – (10) –

6 October 2010 30 June 2012 152.0p 10 – – – 10

6 October 2010 31 December 2012 152.0p 10 – – – 10




Corporate

Governance

Accounts


Issue date

Final

exercisedate

Exercise

price pence

At 1January

2010’000s

New issues’000s

Exercised ’000s

Lapsed or cancelled

’000s

At 31December

2010’000s

11 January 2010 31 December 2013 148.0p 70 – – – 70

11 January 2010 31 December 2013 150.0p 35 – – – 35

12 April 2010 31 October 2013 127.5p 175 – – – 175

12 April 2010 31 December 2014 127.5p 175 – – – 175

4 January 2011 31 December 2015 108.88p – 30 – – 30

4 January 2011 30 June 2016 108.88p – 30 – – 30

12 January 2011 31 December 2015 133.75p – 62.5 – (62.5) –

12 January 2011 30 June 2016 133.75p – 62.5 – (62.5) –

15 August 2011 30 June 2015 69.88p – 50 – – 50

15 August 2011 31 December 2014 69.88p – 50 – – 50

7,813.9 285.0 (1,508.6) (610.0) 5,980.3

*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% (2010: 60%). Risk free investment rates between 0.52% and 2.87% (2010: 0.32% and 5.75%) have also been assumed in the calculations. The weighted average exercise price of all the warrants outstanding as at 31 December 2011 was 77.4p (2010: 75.6p). The weighted average remaining contractual life of all the warrants outstanding as at 31 December 2011 was 1 year and 1 month.

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 4 January 2011: • 30,000werenotexercisablebefore1July2011and30,000werenotexercisablebefore1January2012.

ii) Of the warrants above granted on 15 August 2011: • 50,000arenotexercisablebefore1January2013and50,000arenotexercisablebeforeJuly2013.

Corporate

Governance

Accounts


19. Share Capital continuedThe comparative table for 2010 is detailed below:

Issue date

Final

exercisedate

Exercise

price pence

At 1January

2010’000s

New issues’000s

Exercised ’000s

Lapsed orcancelled

’000s

At 31December

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 2011 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 2011 67.0p 17.5 – (17.5) – –

12 December 2008 31 October 2011 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 2011 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




Corporate

Governance

Accounts


Issue date

Final

exercisedate

Exercise

price pence

At 1January

2009’000s

New issues’000s

Exercised ’000s

Cancelled’000s

At 31December

2009’000s


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

Analysis of changes in share capital during the year:

2011€’000

2010€’000

At 1 January 5,768 4,983

Shares issued for cash as a result of exercise of warrants 86 43

Shares issued for cash as a result of placing – 715

Shares issued to staff in lieu of salary payments 1 27

At 31 December 5,855 5,768

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:

7 January 2011 – 37,500 ordinary 5p shares at 67p 2 27 29

15 February 2011 – 17,500 ordinary shares at 67p 1 13 14

4 March 2011 – 10,000 ordinary shares at 80p 1 9 10



30 March 2011 – 892,500 ordinary shares at an average of 55p 51 504 555

30 March 2011 – 18,600 ordinary shares at 68.5p 1 13 14


1 July 2011 – 150,000 ordinary shares at 66p 8 102 110

29 July 2011 – 250,000 ordinary shares at 31.25p 14 75 89

18 October 2011 – 50,000 ordinary shares at 68p 3 36 39

Issued to staff in lieu of salary payments:

31 January 2011 – 22,115 ordinary 5p shares at 133.50p 1 28 29

87 865 952

Corporate

Governance

Accounts


20. CommitmentsOperating leasesThe Group’s commitments for rental payments under non-cancellable operating leases payable during the year to 31 December 2011 are as follows:

2011 Other Operating leases

€’000

2011 Land and Buildings

€’000

2010Other Operating leases

€’000

2010 Land and Buildings

€’000

Payable:Within one year 47 424 75 444Between one and five years 31 1,413 78 418After five years – 154 – –

78 1,992 153 862

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, two in the UK and one in the Netherlands. The Group also leases two apartments, 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 is held on a rolling three month basis.

The UK office lease was signed in 2007 and was subject to review every five years to take account of any changes in the economic climate. There were two break clauses, one for the Group and one the landlord. Neither party exercised their break clauses falling in 2011, and following negotiations in 2012, the agreement will now run its full term until 2017. No restrictions were imposed by the lease agreement other than a break clause after five years.

The Netherlands office lease has a remaining life of three 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.

21. Contingent LiabilitiesPayments to DirectorsAdditional payments of two times basic salary or fees, (M L Eaton one and a half times), 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 2012 these payments amount to £566,280 (€677,960) for D R Musgrove, £441,720 (€528,880) for C J Foss, £441,000 (€527,954) for G L Heard, £307,890 (€368,598) for M L Eaton, £111,360 (€133,318) for R H R Latham, £65,520 (€78,438) for J M White, £65,520 (€78,438) for A N Brewer.

22. 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 2011 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 2011 55 42

Receivables / (payables) balance at 31 December 2010 44 35

Amounts invoiced by Northern Petroleum Group in 2011:

– project billings under Joint Operating Agreements – 4

– other billings 99 –

Amounts invoiced by Northern Petroleum Group in 2010:

– project billings under Joint Operating Agreements – 14

– other billings 97 –


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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 13.

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.

During the year an amount of €72,000 was paid by a subsidiary for recruitment services to RCM Consulting Limited, a company of which Dr. R W Gaisford is a director. This transaction took place prior to Dr. Gaisford’s appointment as a Non-Executive Director of Northern Petroleum Plc.

In addition there is a further loan to a joint venture, Northpet Investments Limited, which is disclosed in Trade and Other Receivables, note 15.

23. 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 financial risks:

• Creditrisk• Cashflowinterestraterisk• Foreignexchangerisk• Liquidityrisk• Pricerisk

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.

Principal financial instrumentsThe principal financial instruments used by the Group, from which financial instrument risk can arise are as follows:

• Loansandreceivables• Tradeandotherreceivables• Cashandcashequivalents• Shortterminvestments• Tradeandotherpayables

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:

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23. Financial Instruments continuedCredit 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 continued to more closely monitor the performance of its banks. An example of this is that during 2011 the Company’s Dutch subsidiary moved its primary banking relationship to Rabobank, a AA rated bank largely unaffected by the banking crisis. In response to the Eurozone crisis, the Group has also made conscious decisions to both spread its deposits across a wider range of banks and to reduce the amount of Euros it holds.

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 15.

The Group has not historically suffered significantly 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 are 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 or significant losses. 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 €40,337,000 (2010: €30,222,000).

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 focus switched more towards preservation of capital (credit risk, see above). The Group has recently decided to more proactively seek to increase the returns on its cash and this is being supervised by its 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

€’000Total

€’000

2011

Euro 25,781 9,708 35,489

UK Sterling 1,239 697 1,936

US Dollar 2,921 126 3,047

29,941 10,531 40,472

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


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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% (2010: 0% and 2%) 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 2011 been 25% higher (i.e. 0.625%), the Group’s finance income of €335,000 would have been €84,000 higher. Had average interest rates in 2011 been 25% lower, the Group’s finance income would have been €84,000 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.

The 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 2011 1.39 0.87

At 31 December 2011 1.29 0.83

Average for 2010 1.33 0.86

At 31 December 2010 1.34 0.86

Currency exposures The 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 2011 1,239 2,921 – 4,160

At 31 December 2010 5,599 784 – 6,383

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23. Financial Instruments continuedDuring the year the Euro fell in value both against Sterling and the US Dollar by approximately 3%, resulting in an overall foreign exchange gain for the year of €244,000.

Had the Euro fallen by 10% against Sterling and the US Dollar, the gain would have been €813,000. Had the Euro risen by 10% against Sterling and the US Dollar, the loss would have been €813,000. Over the same period the net asset value of the Group’s subsidiaries which have retained Pounds Sterling as their functional currency rose by €527,000 on translation and presentation in Euro. Had Sterling fallen by 10% against the Euro, the fall in their net asset value would have been €1,757,000.

A number of the Company’s subsidiaries use Sterling or US Dollars as their functional currency – with Northpet Investments Limited, the joint venture company through which our 1.25% interest in the Guyane offshore is held moving to US Dollars with effect from 1 January 2011 – so movements in the Euro / Sterling and Euro / US Dollar exchange rates most significantly affect 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. Following the Zaedyus-1 discovery well offshore Guyane, as referred to earlier, the Group is now expected to have more significant US Dollar capital expenditure requirements going forward. As a consequence of all of the above, exchange gains or losses will continue to be reported within future income statements.

As a consequence of the above, few significant foreign currency dealings were therefore required during 2011. Going forward the Group will have a greater requirement to exchange currency on a more regular basis, especially from Euro to US Dollar. Indeed, and partly as a response to the current Eurozone crisis and the Board’s concern over the longevity of the Euro, 2012 to date has seen the Group exchange a significant amount of Euros into US Dollars, and to a lesser extent, Sterling.

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 and forecasts for 2012–2013 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 (€29.8 million) and other working capital balances (€1.5 million), giving a working capital position totalling approximately €31.3 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, especially given additional Netherlands production is anticipated to be brought on stream in 2013. Production levels are also deemed sufficient that the Group also has the possibility of entering into a reserve 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 2011 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 2011 been 20% higher, the Group’s gas revenue of €23,070,000 would have been €4,614,000 higher. Had average gas prices in 2011 been 20% lower, the Group’s gas revenue would have been €4,614,000 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 57.332 on 31 December 2011 and 58.475 on 31 December 2010. The index was 59.283 on 7 April 2012 and 62.432 on 7 April 2011. 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 2012 and beyond given the Group’s current cash flow, which will be further supplemented as more Netherlands’ based production comes on stream in 2013 and beyond.


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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

2011

Euro 2,891 5,822

UK Sterling – 388

Other – 67

2,891 6,277

2010

Euro – 3,855

UK Sterling – 2,459

Other – 12

– 6,326

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 17.

Fair 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 19 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 at the appropriate time 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.

24. Post Balance Sheet EventsSince the balance sheet date 31 December 2011 and the date that these financial statements have been signed, no developments have been announced which have a material impact on, or the understanding of, these financial statements.

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Volumes – GroupTotal

Oil Gas Petroleum

Millionbbl bcf

Millionboe

At 31 December 2010: 70.82 108.06 89.45Changes during the period:Upon licence expiry (1.29) – (1.29)Revisions of previous estimates (7.79) (24.58) (12.03)Production (0.03) (3.21) (0.58)At 31 December 2011 61.71 80.27 75.55

Volumes and categorisation by location – GroupTotal

Oil Gas Petroleum

Millionbbl bcf

Millionboe

At 31 December 2011:Proven reserves 3.80 61.67 14.43Probable reserves 57.91 18.60 61.12

61.71 80.27 75.55

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

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 2011:Proven reserves 0.63 – 0.63 3.17 61.67 13.80 – – –Probable reserves 3.72 – 3.72 1.03 18.60 4.24 53.16 – 53.16

4.35 – 4.35 4.20 80.27 18.04 53.16 – 53.16

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

Unaudited Statement of Net Commercial Oil & Gas Reserve Quantities – Proven and Probable Reservesat 31 December 2011

Corporate

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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. Markwells Wood (PEDL 126) proven and probable reserves are the Group’s most recent estimates as announced within the Group’s 2011 Report & Accounts dated 7 June 2012, which supersede reserves as determined during 2010 by RPS Energy. Otherwise the Group’s proven and probable reserves in the UK at year end are 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 12 to the 2011 Report & Accounts.

3. Brakel, Geesbrug, Grolloo, Ottoland, Papekop and Wijk en Aalburg proven and probable reserves are the Group’s most recent estimates as announced within the Group’s 2011 Report & Accounts dated 7 June 2012, 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 12 to the 2011 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. Waalwijk proven and probable reserves are the Group’s most recent estimates.

5. P12 reserves are as determined by current operator’s most recent estimates.

6. 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.

7. Quantities of oil equivalent are calculated using a gas-to-oil conversion factor of 5,800 scf of gas per boe.

Corporate

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Notes2011

€’0002010

€’000

Fixed assetsIntangible assets 3 2,183 999Tangible assets 4 234 290Investments 5 29,159 16,034Total fixed assets 31,576 17,323

Current assetsDebtors – due within one year 6 23,312 32,477Debtors – due after more than one year 6 – 129

Total debtors 23,312 32,606

Cash at bank and in hand 11,899 16,29535,211 48,901

Creditors: amounts falling due within one year 7 (1,884) (1,645)

Net current assets 33,327 47,256

Total assets less current liabilities 64,903 64,579

Creditors: amounts falling due after more than one year 7 (24) (30)Net assets 64,879 64,549

Capital and reservesCalled up share capital 8 5,855 5,768Share premium 9 12,366 11,501Merger reserve 9 10,289 10,289Special reserve (Distributable) 9 28,583 28,428Special reserve (Un-distributable) 9 – 155Share incentive plan reserve 9 3,020 3,964Profit and loss account 9 4,766 4,444Shareholders’ funds 10 64,879 64,549


These financial statements were approved and authorised for issue by the Board of Directors on 7 June 2012 and were signed on its behalf by:

G L Heard C J FossDirector Director

REGISTERED NO. 02933545

Company Balance Sheetat 31 December 2011

Corporate

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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 €821,000 (2010: loss of €1,363,000).

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 enquiries, 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. The use of the going concern basis of accounting is appropriate because there are 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. Accordingly the Directors 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:

• Leaseholdimprovements–overthetermofthelease• Computerhardwareandsoftware–fourorfiveyears• Officeequipment–fouryears• Motorvehicles–fouryears

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.

Notes to the Company Accountsfor the year ended 31 December 2011

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1. Accounting Policies continuedLease 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 23 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:

• provisionismadefordeferredtaxthatwouldariseonremittanceoftheretainedearningsofoverseassubsidiaries,associatesandjointventuresonly to the extent that, at the balance sheet date, dividends have been accrued as receivable;

• deferredtaxassetsarerecognisedonlytotheextentthattheDirectorsconsiderthatitismorelikelythannotthattherewillbesuitabletaxableprofits 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


2011€’000


2010€’000

Executive salaries including bonus 847 874

Non-Executive fees including bonus 161 152

Compensation for loss of office – 219

Benefits in kind 71 48

Emoluments 1,079 1,293

Details for each Director of remuneration are set out in the tables below. The total remuneration of the highest paid Director was €346,000 (2010: €332,000). This information can also be found on page 42 in the Report on Directors’ Remuneration in the Group’s consolidated financial statements.


Corporate

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Presented in Euro Year ended 31 December 2011 Year ended 31 December 2010

Salaryor fees

€’000Bonus€’000

Otherbenefits

€’000Total

€’000

Salaryor fees€’000

Bonus€’000

Compen- sation

for loss of office

€’000

Otherbenefits

€’000Total

€’000

Executive Directors (salaries):M L Eaton* 61 – 3 64 – – – – –

C J Foss 245 – 11 256 247 – – 11 258

G L Heard 227 – 10 237 230 – – 9 239

D R Musgrove 314 – 32 346 317 – – 15 332

N Wright – – – – 80 – 219 2 301

Non-Executive Directors (fees):A N Brewer 41 – 5 46 42 – – 3 45

R W Gaisford 12 – – 12 – – – – –

R H R Latham 64 – 7 71 65 – – 6 71

J M White 44 – 3 47 45 – – 2 47

1,008 – 71 1,079 1,026 – 219 48 1,293


On the exercise of the Company’s warrants during the year the Directors made aggregate notional gains of £10,916 (€12,578) (2010: £582,000, €645,000); the highest single gain made by an individual Director was £10,916 (€12,578) (2010: £333,000, €370,000).

3. Intangible Fixed AssetsComputer

software€’000

Cost:

At 1 January 2011 999

Additions 1,184


Depreciation:

At 1 January 2011 –

Charge for the year –

At 31 December 2011 –

Net book value:


The additions of €1,184,000 above comprise software and implementation costs for a new IT system. The first IT system modules went live in March 2012 and therefore no depreciation has been charged in 2011 (2010: Nil). The final forecast cost of the IT system is approximately €3.0 million, including the future implementation of budgeting, forecasting and contract management software.

Corporate

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4. Tangible Fixed Assets


€’000

Computer and office equipment

€’000

Motor vehicles

€’000Total

€’000

Cost:

At 1 January 2011 303 651 36 990

Additions – 95 – 95

At 31 December 2011 303 746 36 1,085

Depreciation:

At 1 January 2011 254 443 3 700


At 31 December 2011 302 537 12 851

Net book value:

At 31 December 2011 1 209 24 234

At 31 December 2010 49 208 33 290

5. InvestmentsUnlisted


Investments insubsidiaries

€’000

TotalInvestments

€’000

Cost:

At 1 January 2011 15 16,019 16,034

Additions – 13,125 13,125

At 31 December 2011 15 29,144 29,159

Carrying value at 31 December 2010 15 16,019 16,034

During 2011 further investments were made in Northern Petroleum (UK) Limited to increase the capitalisation of the company, in NP Offshore Holdings (UK) Limited to ultimately fund the drilling of the Zaedyus-1 well offshore Guyane and in NP Oil and Gas Holdings Limited to fund working capital.

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

Northern Petroleum (GB) Limited England & WalesOil and gas exploration


of £1–100%

Northern Petroleum (UK) Limited England & WalesOil and gas exploration

and production ItalyOrdinary shares

of £0.001–100%

NP Offshore Holdings (UK) Limited England & WalesHolding company andoil and gas exploration UK

Ordinary sharesof £1–100%

NP Oil & Gas Holdings Limited England & Wales

Holding company and oil and gas exploration


of £1–100%

Northern Petroleum E&P Holdings Limited England & Wales Oil and gas exploration Italy

Ordinary sharesof £0.0025–97.89%

The Company has accounted for its investments in subsidiaries at cost, less any amounts written off.


Corporate

Governance

Accounts


Included in the above are the Company’s interests at the year end in the following associated undertakings:



of operation


shares held

Oil & Gas Investments Limited England & Wales Oil and gas exploration UKOrdinary shares

of £1–41.32%

The Company has accounted for its investments in associate undertakings at cost, less any amounts written off.

6. Debtors 2011

€’000 2010€’000

Trade debtors 560 272

Other debtors 161 15

Loan 155 –

VAT recoverable 190 200

Amounts due from subsidiary undertakings 21,983 31,625

Prepayments and accrued income 263 365

23,312 32,477

Loans – due in greater than one year – 129

Total debtors 23,312 32,606

7. Creditors

2011€’000

2010€’000

Amounts falling due within one year:

Trade creditors 856 232

Taxation and social security 335 133

Accruals and deferred income 693 1,280

1,884 1,645

Amounts falling due after one year:

Trade and other creditors 24 30

1,908 1,675

8. Share Capital 2011

€’000 2010€’000

Authorised:


Allotted, issued, called up and fully paid:


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 2011 are as disclosed in note 19 of the Group financial statements.

Corporate

Governance

Accounts


8. Share Capital continuedAnalysis of changes in share capital during the year:

2011€’000

2010€’000

At 1 January 5,768 4,983

Shares issued for cash as a result of exercise of warrants 86 43

Shares issued to staff in lieu of salary payments 1 27

Shares issued for cash as a result of placing – 715

At 31 December 5,855 5,768

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:

7 January 2011 – 37,500 ordinary 5p shares at 67p 2 27 29

15 February 2011 – 17,500 ordinary shares at 67p 1 13 14




30 March 2011 – 892,500 ordinary shares at an average of 55p 51 504 555

30 March 2011 – 18,600 ordinary shares at 68.5p 1 13 14


1 July 2011 – 150,000 ordinary shares at 66p 8 102 110

29 July 2011 – 250,000 ordinary shares at 31.25p 14 75 89

18 October 2011 – 50,000 ordinary shares at 68p 3 36 39

Issued to staff in lieu of salary payments:

31 January 2011 – 22,115 ordinary 5p shares at 133.50p 1 28 29

87 865 952

9. ReservesShare

premiumaccount

€’000

Mergerreserve

€’000

Specialreserve

(distributable)€’000

Specialreserve

(undistributable)€’000

Shareincentive

plan reserve€’000

Profitand lossaccount

€’000

At 1 January 2011 11,501 10,289 28,428 155 3,964 4,444

Share-based payments – – – – 199 –

Transfer between reserves for share warrants exercised during the year – – – – (1,143) 1,143

Issue of shares during the year 865 – – – – –

Transfer between special reserves – – 155 (155) – –

Loss for the year – – – – – (821)

At 31 December 2011 12,366 10,289 28,583 – 3,020 4,766

The merger reserve is explained in the text below the Statement of Changes in Equity within the Group financial statements.


Corporate

Governance

Accounts


10. Reconciliation of Movement in Shareholders’ Funds

€’000

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 1 January 2011 64,549

Issue of shares during the year 952

Loss for the year (821)

Share-based payments 199

Shareholders’ funds at 31 December 2011 64,879

11. CommitmentsOperating leasesThe Company’s annual commitments for rental payments under non-cancellable operating leases payable during the year to 31 December 2011 are as follows:

2011 Other

operatingleases €’000

2011Land and Buildings

€’000

2010 Other

operatingleases €’000

2010Land and Buildings

€’000

Leases expiring:

Within that year 6 4 33 306

Within the second to fifth years inclusive – – 6 143

In more than five years – 308 – –

6 312 39 449

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 and was subject to review every five years to take account of any changes in the economic climate. There were two break clauses, one for the Group and one the landlord. Neither party exercised their break clauses falling in 2011, and following negotiations in 2012, the agreement will now run its full term until 2017. No restrictions were 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 (M L Eaton one and a half times), 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 2012 these payments amount to £566,280 (€677,960) for D R Musgrove, £441,720 (€528,880) for C J Foss, £441,000 (€527,954) for G L Heard, £307,890 (€368,598) for M L Eaton, £111,360 (€133,318) for R H R Latham, £65,520 (€78,438) for J M White, £65,520 (€78,438) 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 2011 and the date of these financial statements which have a material impact on, or the understanding of, the financial statements of the Company.

Corporate

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Accounts


NOTICE IS HEREBY GIVEN that the Annual General Meeting of the Company will be held at Skinners’ Hall, 8½ Dowgate Hill, London, EC4R 2SP on 29 June 2012 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 2011.

2. To re-appoint KPMG Audit Plc as auditors and to authorise the Directors to fix their remuneration.

3. To re-elect G L Heard (who retires from office in accordance with Article 108 of the Company’s Articles) as a Director of the Company.

4. To elect Dr R W Gaisford (who retires from office in accordance with Article 113 of the Company’s Articles) as a Director of the Company.

5. To elect M L Eaton (who retires from office in accordance with Article 113 of the Company’s Articles) as a Director of the Company.

6. 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 £1,192,075 (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:

7. 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 £476,830 (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).

8. 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 4,768,300, 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

Governance

Accounts


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 2012 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

Corporate

Governance

Accounts


Notes

Corporate

Governance

Accounts


Form of Proxyfor use by members at the Annual General Meeting to be held on 29 June 2012

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 2012 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 2012 as follows and otherwise as he / she shall think fit:

For Against Vote withheld

Ordinary Resolutions:

1 Receiving of Report & Accounts

2 Re-appointment of KPMG as auditors

3 G L Heard as Director

4 Dr R W Gaisford as Director

5 M L Eaton as Director

6 Authority to allot

Special Resolutions:

7 Authority to allot

8 Authority to make market purchases of own shares

Signed Dated

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 2012.

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.

#

Neville Registrars LimitedNeville House 18 Laurel LaneHalesowenWest Midlands B63 3DA

Fold 2

Fold

1

Fold 3 & tuck in

PLEASE AFFIX

POSTAGE STAMP HERE

Corporate

Governance

Accounts

53.16 million*Oil million bbl: Net probable reserves 53.16 Total net reserves boe: 53.16* 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 The Netherlands see p16

For more information on Northern’s operations in the UK see p19For more information on Northern’s operations in Italy see p23 For more information on Northern’s operations in Guyane see p21

Licence Status Interest OperatorOnshore – ExplorationPo ValleySavio Permit 80.00% NorthernLongastrino Permit 30.00%* NorthernLa Sacca Permit 100.00% NorthernPunta Marina Permit 100.00% NorthernCascina Alberto Application 100.00% NorthernOffshore – Exploration

Sicily Channel, West of Sicily Thrust BeltG.R17.NP Permit 45.00%** NorthernG.R18.NP Permit 45.00%** NorthernG.R19.NP Permit 45.00%** NorthernG.R20.NP Permit 30.00%** NorthernG.R21.NP Permit 30.00%** NorthernG.R22.NP Permit 30.00%** NorthernD362C.R-.NP† Application 100.00% NorthernD21G.R-.NP Application 100.00% NorthernD25G.R-.NP Application 100.00% NorthernD26G.R-.NP Application 100.00% NorthernSicily ChannelC.R146.NP Permit 100.00% NorthernD351C.R-.NP Application 100.00% NorthernSicily Channel Offshore SicilyD347C.R-.NP Application 100.00% NorthernD358C.R-.EL Application 50.00% PetrocelticD29G.R-.NP Application 50.00% NorthernD30G.R-.NP Application 100.00% NorthernIonian Sea, Offshore Sicily D63F.R-.NP Application 100.00% NorthernD77F.R-.NP Application 100.00% NorthernD75F.R-.NP† Application 100.00% NorthernD78F.R-.NP† Application 100.00% NorthernSouthern AdriaticF.R 39.NP Permit 85.00%^ NorthernF.R 40.NP Permit 85.00%^ NorthernD149D.R-.NP Application 100.00% NorthernD60F.R-.NP Application 100.00% NorthernD61F.R-.NP Application 100.00% NorthernD65F.R-.NP Application 100.00% NorthernD66F.R-.NP Application 100.00% NorthernD71F.R-.NP Application 100.00% NorthernD72F.R-.NP Application 100.00% Northern

* 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

9 Offshore permits20 Offshore applications

4.35 millionOil million bbl: Net proven reserves 0.63; Net probable reserves 3.72 Total net reserves boe: 4.35

Exploration phase

Licence Interest* OperatorOffshore – ExplorationGuyane EEL 1.25% Shell

* 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 126 50.00% NorthernPEDL 155 50.00% NorthernPEDL 233 50.00% ProvidencePEDL 240 62.50% NorthernPEDL 256 50.00% NorthernOffshore – ExplorationP1916 62.50% NorthernOnshore – ProductionPL211 (Horndean Oilfield) 10.00% Star EnergyPEDL 070 (Avington Oilfield) 5.00% Star Energy

United Kingdom9 Exploration and production licences2 Producing oil fields

Guyane

Where We Operate: Licences and Applications

18.04 millionOil million bbl: Net proven reserves 3.17; Net probable reserves 1.03 Gas bcf: Net proven reserves 61.67; Net probable reserves 18.60 Petroleum million boe: Net proven reserves 13.80; Net probable reserves 4.24 Total net reserves boe: 18.04

Licence Status Interest OperatorOnshore – Exploration Engelen Licence 60.00% NorthernOosterwolde Licence 60.00% NorthernUtrecht Licence 60.00% NorthernAndel V 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 V (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, 3Dtwo / 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.

$US dollar

AGMAnnual General Meeting

AIMAlternative Investment Market of the London Stock Exchange

APIAmerican Petroleum Institute

AzimuthAzimuth Limited

Barrels of oil equivalent (BOE)A term used to summarise the amount of energy that is equivalent to the amount of energy found in a barrel of crude oil. There are 42 gallons (approximately 159 litres) in one barrel of oil, which will contain approximately 5.8 million British Thermal Units (MBtus) or 1,700 kilowatt hours (kWh)

bbl barrel(s) of oil

B, bbillion

bcfbillion cubic feet

bcmbillion cubic metres

BlackwatchBlackwatch Petroleum Services Ltd

boebarrel(s) of oil equivalent

boepdbarrel(s) of oil equivalent per day

bopdbarrel(s) of oil per day

cfcubic feet

cfdcubic feet per day

€ct/m3

Euro cents per metre cubed

DBSDeferred Bonus Scheme

DyasDyas B.V.

EBNEnergie Beheer Nederlandse B.V.

EBITDAEarnings Before Interest, Taxes, Depreciation and Amortisation

ENIEni SpA

EUEuropean Union

FPSO Floating Production and Storage Offloading Vessel

FRSFinancial Reporting Standard

GAAPGenerally Accepted Accounting Practice

Guyane EELGuyane Maritime Permit

HSEHealth, Safety and the Environment

IASInternational Accounting Standards

IFRSInternational Financial Reporting Standards

km, km²kilometre, square kilometres

KPIKey Performance Indicator

KPMGKPMG Audit Plc

m metres

MMBBLmillion barrels

MMBO million barrels of oil

MMBOEmillion barrels of oil equivalent

mmcfdmillions of cubic feet per day (of gas)

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

Net to NorthernNorthern Petroleum’s share

Normal cubic metreMetric expression of gas volume at European standard conditions for temperature and pressure.

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.

PetroCanadaPetro-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.

ProvidenceProvidence Resources (GB) Limited

RPSRPS Energy

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

ShellShell E&P France SAS

scfstandard cubic feet

Star EnergyStar Energy Group plc

million stbmillion Stock Tank Barrels

T, ttrillion (10^12)

the CompanyNorthern Petroleum Plc

TotalTotal E&P Guyane Francaise SAS

TSRTotal shareholder return

TullowTullow Oil Plc

UITFUrgent Issues Task Force

Unconventional energyUnconventional reserves can be defined as reserves which are not commercially recoverable at current prices using conventional technology being situated in rocks of low permeability, which makes the oil gas difficult to access.

WessexWessex Exploration

Working interestRefers to investment in oil and gas drilling operations in which the investor is directly liable for a portion of the ongoing costs associated with exploration, drilling and production and participates on an agreed basis in the profits of any successful wells.

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