Annual Report - FINAL DRAFT - Cabot Energy Plc · 4 Northern Petroleum Plc Annual Report and Accounts 2014 Chairman’s Statement Farm out negotiations immediately began for the onshore

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Northern Petroleum Plc

Production led growth

Northern Petroleum is an oil and gas exploration and production company quoted on the AIM Market of the London Stock Exchange. The Group is focused on production and development activities which are expected to deliver cash flow and demonstrable value for shareholders in a reasonable timeframe. In conjunction with this production activity, Northern Petroleum continues to mature exploration and appraisal projects which can be farmed out and drilled in order to generate the possibility of very high returns on investment. Northern Petroleum’s key assets are in Canada, an onshore oil production play with significant growth potential, and in Italy, with both onshore and offshore permits and applications containing exploration prospects and discovered oil fields.

Introduction

01 Highlights

02 Investment Case

03 At a Glance

04 Chairman’s Statement

Strategic Report

05 Chief Executive Officer’s Statement

07 Key Performance Indicators

08 Review of Operations

12 Risk Management and Principal Risks

14 Group Financial Review

Governance

16 Board of Directors

17 Corporate Governance Report

19 The Health, Safety and Environment Committee

20 The Audit Committee

21 Report on Directors’ Remuneration

25 Directors’ Report

27 Directors’ Responsibilities in respect of the Annual Report and the Financial Statements

Financial Statements

28 Independent Auditor’s Report

29 Consolidated Statement of Profit or Loss

30 Consolidated Statement of Other Comprehensive Income

31 Consolidated Statement of Financial Position

32 Consolidated Cash Flow Statement

33 Consolidated Statement of Changes in Equity

36 Notes to the Accounts

77 Unaudited Statement of Net Commercial Oil & Gas Reserve Quantities – Proven and Probable Reserves

78 Company Balance Sheet

79 Notes to the Company Accounts

Information

86 Glossary

87 Directors, Offices and Advisers

88 Licence Table

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Northern Petroleum Plc Annual Report and Accounts 2014 1

Highlights

Health, Safety and Environment Financial

The Group maintained a record of no lost time incidents despite having the most active drilling year in the Group’s history

Three HSE audits and inspections conducted during drilling and production operations in Alberta

Continuing improvement seen in operational HSE during the year

Markwells Wood site safely maintained without issue until the sale of the asset in October 2014

Cash on the balance sheet at the year end was $12.1 million (31 December 2013: $35.8 million)

Capital investment in Canada of $21.4 million

Production sales revenues of $2.7 million (2013: $0.8 million)

Sale of the UK assets for £1.5 million in cash

Loss attributable to shareholders of $43.0 million (2013: $39.3 million) reflecting $35.6 million impairment of capitalised costs relating to French Guiana and Canada

Change in the Group’s presentational currency to US dollars

Operational Board and Governance

In Alberta, drilling operations started in January and production started in April

Five wells drilled and one recompleted during the year

Award of two new permits in Italy, one onshore and one offshore

UK assets sold including transfer of Markwells Wood well Restructuring of the Group to significantly reduce cost base in

line with prevailing oil price environment Farm out of Italian permit to Shell Italia post year end to realise

$0.9 million in cash and a future work programme carry

Commitment to best practice governance commensurate with Group activity

Continual review of Group costs in light of commodity price volatility

Reduction of the Board from six to four members following the retirement of one Executive and one Non‐executive Director

To be a focused exploration and production company, achieving material growth, with a respected reputation

>> Strategic Reportpages 5 – 15

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2 Northern Petroleum Plc Annual Report and Accounts 2014

Investment Case

The investment focus for Northern Petroleum is on redevelopment projects which provide production, with demonstrable value, and a portfolio of higher return appraisal opportunities and exploration prospects.

The Strategy

The Group’s strategy is to build upon production and generate cash flow to create a sustainable and growing business. High return appraisal and exploration projects are then matured alongside to give shareholders exposure to opportunities with significant growth potential.

1 2 3 Production led growth Capital discipline Exploration and appraisal upside The primary growth of the business through production provides stability within the Group, reduces risk and is more within management’s control. The net cash flow contributes to funding the Group’s overhead to enable the progression of other areas of the business.

As a small Group, financial resources are limited. The forecast rates of return and payback periods on all projects need to be evaluated on an equal basis, to ensure they contribute to the overall growth of the business at the appropriate level of risk.

The Group’s exploration and appraisal assets have the ability to produce significant returns to shareholders upon successful monetisation. The portfolio has large growth potential with exploration prospects both onshore and offshore, which include undeveloped oil discoveries. External capital, which includes farming out licences, will be required for further material development.

The Business Model

The simple business model is aimed at creating sustainable growth.

A sustainable source of cash flow with growth potential is fundamental to demonstrating the Group’s value and underwriting its other activities.

The management of capital and monitoring of costs against revenue ensures that the business maximises its efficiency and is robust throughout the volatile cycles of the sector.

A meaningful return for shareholders over a reasonable timeframe is the overall objective and requires a balanced portfolio of assets and projects to mitigate the inherent risks of the industry.

Cash Flow Investor

Return

Capital

Management

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At a Glance Canada – production and development

The Keg River carbonate reef redevelopment project in north west Alberta is targeting production from more than 80 million barrels of light oil remaining in place in the 30,000 acres owned by the Group. The reefs on the Group’s acreage produced from the 1960s through to the early 2000s, with significantly lower recovery factors than surrounding areas from similar developments. The opportunity now exists to put the fields back on production targeting areas of unswept oil and benefiting from the potential re‐equilibration of the oil within the reservoirs.

_________ _________ Acres Barrels of oil originally in place

30,000 108 million _________

Recovery factor to date

18%

>> Review of Operations

pages 8 – 9

Italy – exploration and appraisal

>> Review of Operations >> Licence Table pages 10 – 11 page 88

The Group owns five permits onshore and offshore and a large area of applications in the Adriatic, an area of recent interest by the industry following the licencing rounds in Croatia and Montenegro. The Adriatic permits contain the Giove undeveloped oil discovery with 26 million barrels of 2C contingent resource, and the potentially significant Cygnus exploration prospect. Onshore, the Group has recently farmed out its Cascina Alberto permit to Shell Italia, who will operate the permit through the exploration work programme. Building and maturing a broad collection of exploration and appraisal assets in Italy will provide opportunities to create value for the Group and its shareholders. Italy’s proven hydrocarbon potential is very attractive to the industry at this time.

_________ _________ Contingent oil resource (barrels) Onshore partner

30 million Shell Italia _________ _________ Permits Applications

5 9 Other

Australia – exploration Large acreage position in the Otway basin primarily targeting an unconventional oil and gas play, currently available for farm out.

French Guiana – exploration Contains the Zaedyus oil discovery and additional prospects within a large deepwater exploration licence. Monetisation of the interest is currently being considered.

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Chairman’s Statement

Farm out negotiations immediately began for the onshore Cascina Alberto permit and concluded early in 2015 with an excellent transaction with Shell Italia. The Italian exploration and appraisal assets remain a key component of the growth potential of the Group and, with a positive change in the business environment in Italy now underway, the ability to unlock this potential becomes more tangible. The divestment of our onshore UK position is part of our strategy to focus on areas of the portfolio which can provide material growth for the Group. With the negative investor sentiment to the oil and gas industry, the current ability to attract capital into the sector is limited. The deployment of existing financial resources has to be primarily for investments which can produce a return in the short term. Boosting internally generated cash flow through the optimisation of existing production and development opportunities continues to be a focus for the management team this year. As demonstrated by the farm out to Shell Italia in Italy, industry transactions are still possible in this environment and can be a valuable source of external capital, without which the Group currently has limited ability to materially progress its existing assets. The Group’s asset portfolio contains opportunities which are of interest to other operators and efforts will continue to be made to manage these assets to support the financial objectives of the Group, whether through farm out or other forms of monetisation. In 2014 we announced the departure of Graham Heard from the Board. Graham has been a stalwart of the Group for many years and, during his time with Northern Petroleum, he contributed significantly towards creating an asset portfolio that has the potential to deliver value and cash flow for shareholders. The decision at this time is not to replace Graham on the Board, although this will continue to be reviewed in the future in conjunction with the needs of the business. In addition, Stewart Gibson retired from the Board early in 2015 as a result of the need for the Group to manage costs throughout all areas of the organisation, and while this decision was prudent, it is with regret that we lose Stewart’s skill and experience. On behalf of all our shareholders I thank Stewart for his contribution to making the business stronger for the future. Despite low oil prices we are confident that we have taken necessary steps to ensure we continue to add value across our existing portfolio and have not compromised our ability to identify and secure opportunities for growth. Our production led growth strategy remains the basis for a positive future. The challenges the Group faced towards the end of 2014 are set to continue in 2015, but we have adjusted our costs and operational focus to meet these challenges head on. I thank our staff and shareholders for their support during a year of transformation and I look forward to continued support as we focus on the development of production that will lead the Group to sustainable growth and the creation of real value.

Jon Murphy Chairman

17 April 2015

Summary The Group is better positioned to recognise and

pursue value creation opportunities during a period of uncertain and volatile commodity prices

Work continues with the appropriate authorities to unlock the value potential of our assets in Italy

The Group’s existing portfolio will be managed to generate capital to develop and advance our core assets

“Given the new oil price environment, the reduction of operating costs to maximise economic production and internally generated cash flow is the focus for 2015, which will help achieve breakeven and fund the Group beyond the end of 2016.”

As Chairman of Northern Petroleum my statement this year outlines the progress of the production led growth strategy and the steps taken to ensure the Group maintains an appropriate operating capability in the current economic climate without compromising the opportunity for a successful future. The Board recognise the challenges that the current oil price environment creates and has taken action to mitigate these challenges. The collective experience of the management team, which has been through more than one previous cycle of low commodity prices, enables us to manage financial resources and deploy technical skills in support of short term stability and the mid to long term growth of the business. New initiatives focused on cost control were started in 2014 and continue into 2015 as we make strategic and operational decisions that protect the Group’s future. The commodity price affects our partners, our competitors, host governments and the supply chain and in so doing creates opportunity for those companies who have taken positive steps to deal with this oil price environment. I am confident we have taken the necessary actions to make us stronger and therefore better positioned to take advantage of appropriate opportunities. Production and drilling operations during 2014 were driven by our production led growth strategy. In Canada we completed six wells and, despite varying results, stable production at the year end was 275 bopd with a peak of over 500 bopd reached towards the end of December. The ability to grow production and generate internal cash flow is especially important in the current economic environment. In Italy activity was focused on securing the necessary approvals for our planned work programme in the southern Adriatic and the Group was awarded two new permits, one onshore and one offshore.

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Chief Executive Officer’s Statement

The results of the three wells drilled in the second half of the year were mixed, with one well testing at more than 1,000 bopd, one at 20 bopd and the third proving to be swept with water. The high rate well was tied in to the existing local infrastructure and, combined with the original three wells, allowed production to peak at more than 500 bopd just before the end of the year. However, the declining oil price postponed further capital investment to tie in the three original wells due to a much longer investment payback horizon. The key uncertainty with the three wells drilled in the second half of the year proved to be the ability to correctly identify the top of the reservoir from interpretation of the seismic prior to the wells being drilled. This, in conjunction with the impact of water injection into other reefs on reservoir sweep, led to the poor results of two of the wells. These well results were added to the increasing database and integrated before the drilling of a further well early in 2015. The result was that the top reservoir came in where expected proving the revised seismic model. On test, the well produced oil at a rate of 90 bopd from a top reservoir section, but with significant amounts of water making the well uneconomic in the current oil price environment. Analysis is underway to determine whether the water was being produced from a separate zone not completely isolated by the cemented liner, or the dynamic nature of the reef system is more complex than previously understood. As part of the year end process, a reserves report for the Virgo asset was commissioned using GLJ Petroleum Consultants Limited (“GLJ”), a reserves auditor based in Calgary. GLJ reviewed four wells, the first three wells and the high rate well from the second phase of drilling. Using current oil prices they assigned proved reserves of 144,000 barrels of oil and additional probable reserves of 149,000 barrels of oil to these wells, which generate a net present value at 10 per cent discount rate of approximately Canadian $4 million. This work has been used to evaluate the current tangible asset book value for the Virgo asset and the associated impairment. In Italy, the Group focused its efforts on three areas: the Cascina Alberto permit onshore in the north and the offshore exploration permits in both the Sicily channel and the southern Adriatic. The recently completed farm out of Cascina Alberto to Shell Italia was a great success for the Group, especially as the permit was only awarded in July. In the Sicily Channel, following the award of permit C.R149.NP, also in July, the Group has joined forces with Schlumberger and GEPlan Consulting, an Italian petroleum consultancy group, to undertake a joint study covering a large area of the Streppanosa Basin which includes the Group’s contiguous exploration permits, C.R146.NP and C.R149.NP. Northern Petroleum and GEPlan will provide technical data and support to a petroleum system modelling study to be carried out by Schlumberger, with the objective of promoting and high grading the area for exploration. There has been limited opportunity to discuss ongoing activities in the southern Adriatic without tangible evidence of progress in relation to the application to undertake a 3D seismic survey across the Giove oil field and Cygnus exploration prospect. Continuous communication and regular meetings were held throughout 2014 with regulatory and political representatives to further this application. Progress has been made and the final approval is currently being reviewed by the regulator.

Summary

Focus on production led growth brings a successful production start up in Canada

The operating environment is ever more challenging as a result of significant reduction in oil price combined with complex subsurface results

Progress in Italy with new exploration permits awarded and a farm out deal with Shell Italia negotiated

Focus on reducing costs and realising capital from existing assets to help fund the Group and develop projects beyond 2016

“The Group is now structured to have a low running cost while retaining the technical ability to resolve the issues with the Virgo asset and build a suitable development plan, along with pushing forward our Italian assets to realise the significant value that these contain.”

A year of contrast 2014 proved to be a year of contrast for Northern Petroleum. Five wells were successfully drilled in Canada and a further well recompleted; more well activity than the Group has ever undertaken previously. However, a rapidly changing macro environment that included a greater than 50 per cent reduction in the oil price after the Group business plan had been developed and approved has led to a rethink of planned activity for 2015. Making tangible progress in the environment created by the oil price change, combined with the results of some of the wells, has proved difficult and has meant that the Group has needed to adapt throughout the year and into 2015. This has included the requirement to reduce the size of the Board and staff and to continue the process of asset rationalisation and focus for the business, most notably with the sale of the UK assets. Progress across the Italian assets has been made as a result of a lot of work behind the scenes to ensure that all governmental requirements can be met. Continuous dialogue with industry partners has kept them appraised of the issues and the progress achieved. This has continued into 2015 and I expect further activity reflecting the increased industry interest in the region.

Operational progress Early in the year, the Group started proof of concept work in the Virgo area of north west Alberta, aiming to redevelop Keg River carbonate reefs with low recovery factors, using workovers of existing wells and the drilling of new wells. The positive results of the first three wells resulted in a redevelopment programme being initiated with the expectation that the year end exit production rate of the Group would be greater than 500 bopd. The three initial wells were placed on production using rental equipment with the fluids trucked to the local processing facility, pending tie‐in to the existing infrastructure. This gave stabilised production of greater than 200 bopd at the half year.

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Chief Executive Officer’s Statement continued It is worth noting that this approval is coincidentally being considered at a time when the Italian parliament and senate is approving new environmental legislation, a process which is likely to have a bearing on the timing of Northern Petroleum’s approvals.

Strategy and focus The Group continued to develop the strategy of production led growth through 2014 with the work conducted on the Virgo asset. This, combined with the continuing focus on two key areas, namely Canada and Italy, led to the divestment of the UK asset portfolio during the year. As a result of this and the Netherlands divestment in 2013, the Group started a process of restructuring. This has continued into 2015 and includes staff and contractor reduction as well as a planned move to a smaller and cheaper office in London reflecting the reduced requirements of the Group. It is always a difficult time when companies go through this process and I am very grateful for the work and approach of both the staff that have left the Group and particularly the remaining staff who have continued to work very hard during these uncertain times. The overhead for the Group is now at an appropriate level for better weathering the current storm and also being able to take advantage of any opportunities that may present themselves, particularly if commodity prices start to pick up again. At current commodity prices, the Group’s existing financial resources provide limited scope to materially advance the core assets of the business and may be exhausted by the end of 2016 without the realisation of cash resources through farm out or other monetisation of projects.

Looking forward Production led growth is still the key strategy for the Group. However, as a result of the fall in oil price only one Canadian production well was tied into the existing local third party infrastructure and with the high cost involved in trucking significant amounts of water, the decision was taken to shut in the other wells at the start of 2015. The Group will not produce wells that are currently uneconomic, but through a combination of working closely with suppliers and developing different methods of disposing of water, efficiencies in operating costs can be achieved and production from shut in wells should be able to be brought back on line during 2015. The future programme for the Virgo area will now focus on understanding the dynamic nature of the reservoir sweep such that future well locations can be optimised. It will also establish how to produce and handle significant amounts of water with the lowest possible cost and allow the existing and new wells to be produced at lower oil prices, while still making economic returns for the Group. This will also position the Group well if the oil price starts to increase again. A revised development plan will be established such that the understanding derived during the planning process can be tested early on in the execution of the project. Further drilling operations are not expected to commence until the end of 2015.

With the changes in Italy, exploration and appraisal should take a more prominent role in 2015. The farm out to Shell Italia demonstrates the industry interest in the country and the Group will work hard to attract a farm in partner for the 3D seismic in the southern Adriatic once the permits are approved. There will also be strong interaction with Shell Italia in their role as operator of the Cascina Alberto permit, in order to establish the work programme through to drilling the first exploration well on the permit. With a number of opportunities already available to the Group in Italy, there is also the chance to look at increasing our position in the country, something that is much more attractive with the positive steps being taken by the administration there. More broadly, the fundamental shifts in the industry will also bring other corporate and asset acquisition opportunities. Through the restructuring that has taken place and the expectation of future operating cost reductions to realise greater economic production, the Group is better positioned to take advantage of appropriate opportunities to enhance shareholder value and position the Group well for when there is an improvement in the industry. Until that time, external capital will be needed to materially advance the existing assets and the focus in 2015 will be to generate the required funds from the Group’s existing assets via farm out or other forms of monetisation.

In summary With 2014 being a very tough year in many respects, not least the performance of the oil and share prices, I am looking forward to a better 2015. The change in the oil price has required us to position ourselves to be able to survive first and then grow as the business environment improves. The Group is now structured to have a low running cost whilst retaining the technical ability to understand the future potential of the Virgo asset and build a suitable development plan, along with pushing forward our Italian assets to realise the significant value that these contain.

Keith Bush CEO

17 April 2015

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Key Performance Indicators The Group measures the Key Performance Indicators it believes are important in assessing performance against strategic objectives. Financial and non‐financial metrics are tracked across the Group to help manage the long‐term performance and achieve the strategy and implement the business model.

Health, Safety and Environment Finding and Development Costs

Exploring for and producing hydrocarbons requires the highest standards of Health, Safety and Environmental management to ensure that no stakeholders are adversely affected by the Group’s activities and the environment in which operations occur is protected to minimise the impact of activities.

In 2014 the operational activities of the Group were centred on the Virgo region in Canada and comprised a diverse range of well and facilities activities. All were performed without any harm to our staff and contractors and with minimal impact to the environment. The overall HSE performance in 2014 was good and the Group recognises that incident prevention continues to be the key to good HSE governance. HSE will remain a key pillar in building a successful business.

Finding and development costs are a key indicator of the performance of the business over the long term as the measure gives the total cost of creating reserves up to the point of production, divided by the number of barrels classified as reserves. The Group includes all the acquisition, exploration and development costs directly associated with assets that are categorised as property, plant and equipment and any costs written off. Historic costs held as intangible assets are not included in this calculation.

The Group’s finding and development cost for 2014 was $66 per barrel. The very high cost per barrel is a result of the start‐up costs associated with new wells developing the Virgo project, the limited reserves allocated only to the production wells at the year end and the fall in oil price reducing the economic cut off for future production.

Reserves and Production Staff Scorecard

The Group’s reserves are an important indicator of the future cash generating ability of the business and therefore its ongoing viability, as well as a key element of the Group’s core value. Reserves growth is also a key indicator of the Group’s success in progressing assets from exploration through to development and production. A Group reserves report was produced by GLJ Petroleum Consultants, an independent expert based in Calgary, Canada, who conducted a review of the Virgo field. The Group has established its first reserves in Canada following the initial drilling and development in the Virgo area in 2014. The total Group 2P reserves as at 31 December 2014 were 0.3 million barrels of oil equivalent, all related to Virgo.

Production rates are a key indicator of the Group’s operational performance through the year and of the quality of the oil and gas assets in production. As the Virgo development and production project was started during 2014, the only production goal to be measured was an exit rate of barrels per day. The Virgo field reached a peak production rate of 507 barrels of oil per day on 27 December 2014. Post year end, certain wells have been shut in resulting from the strategic decision not to tie‐in wells into the local infrastructure due to the current oil price environment.

Appropriate staffing is essential to successfully delivering the Group’s strategy and future growth plans. During the year employees completed a scorecard to give their view on strategy, the growth of the business and shareholder value. The results demonstrate a positive sentiment from the Group employees:

88% understand the strategy and goals of the Group

81% agree the strategy is focused on adding shareholder value

93% are motivated to accelerate growth of the Group

Future years will include a follow up to this survey in order to determine how the perspective of the Group employee’s change as the business develops.

>> Risk Management and Principal Risks

pages 12 – 13

>> The Health, Safety and Environment Committee

page 19

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Review of Operations Canada 2014 Activity The Group’s land position of approximately 30,000 acres over 94 mineral leases in north west Alberta has been established to build a sustainable and growing production base. The redevelopment is a relatively low cost conventional oil play with ready access to infrastructure and an established supply chain enabling product to be brought to market quickly and cheaply in comparison with other oil provinces around the world. The Group’s land position comprises acreage with an estimated 108 mmbbls STOOIP as determined by the Alberta Energy Regulator, with an existing average recovery factor of only 18 per cent to date. The appraisal and development work performed during 2014 has confirmed the concept that recovery factors of approximately 25 per cent should be achievable from the Keg River play with primary recovery and an upside of over 40 per cent may be possible using enhanced oil recovery techniques. During 2014 two drilling campaigns, each of three wells, were undertaken. The first three wells comprised a re‐entry into an existing well (100/14‐22); a new well into a previously undrilled reef (100/16‐19); and a new well into a previously produced reef (102/13‐33). The results from the 100/14‐22 well prove the concept of oil re‐equilibration since when the well was brought back into production, the well had a peak daily rate of 100 bopd with an initial water cut of 40 per cent, an improvement on both measures from when the well was shut in previously in 1991. The results from the 102/13‐33 well support the concept that larger reefs developed with only a single well contain remaining un‐swept oil zones that can be targeted by drilling new wells. The well had a peak daily rate of 260 bopd with an initial water cut of 36 per cent. The result of the 100/16‐19 well, an exploration well, highlighted that structures may exist which have not been identified in the past and provided additional information to assist with the subsurface identification of future well locations. The 100/16‐19 well had a peak rate of 140 bopd of dry oil. The second campaign of three wells drilled during the summer and autumn all targeted unswept zones at the edges of previously produced reefs. The result from the 102/15‐23 well was exceptional, with the well encountering 14 metres of net oil pay and flowing on test at a facilities constrained rate of 1,300 bopd of dry oil. The 100/14‐23 well encountered four metres of net oil pay and produced at a rate of 20 bopd during swabbing, while the 100/1‐27 well encountered an unexpected overpressured and water swept reservoir. Both wells were subsequently suspended without being tested and have been impaired in the accounts while awaiting further evaluation. All six wells provided valuable lessons and prompted a focused subsurface review aimed at delivering similar high performance results as seen by the 102/15‐23 well. The review refined the subsurface understanding, primarily through revised seismic interpretation, well location optimisation with respect to nearby

production wells and the understanding of reservoir sweep behaviour. The results of this multidiscipline review were integrated with the planning of the 2014 / 2015 winter drilling programme. Other activities in the fourth quarter of 2014 concentrated on the installation of the surface facilities and the tie‐in for the 102/15‐23 well, along with well planning for the next drilling phase. The facilities work was completed before Christmas and following the tie‐in of the 102/15‐23 well, production was progressively increased between Christmas and New Year enabling the Group to achieve a total field production rate from all four producing wells of more than 500 bopd. 2015 Activity The planned two well drilling programme in early 2015 was reduced to a single well in a response to the rapidly falling oil price during the last quarter of 2014. The 102/11‐30 well was located down flank of the reef structure in order to investigate the possibility of unswept oil on the reef edge. The well reached the top of the Keg River formation in line with prognosis and encountered the expected reservoir section. When tested the well flowed at 90 bopd, with a water cut of 85 per cent. As a result the well was suspended pending a subsurface and facilities review to determine the source of the water and establish a cost effective method of handling the water. The results of this well and the previous wells drilled in 2014 will be further integrated into a revised subsurface model with the aim of understanding the dynamic nature of the reservoir more clearly. The subsurface study work is expected to be completed during the third quarter of 2015 to be incorporated in a revised development plan. No further wells will be drilled until this plan is completed and ready for execution. In the current reduced oil price environment, the Group also recognises that a reduction in development and production costs will be crucial in delivering an economic project in Alberta. The Group’s year end reserves report illustrates the effects on the economics of producing oil at the prevailing oil prices coupled with last year’s cost structure, which has contributed to the impairment of the Canadian project. Therefore, in conjunction with subsurface work, the Group is conducting a review of operational activities and expenditure during 2015 to maximise production rates and generate positive cash flow. Should the current oil price environment continue, the Group expects to see a continuation in the reduction of operating costs due to downward price pressure on the supply chain coupled with a reduction in rig and associated service industry rates by the second half of 2015. In the meantime the Group is investigating alternative operating strategies for the existing wells commensurate with reducing third party costs and variable operating costs.

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Review of Operations

_________ Revenue ($m)

2.2 _________ Production (bbls)

30,685 1. 100/16‐19 production well

2. Service rig on 100/14‐23

3. Well logging on the 100/1‐27 well

4. Drilling rig on the 100/1‐27 well

1 2

3

4

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Review of Operations continued Italy 2014mActivity The focus of the Group during 2014 was to continue to liaise with industry and governmental authorities in Italy for approval of the environmental impact assessment to allow the acquisition of 3D seismic data to be made on the southern Adriatic permits, F.R39.NP and F.R40.NP, that contain the Giove oil discovery and the Cygnus exploration prospect. Elsewhere the award of the onshore Cascina Alberto permit and offshore C.R149.NP permit in the Sicily Channel demonstrated that the Italian regulatory authorities are providing the support needed for the Group to move forward within Italy. The Giove undeveloped oil discovery has been independently assessed by ERCE to contain a 2C contingent resource of 26 million barrels of oil. The planned 3D seismic survey will assist in locating an appraisal well on the field required to establish a viable development plan. Results of the most recent subsurface analysis indicate that there is potential for improved reservoir properties and a higher recovery factor. The Cygnus prospect remains a high priority within the Group’s asset portfolio and is the primary focus of the 3D seismic survey. Cygnus is a stratigraphic trap, interpreted as having a proximal reservoir sequence to the equivalent distal reservoir sequence that forms the reservoir in the adjacent Aquila oilfield. ERCE's assessment of the prospective resources for the Cygnus prospect assigned 978 million barrels in their high case estimate, using a common oil water contact with the adjacent Aquila oilfield, of which 790 million barrels of prospective resource are net to the Group on the F.R39.NP permit. In the mean case, using a shallower contact and assuming that there is separation of the mapped prospect from the Aquila oilfield, ERCE assigned a prospective resource estimate of 446 million barrels, of which 401 million barrels lie within the permit. ERCE has estimated a chance of success of 12 per cent for the Cygnus prospect. The Group is seeking a farminee to progress the work programme, which will include the acquisition of 3D seismic data across both the Giove oil field and Cygnus prospect that will further enhance the potential to progress with a Giove oil field development and the drilling of a highly attractive exploration well on Cygnus.

Onshore

The Cascina Alberto permit in northern Italy was awarded in July 2014 and is the only permit held onshore. The area was formally held in the late 1990's by Eni as permit Fiume Sesia and was the subject of a farm‐in by Enterprise Oil in 2000 focusing on a prospect called Gattinara that was previously interpreted by Eni as holding a prospective resource of 300 million barrels of oil. The trap is similar to structures such as the Villafortuna‐Trecate field, which is located 25km to the south east. In early 2015 the Group announced a farm out deal with Shell Italia whereby in return for an 80 per cent interest in the licence and operatorship, Shell Italia will carry the Group for a seismic acquisition programme up to $4 million and any single exploration well up to $50 million. Shell Italia will also pay the Group $850,000 on completion of the farm out, which is subject to official sanction by the Italian regulatory authorities.

SicilynChannel Permit C.R149.NP was awarded in July 2014 and is adjacent to and east of C.R146.NP and contains an extension of the Vesta oil prospect. The prospect is interpreted as having the same age reservoir sequence as the on trend Vega oilfield. Permit C.R146.NP is currently held in suspension while an environmental impact assessment to drill an exploration well is processed through the Ministry of Environment. Applications closer to the Sicily coast contain leads similar to the on trend Palma oil discovery and are pending environmental impact assessment approval from Ministry of Environment before permit award. Following the year end the Group announced a joint technical study with Schlumberger and GEPlan. The study will cover a large area of the Streppanosa Basin, which includes C.R146.NP and C.R149.NP, with the objective of promoting and high grading the area for exploration.

Ionian Sea Within application d59F.R‐.NP there are three deepwater gas discoveries Fiorenza, Fedra and Florida drilled in 1982, 1987 and 1999 respectively by Agip S.p.A. The gas discoveries are adjacent to the producing Luna, Hera Lacinia and Linda gas fields operated by Eni. Additional exploration prospects are contained within application d59F.R‐.NP and these together with the existing gas discoveries will be evaluated on the pre‐existing Eni 3D seismic survey once this permit has been awarded.

Geoseismic cross‐section of Cygnus prospect and Giove Oil field

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Review of Operations

French Guiana The Zaedyus oil discovery in 2011 was the first deepwater well in the country. Following this success an extensive 3D seismic acquisition programme was undertaken, covering the deepwater margin and a four well drilling campaign following up on the initial discovery. The new 3D seismic interpretation has demonstrated additional prospects with the potential for stratigraphic traps similar to Zaedyus. Northern Petroleum is now looking at ways to monetise the investment in the licence.

AustraliaThe primary play is for unconventional resources in several shale formations, the Casterton, Sawpit and Eumeralla Formations within the Otway Basin of southern Australia, along with secondary conventional resource target sandstones in the Crayfish Group. Two deep wells drilled by Beach Energy in 2014 on adjacent acreage provide further support for the play concept. The licence is suspended for a year to allow further technical work and evaluation prior to progressing with a seismic programme. The Group is seeking a farminee for the licence.

UK The UK licence portfolio was sold to UK Oil & Gas Investments PLC in October 2014 for a consideration of £1.5 million.

Southern Adriatic permits and applications

__________________________________________________________________________________________________


Risk Management and Principal Risks

Northern Petroleum works in an industry that contains inherent areas of risk that need to be managed appropriately. The Group uses risk management to identify the specific risks that the Group faces and the ways to mitigate those risks. Risk reduction measures are then prioritised through the risk management strategy. Identifying and managing the key risks to the Group are the responsibility of the senior management and Executive Board members. The Board is then charged with monitoring and reviewing the management of these risks.

Health, Safety and Environment

Description Mitigation Major Incident

The processes and operations involved in the exploration for and production of hydrocarbons can be hazardous if not properly undertaken. A major incident such as a blow out or fire at a well site, or a collision or loss of vessel at sea while undertaking seismic operations, may result in harm to personnel, the environment or significant asset damage.

Northern Petroleum has designed and implemented a robust Health, Safety and Environmental Management System that is aligned to the principles of ISO 14001 and OHSAS 18001. The purpose of the management system is to ensure our staff, contractors and all sub‐contractors work to the principles of our HSE policy.

Financial Description Mitigation Liquidity

As a small business, financial resources are limited and significant capital resource is required for the exploration and production of hydrocarbons. A lack of access to sufficient capital could result in the delay or curtailment of operations.

The Group maintains up to date forecasts and modelling of the potential future capital requirements of projects and amends work programmes to match capital resources available. Northern Petroleum will consider all forms of external capital as appropriate to maintain liquidity.

Capital Discipline

Determining the required investment in projects is complicated and constantly changes. Lack of discipline in the application of capital to appropriate projects may result in unnecessary exposure to potentially excessive capital outlay and a high overhead cost structure.

Northern Petroleum only pursues assets which are of an appropriate size and risk in relation to the Group’s resources.

Commodity Price

The price of oil and gas is volatile and beyond the control of the Group. Weak commodity prices will impact negatively on the Group’s cash flow and ability to progress its planned investment programme. Commodity price volatility increases the financial risks associated with medium to long term projects.

The Group will consider the hedging of future production where appropriate and look to develop and maintain lower cost production projects to mitigate falling commodity prices.

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Risk Management and Principal Risks

Technical

Description Mitigation

Subsurface

There is a significant amount of technical risk in exploring for and developing commercial oil and gas fields. Insufficient or the incorrect interpretation of data can lead to the wrong conclusions regarding the subsurface environment.

Robust technical work processes, a full data inventory and technical peer review ensure opportunities are fully evaluated and the subsurface risks are understood as far as possible before investment decisions are made. Lessons learned are developed, communicated and implemented.

Reserves

The estimation of reserves is inherently difficult and requires the subjective opinion of key uncertainties. Inaccurate estimates may result in the over or under valuation of an asset and the incorrect allocation of capital. The incorrect reporting of reserves does not comply with good business practice and would damage the market performance and reputation of the Group.

A reserves review is carried out as part of an annual process. Audits are undertaken in accordance with regulatory standards and industry best practice.

Development and Production Operations


Operations

Development and production operations are complicated as they require the coordination of many different service providers and contractors, some of which are not within the control of the Group. Delays, unplanned shut downs or the failure of infrastructure can lead to the failure to meet production targets and revenue requirements.

All Group developments require robust project planning, a quality management system, appropriate operations and maintenance procedures and operational flexibility with respect to events outside the control of the Group. Only competent contractors are employed.

Political and Other


Political

The oil and gas industry is heavily scrutinised and influenced by the prevailing political leadership in the countries of operation. Regulatory or legislative uncertainty or changes may result in delayed operations and an inability to progress assets in a timely manner or changes in fiscal policy which may negatively affect the profitability or overall economics of a project.

The Group actively engages with government and regulatory bodies in all countries that it works in. British government advice is sought and taken when travelling to new countries and when performing detailed country entry studies. Business is only conducted in countries considered to be relatively stable. Lobbying of government is undertaken through industry bodies and British government agencies.

Corporate Delays

Non‐governmental Groups and organisations may pursue agendas not aligned with shareholder interests and can cause delays or the cancelling of projects.

Engagement with NGOs is conducted in a timely fashion to ensure stakeholder requirements are met where possible.

__________________________________________________________________________________________________


Group Financial Review

Following the consolidation of the Group’s 55.9 per cent interest in Northpet Investments Limited, the French Guiana investment vehicle, the gross impairment charge of $36.3 million shown in the profit or loss account represents 100 per cent of the Northpet interest in the licence, with the non‐controlling interest disclosed separately towards the bottom of the table. Impairment review of the Group’s Canadian development and production project The Group’s biggest investment focus for 2014 has been the development and production project in Virgo, north west Alberta. Activities throughout the year included the acquisition of mineral lease rights, purchase and analysis of 3D seismic and the drilling and workover of six wells. Project wide exploration and analysis costs are capitalised as intangible assets and then allocated proportionately to specific wells when drilled. The drilling of a well is regarded as part of the development and the associated costs are categorised under property, plant and equipment within tangible assets. An impairment exercise was undertaken, in conjunction with the provision of a reserves report by GLJ, to evaluate the project and ensure the ongoing value of the costs capitalised and held as tangible assets reflected the net present value of the forecast net cash flows likely to be derived from production from existing wells. Due to a combination of two of the wells drilled in the second half of 2014 currently being regarded as unlikely to have a positive economic value and the significant drop in oil prices during the year, an impairment of $15.3 million has been charged to the profit or loss account in relation to the Virgo project. Gross profit The gross contribution from Canada for 2014, which when calculated after a $0.8 million depreciation and amortisation charge, was loss making. The initial production strategy used expensive rental production units on the wells to limit capital outlay at the start of production. This contributed to a high level of fixed operating expense which, when combined with planned and unplanned periods of production downtime, led to the erosion of gross profit margin. This was further exacerbated by the trucking of fluids before wells were planned to be tied in. With the drop in oil price, negotiations with service companies have and will continue to help realise production cost savings which should allow wells to be produced with a positive contribution at the gross profit level during 2015. Sale of UK assets In October 2014, the Group completed the sale of all its interests and licences in the UK for £1.5 million. The UK assets and licences comprised the 10 and 5 per cent minority interests in the Horndean and Avington producing fields respectively, 50 per cent interests in the Markwells Wood and Baxters Copse discoveries, and a 65 per cent interest in a licence offshore the Isle of Wight. These assets contributed $494,000 of revenue and $232,000 of gross profit to the Group until the point of sale in 2014. The book value of the UK assets was a liability, giving rise to a profit on disposal, and proven and probable reserves were 60,000 barrels of oil.

Summary Production and revenue established in Canada

Sale of UK assets

Significant impairment charge from the decision to write down French Guiana and certain wells in Canada

Continued reduction in administrative costs

Change of presentational and functional currencies to US dollars

Overview Three issues dominate the financial statements for 2014, the change in the Group’s presentational currency and changes in the functional currencies of certain entities to US dollars, the impairment of the Group’s interest in the French Guiana licence, and the impairment of the Group’s assets in the Virgo development play. Alongside these events, the Group sold its UK assets, which included a small amount of production, and has undertaken a significant restructuring of the Group’s underlying cost base, which has continued subsequent to the year end. Change in presentational and functional currencies In the fourth quarter of 2013 the Group disposed of its Netherlands subsidiary which had previously contributed 95 per cent of the Group’s revenue. In the first quarter of 2014 the Group completed a successful three well proof of concept drilling programme in Canada which resulted in oil production and revenue. Following this success, the Group made the decisions to continue with a significant investment programme in Canada. Given the importance of the US dollar to the global petroleum industry, the anticipated oil revenues derived in US dollars, and the number of different currencies the Group is exposed to for costs, the US dollar is now the most appropriate for the Group to use as its presentational currency. As a result the parent company and one subsidiary have also changed their functional currencies to US dollars. This is further supported by the strategy of the Group to focus on production led growth on a global basis which will also have its costs and revenues linked to the US dollar. Impairment of the Group’s interest in French Guiana As noted in the annual report and accounts for 2013, the full cost for the investment in the French Guiana licence was being carried in intangible assets while the future of the exploration project was being evaluated by the Joint Venture partners. While subsurface analysis is still ongoing any future exploration or appraisal wells are contingent on the satisfactory outcome of this analysis and would most likely require an extension of the licence which expires in mid 2016. With this level of uncertainty concerning future exploration, it has been deemed appropriate to impair the full value of this asset at this time.

__________________________________________________________________________________________________


Group Financial Review

Costs In the first half of 2014, an exercise was undertaken to reduce the Group’s general and administrative costs to an appropriate level, based upon the activity of the Group. Towards the end of the year, given the significant fall in oil prices and the impact this will have on the Group’s forecast revenue, further cost reductions were undertaken, including a planned office move in 2015. The majority of these savings will have a greater impact in 2015 and 2016, having taken into account the one off costs associated with the reduction exercise. Cash and debt Cash at the year end was $12.1 million (2013: $35.8 million). Throughout the year the biggest individual cash investment for the Group, $21.4 million, was the ongoing operations in Canada. Going concern The current ability to attract capital into the oil and gas sector is limited. The deployment of existing financial resources has to be for investments which can produce a return in the short term. The Group has sufficient funds to meet its working capital requirements until the end of 2016, however the material development of existing projects will be contingent on the sourcing of further capital. Boosting internally generated cash flow through the optimisation of operating costs in Canada will help maximise the net contribution to the Group from production to help fund the ongoing business overhead. It is also expected that further capital will become available for investment through the careful management of the Group’s existing assets to achieve farm outs or other methods of monetisation.

>> Financial Results pages 29 – 85

The reported cash balance in US dollars has reduced further due to the considerable strengthening of the US dollar against the currencies of other cash deposits over the period. The total debt outstanding at the year end of $1.3 million was in relation to the Italian government seismic incentive scheme, which is repayable over five years and bears interest at 0.5 per cent per year. At the year end, net current assets were $8.5 million (2013: $34.1 million) and net assets were $39.7 million (2013: $102.8 million). Dividends No dividend is proposed to be paid for the year ended 31 December 2014 (2013: $nil). Accounting policies These financial statements have been prepared by the Board using accounting policies consistent with 2013. There have been no new or revised International Financial Reporting Standards adopted during the year which have had a material impact on the numbers reported. Details of the accounting policies used are included within the accounting policy notes starting on page 36 (Group) and page 79 (Company).

Nick Morgan

Finance Director

17 April 2015

Keith Bush Chief Executive Officer

17 April 2015

This Strategic Report comprises the Chief Executive Officer’s Statement, the Business Model and Strategy, the Review of Operations, the review of Risk Management and Principal Risks and the Group Financial Review, collectively on pages 5 to 15, and is approved on behalf of the Board by

__________________________________________________________________________________________________


Board of Directors

Jon Murphy (3) Independent Non‐executive Chairman Jon was appointed as Chairman in September 2013 and has over 30 years’ of experience in the mid‐cap exploration and production industry. Jon holds a BSc. in Geology from the University of London. His career includes several years with Lasmo plc where he held various positions in geology, planning and new business, and in 1999 he joined Venture Production plc as Chief Operating Officer where he remained until Venture’s sale in 2009. He is currently a Non‐executive Director of Trinity Exploration and Production plc.

Keith Bush (2) Chief Executive Officer Keith joined Northern Petroleum in May 2012 as Chief Operating Officer, was appointed to the Board in November the same year, and was made Chief Executive Officer in July 2013. Keith gained a degree in physics and has over 20 years’ industry experience. Commencing his career with Western Atlas Logging Services, Keith progressed to hold managerial positions in Amerada Hess, Burlington Resources and was most recently employed as General Manager Operations for E.ON Ruhrgas in Norway. Keith has extensive experience in the North Sea, North Africa and Norway.

Iain Lanaghan (1) Independent Non‐executive Director Iain Lanaghan was appointed as a Non‐executive Director in February 2014. Iain is the Non‐executive Chairman of MET and a Non‐executive Director of National Nuclear Laboratory and Kentech Group Limited. He was previously Group Finance Director of Faroe Petroleum plc, spent four years as Group Finance Director of transport operator FirstGroup plc and was a founder of the German bus and rail group Abellio GmbH. He planned the flotation of 3i‐backed Atlantic Power Group and then led its merger with the Norwegian group Petroleum Geo‐Services. He was also Finance Director of PowerGen International. Iain is a chartered accountant, having qualified with KPMG in London.

Nick Morgan (4) Finance Director Nick was appointed Finance Director in November 2012. Before joining Northern Petroleum, Nick spent over 13 years in investment banking where he focused on advising the international E&P industry. He specialised in advising upon mergers and acquisitions and providing equity capital markets advice and services to a broad range of global oil and gas companies, both public and private. He was employed by Tristone Capital, the global energy investment bank, and latterly GMP Securities for six years prior to joining Northern Petroleum. Nick qualified as a chartered accountant at Price Waterhouse and is a member of the Institute of Chartered Accountants in England and Wales.

>> Directors Report pages 25 – 26

__________________________________________________________________________________________________


Corporate Governance Report The Board is committed to high standards of stewardship and governance and aims to create a culture which demands the same commitment and performance in all its business activities. As a result accountability, integrity and honesty are fostered throughout the Group.

The Group is not required to comply with the Principles of Good Corporate Governance and the Recommendations of Best Practice as set out in the principles of the revised UK Corporate Governance Code (the “Code”) published in May 2010 by the Financial Reporting Council and revised in September 2012. While the Group does not comply with all aspects of the Code, in so far as is practicable and appropriate for an AIM quoted company of Northern Petroleum’s size, the business seeks to follow the guidance set out in the Code.

The role of the Board

The Board sets the Group’s strategic objectives and ensures that they are properly pursued and that the major business risks are actively monitored and managed. The Board provides leadership and guidance whilst maintaining responsibility for the sustainable financial performance and long term success of the business.

The Board continued to focus efforts in 2014 on strategic goals which will create shareholder value, monitoring performance against agreed objectives and planning future business opportunities.

Board composition

At 31 December 2014 the Board comprised of six Directors, including Graham Heard who retired at the end of the year. Subsequent to the year end, Stewart Gibson stepped down as a Non‐executive Director. The Board now comprises two Non‐executive and two Executive Directors. The Chairman and second Non‐executive Director are deemed to be independent as defined by the Code.

There is a balanced mix of skills and experience among the Board which enables the Board to effectively debate all strategic, operational and financial issues.

Committees

The Board has delegated certain responsibilities to its Committees in line with recommendations of the Code, to facilitate the business of the Board. These are the Audit Committee and the Remuneration Committee. The duties of these Committees are set out in formal terms of reference approved by the Board. The entire Board bears the responsibilities of Health, Safety and Environment issues.

Key matters reserved for the Board The key matters reserved for the consideration and sanction by the Board are:

approval of Group strategy, long‐term objectives and annual business plan;

approval of the Group’s annual financial statements, interim management statements and changes in the Group’s accounting policies or practices;

changes relating to the capital structure of the Group, material share issues and the Group’s dividend policy;

approval of the annual Group budget and of individual project budgets as required by the Group Delegation of Authority guideline;

review of the Group’s future funding needs and the financial requirements to maintain its going concern status;

major changes in the nature of business operations, including entering new countries, licence applications and new business activities;

material investments and divestments in the ordinary course of business;

adequacy of internal control systems, hedging policy and risk management;

approval of Group policies including the Code of Ethics, Anti‐Bribery and Corruption, Code of Conduct, Health, Safety and Environmental policies;

the creation and approval of terms of reference, chairmanship, membership and delegation of authority to all committees of the Board;

authorisation of potential conflicts of interest of Directors and determining the independence of Directors;

appointments to the Board;

succession planning for the Board and senior management;

the appointment and removal of the Group’s external auditor, corporate brokers and financial advisers;

principal terms and conditions of employment of all Directors;

changes in employee share schemes and other long term incentive schemes;

decisions to prosecute or defend material litigation; and

annual Board, Committee and Chairman appraisals.

__________________________________________________________________________________________________


Corporate Governance Report continued How the Board operates Communication with shareholders

The Board has six scheduled meetings per year and meets annually to discuss the Group strategy. The agenda for each meeting is set by the Chairman in conjunction with the Executive Directors, with Board papers sent to members for consideration prior to the meeting. In addition the Board engages in regular ad hoc telephone calls to keep all members fully briefed on the Group’s operations. The Board believes that one of its strengths is in having open communication channels that enable its members to engage informally on a variety of topics.

The Group’s management has recognised the need for open communication with all its stakeholders and has prioritised the requirement for a clear and consistent message concerning the Group’s performance and operations. Extensive information concerning the Group’s activities is provided in the annual and interim reports which are available to all shareholders. The Board is aware of its reporting responsibilities and ensures that material information is released on a timely basis.

The Group website (www.northernpetroleum.com) provides detailed information on the Group’s activities. In addition, there is regular dialogue with investors and throughout 2014, Executive Directors and senior management attended meetings, presentations and conferences with investors in London and across the UK.

All shareholders are offered the choice of receiving shareholder documentation electronically or in paper format, as well as the choice of submitting proxy votes either electronically or by post.

Enquiries from individuals on matters relating to their shareholding and the business of the Group are welcomed and shareholders are encouraged to attend the AGM to discuss the progress of the Group.

Jon Murphy

Chairman

17 April 2015

Meetings

Board HSE Audit Remuneration

6 6 2 3

Number of meetings attended by

Executive directors Keith Bush 6 6 ‐ ‐ Graham Heard1 6 6 ‐ ‐ Nick Morgan 6 6 ‐ ‐

Non executive directors Stewart Gibson2 6 6 2 3 Iain Lanaghan3 5 5 2 2 Jon Murphy 6 6 2 3

1 Graham Heard stepped down from the board on 31 December 2014 2 Stewart Gibson stepped down from the board on 31 March 2015 3 Iain Lanaghan appointed 13 February 2014

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The Health, Safety and Environment Committee The role of the Health, Safety and Environment Committee

The Health, Safety and Environment Committee provides the necessary resources for the corporate HSE management system and oversee its implementation across all of the Group’s assets. Operations in the field are outsourced to specialist contractors selected through a robust contractor selection process and regularly monitored to ensure they adhere to the corporate Health, Safety & Environmental policies, industry best practice and legal and other requirements in the countries in which we operate.

The Group develops a corporate HSE plan at the beginning of the year which directs the HSE strategy and initiatives for the coming year. A key focus of this plan is the HSE scorecard which is the basis of the groups lagging and leading Key Performance Indicators (KPIs). The plan is approved by the Committee and performance is tracked throughout the year and formally reported to the board on a quarterly basis.

Regular third party audits are scheduled and undertaken in the field to assure the Committee that the systems of both the Group and our main contractors (interfaced accordingly) are managing the HSE risks. These audits are supplemented by regular senior management visits to all operational sites demonstrating a commitment to HSE from the top of the organisation.

In the unlikely event that any of the identified significant HSE risks materialise, robust Crisis Management Plans and location specific incident management plans are in place to ensure the safety of staff and contractors, minimise damage to the environment and assets as well as manage the reputational risks to the organisation.

HSE Committee activities during 2014

During 2014, the following activities took place:

undertook a full and thorough review of the corporate HSE system against the requirements of ISO14001 and OHSAS 18001 environmental and health and safety standards to ensure the system aligns with the principles of the respective standards;

monitored and regularly reviewed the Group operations in Canada with specific HSE reporting systems, incident investigation systems and emergency management plans implemented at each site, interfaced to those of our contractors;

ensured that crisis management and incident response training was given throughout the organisation with the assistance of RPS Group Plc as independent instructors;

monitored developments in legislative and regulatory requirements through specialist third parties and communicated changes to the wider organisation; and

reviewed, amended and agreed HSE key performance indicators for 2015 as part of a HSE scorecard that will form part of the Group performance evaluation at the end of the year.

Keith Bush

Chairman of the HSE Committee

17 April 2015

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The Audit Committee

The role of the Audit Committee

The Audit Committee is governed by Terms of Reference which are agreed by the Board and subject to annual review. The principle objectives of the Committee are to:

monitor the integrity of the published financial information of the Group;

monitor the Group’s internal control procedures and risk management system;

make recommendations to the Board regarding the appointment, reappointment and removal of external auditors; and

review whistle‐blowing arrangements and the Group’s procedures to prevent bribery and corruption.

Activities during 2014

The Committee met twice in 2014 to execute its responsibilities. The meetings focused on audit planning, risk management, approval of final results and approval of the interim results.

Accounting, tax and financial reporting

The Group financial statements and accounting policies are reviewed by the Committee to comply with International Financial Reporting Standards. In addition the annual budget, liquidity risk, changes to the Corporate Governance Code and statutory audit requirements are all considered on an annual basis. As part of the process the Committee considers reports from the external auditors on the assessment of the internal control environment.

Internal controls and risk

The Board assigns to the Committee the responsibility of monitoring and improving the Group’s internal controls governing the finances of the business. The system of internal controls is vital in managing the risks that face the Group and safeguarding shareholders’ interests. It is the Board’s objective to be aware of the risks, to mitigate them where possible, to insure against them where appropriate and to manage the residual risk in accordance with the stated objectives of the Group.

External auditors

The Committee reviews the findings of the external audit and then approves the scope of work to be undertaken for the next financial reporting year. In addition, a review of the effectiveness of the external audit process is undertaken and an annual assessment of the external auditors independence is made.

Whistle‐blowing and prevention of bribery and corruption

The Committee undertakes a review of whistle‐blowing policy arrangements and the Group’s procedures to prevent bribery and corruption to assess the effectiveness of the Group’s Anti‐Bribery and Corruption Annual Plan. The Committee is pleased to report that no incidents were raised during 2014, or have been raised in 2015.

Iain M Lanaghan

Chairman of the Audit Committee

17 April 2015

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Report on Directors’ Remuneration

This report sets out the details of the remuneration policy for the Group’s Directors, describes its implementation and discloses the amounts paid in 2014. The report meets statutory requirements, in particular the relevant regulations on Directors’ remuneration reports pursuant to the Companies Act 2006 and, provisions of the Code as prescribed for AIM quoted companies. Additional remuneration details have been offered voluntarily.

Remuneration Committee membership and process

During 2014 the Remuneration Committee comprised the Non‐executive Chairman, Jon Murphy and the two Non‐executive Directors, Stewart Gibson and Iain Lanaghan. Stewart has stepped down from the Board and the Remuneration Committee in 2015 and his place as Chairman of the Remuneration Committee has been taken by Jon Murphy.

The Committee met three times during 2014 to determine the remuneration arrangements and contracts of the Directors and senior employees. No Director plays a part in any discussion regarding his own remuneration.

The Committee has engaged PricewaterhouseCoopers as its independent executive remuneration advisers.

Activities during 2014

During 2014 the Committee discussed and decided upon:

the approval of executive salary for 2015;

the enrolment in a Group pension scheme, in line with the UK workplace pension requirements; and

the creation and development of a new long term incentive plan.

The Committee has drawn up a proposed long term incentive plan for the Executive Directors and employees with which to attract, retain and motivate key personnel who are critical to executing the business strategy and more closely align employees and shareholder interests. This plan will be further considered and approved by the Committee once the Group is not in a closed period for the purposes of share based awards.

Following the year end, the Committee implemented a deferred salary scheme for all members of the Board and some senior members of staff to reduce the Group’s ongoing administrative cash payments, given the current low oil price environment. The future payment of any of the deferred salary in relation to the members of the Board is at the discretion of the Committee and can be paid in ordinary shares or cash. No further changes to the operation of the remuneration policy in 2015 are currently planned.

Remuneration policy

The Committee aims to ensure that total remuneration is set at an appropriate level for the Group and its operations and relative to peer group comparator companies. The comparator companies are UK‐based oil and gas companies which are primarily quoted on AIM.

The objectives of the remuneration policy are to:

enable the Group to recruit, retain and motivate individuals with the skills, capabilities and experience to achieve its stated objectives;

strengthen teamwork by enabling all employees to share in the success of the business;

ensure remuneration levels support the Group strategy and a sustainable business model while promoting capital discipline throughout the Group; and

ensure alignment of executive, senior management and shareholder interests.

The core principles of the remuneration policy are to:

ensure that there is an appropriate link between performance and reward;

pay an appropriate level of total remuneration relative to peer group companies;

determine annual bonuses which are linked to the delivery of targets including the achievement of strategic objectives and personal performance;

ensure that long‐term incentives are linked to shareholder return;

review progress made against KPI targets and agree incentive awards;

determine the remainder of the remuneration packages (principally comprising salary) for each Executive Director; and

review and note the remuneration trends across the Group.

The philosophy of the Committee is that the targets established for each element of the remuneration should be quantified wherever practicable.

__________________________________________________________________________________________________


Report on Directors’ Remuneration continued

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

basic annual salary or fees;

benefits in kind;

discretionary annual bonus; and

a long‐ term incentive plan.

Basicnannualnsalarynornfees

An Executive Director’s basic salary and the other fixed elements of pay are determined by the Committee at the beginning of each year with any changes taking effect from 1 January. The individual salaries and benefits of Executive Directors are reviewed and adjusted taking into account individual performance, market factors and sector conditions.

Although the Committee does not formally consult employees on executive pay policy, in setting the remuneration levels for Executive Directors, the Committee considers base salary in the context of all employees as a whole. Details of the Executive Directors’ basic salary are shown on page 23. The Chief Executive Officer received a 2.1 per cent pay increase in basic salary compared to an average increase of 3.9 per cent among employees.

Following the year end, all members of the board had their basic salary reduced to better manage the cash resources of the business due to the change in oil price affecting the forecast net revenue of the Group.

Benefitsninnkind Benefits provided to Executive Directors include Critical Illness cover, Death in Service cover, Private Medical Insurance and a pension contribution of 3 per cent of basic annual salary in 2014, all of which are offered to all employees.

Discretionarynannualnbonus An Executive Director’s annual bonus is based on performance for the year and is determined at the discretion of the Remuneration Committee and granted in January. A deferred bonus facility is in place whereby a proportion of any annual bonus is transferred into shares at the discretion of the Committee which vest at the end of a three year period. As disclosed in the 2013 annual report the Committee decided that the Executive Directors will receive an award under the deferred bonus facility in relation to their performance during that year. This award will be made once the Group is out of a closed period.

There was no discretionary bonus award to Executive Directors for 2014. Future bonus payments will continue to be determined by the Committee with reference to the achievement of annual goals and objectives set at a Group and individual level.

LTIP The Committee has drawn up a proposed long term incentive plan for the Executive Directors and employees with which to attract, retain and motivate key personnel who are critical to executing the business strategy and more closely align employees and shareholder interests. This plan will be finalised and approved by the Committee once the Group is not in a closed period for the purposes of share based awards.

Non‐executivenDirectors’nfees The Non‐executive Directors are paid a base fee for carrying out their duties and responsibilities as disclosed in the table on page 23. The Non‐executive Directors waived their contractual entitlement to receive £2,000 and £1,500 where applicable for chairmanship and membership of each of the Remuneration and Audit Committees.

Directors’nservicencontracts The notice period for Keith Bush and Nick Morgan is six months, unless in the case of a change of control and the Director is removed from office at which point the notice period will be extended to 12 months. The Non‐executive Directors have a notice period of three months. The Directors’ contracts do not contain any further obligations on the Group.

Lossnofnofficenpayments Group Policy for loss of office payments is to provide payment to cover contractual rights. Graham Heard, who stepped down from the Board at the end of 2014, agreed a compromise settlement and waived his contractual rights. Details of the loss of office payment in relation to Graham Heard can be found on page 23.

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Report on Directors’ Remuneration

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

Year ended 31 December 2014 Year ended 31 December 2013 Presented in USD

Salary or

fees Taxable benefits

Loss of office

payment

Salary

or fees

Taxable benefit

Loss of office

payment

Pension Total Bonus Total $’000 $’000 $’000 $’000 $’000 $’000 $’000 $’000 $’000 $’000

Current Executive Directors (salaries): K R Bush 406 17 5 ‐ 428 346 8 48 ‐ 402 G L Heard (retired 31.12.14) 372 8 ‐ 381 761 359 11 32 ‐ 402 N T Morgan 372 16 5 ‐ 393 324 7 39 ‐ 370

1,150 41 10 381 1,582 1,029 26 119 ‐ 1,174

Current Non‐Executive Directors (fees): S G Gibson (retired 31.03.15) 58 ‐ ‐ ‐ 58 1 ‐ ‐ ‐ 1 I M Lanaghan (appointed 13.02.14) 51 ‐ ‐ ‐ 51 ‐ ‐ ‐ ‐ ‐ J D Murphy 91 ‐ ‐ ‐ 91 22 ‐ ‐ ‐ 22

200 ‐ ‐ ‐ 200 23 ‐ ‐ ‐ 23

Total Current Directors 1,350 41 10 381 1,782 1,052 26 119 ‐ 1,197

Former Executive Directors (salaries): M L Eaton (resigned 17.06.13) ‐ ‐ ‐ ‐ ‐ 171 7 ‐ 248 426 C J Foss (resigned 23.07.13) ‐ ‐ ‐ ‐ ‐ 203 8 ‐ 492 703 D R Musgrove (resigned 10.07.13) ‐ ‐ ‐ ‐ ‐ 239 19 ‐ 616 874

‐ ‐ ‐ ‐ ‐ 613 34 ‐ 1,356 2,003

Former Non‐Executive Directors (fees): A N Brewer (resigned 20.12.13) ‐ ‐ ‐ ‐ ‐ 57 6 ‐ 48 111 R W Gaisford (resigned 02.07.13) ‐ ‐ ‐ ‐ ‐ 33 ‐ ‐ 33 66 R H R Latham (resigned 10.07.13) ‐ ‐ ‐ ‐ ‐ 51 8 ‐ 87 146 J M White (resigned 20.12.13) ‐ ‐ ‐ ‐ ‐ 61 1 ‐ 51 113

‐ ‐ ‐ ‐ ‐ 202 15 ‐ 219 436

Total Former Directors ‐ ‐ ‐ ‐ ‐ 815 49 ‐ 1,575 2,439

Total All Directors 1,350 41 10 381 1,782 1,867 75 119 1,575 3,636 The taxable benefits comprise critical illness cover, death in service and medical and dental insurance. The Non‐executive Directors have waived fees for acting as members of the Group’s Audit and Remuneration Committees.

Percentage change in remuneration of Director undertaking the role of CEO The percentage change in the remuneration of the CEO compared to the group average percentage changes from 2013 to 2014 in respect of the employees of the Group continuing operations taken as a whole is detailed in the table below. Salary Benefit Pensions Bonus

Chief Executive Officer 2.1% 3.9% 100% ‐ Average Employees 3.9% 3.9% 100% ‐

No bonus was awarded to the Chief Executive Officer or employees in relation to 2014. A new pension scheme was created, in line with the UK workplace pension requirements.

__________________________________________________________________________________________________


Report on Directors’ Remuneration continued

Relative importance of spend on pay The table below shows the Group’s actual spend on all employees relative to capital expenditure as shown on the cash flow statement. 2014 2013 $ million $ million Change

Employee cost 5 7 (35%) Capital expenditure 21 17 24%

Warrants held by Directors serving at 31 December 2014 were as follows: At 1

January 2013

Issued

Exercised

Lapsed

At 1 January

2014

Issued

Exercised

Lapsed

At 31 December

2014 ‘000s ‘000s ‘000s ‘000s ‘000s ‘000s ‘000s ‘000s ‘000s

K R Bush: At 85.0p (exercisable by 31 December 2014) 75 ‐ ‐ ‐ 75 ‐ ‐ (75) ‐ At 100.0p (exercisable by 30 June 2016) ‐ 100 ‐ ‐ 100 ‐ ‐ ‐ 100 At 100.0p (exercisable by 30 June 2017) ‐ 100 ‐ ‐ 100 ‐ ‐ ‐ 100

75 200 ‐ ‐ 275 ‐ ‐ (75) 200

G L Heard: At 68.5p (exercisable by 31 December 2013) 156 ‐ ‐ (156) ‐ ‐ ‐ ‐ ‐

156 ‐ ‐ (156) ‐ ‐ ‐ ‐ ‐

Total 231 200 ‐ (156) 275 ‐ ‐ (75) 200

Details of when the warrants above were granted are disclosed in note 20 “Share Capital”. This report was approved by the Board on 17 April 2015 and signed on its behalf by Jon Murphy.

Jon Murphy

Chairman

17 April 2015

__________________________________________________________________________________________________


Directors’ Report

The Directors present their annual report and the audited financial statements for the year ended 31 December 2014.

Principal activity and review of the business

The activities of the Group are the exploration, appraisal, development and production of oil and gas assets. The areas of activity during 2014 were Canada, Italy, French Guiana, the UK and Australia.

Results and dividends

The Group financial statements are set out in pages 29 to 76 and are presented in US Dollars. The Group’s net loss for the year was $58.9 million (2013: $39.4 million). The Directors do not recommend the payment of a dividend for the year.

Going concern

The Group’s business activities, together with the factors likely to affect its future development and performance are set out in the Chairman’s

and Chief Executive’s Statements and the Review of Operations. The financial position of the Group, its net cash position and liabilities are

described in the Financial Review and in notes 16 and 17. Further information on the Group’s exposure to financial risks and the management

thereof is provided in note 23. Taking into consideration the Group’s year end cash position of $12.1 million and future revenue from existing

oil and gas fields, the Group has adequate financial resources and the Directors believe that the Group is well placed to meet the costs of the

Group’s current financial commitments. However, further development or drilling in Canada and appraisal activities on the Group’s assets in

Italy will require external capital, which may come from the farm out of existing assets, the sale of non‐core assets or debt or equity. The

Board’s review of the accounts, budgets and financial plan lead the Directors to believe that the Group has sufficient resources to continue in

operation at least until the end of 2016 and are managing the Group’s assets to realise further capital to allow the development and growth of

the business beyond that point. The financial statements are therefore prepared on a going concern basis.

Directors and their interests

The Directors of the Group, who all served throughout the year, except where otherwise stated, are listed below. There are no requirements for Directors to hold shares. The Directors’ beneficial interests in the shares of the Group as at the below dates were:

Name

At 31 December 2014

(ordinary 5p shares)

At 31 December 2013

(ordinary 5p shares)

Current Directors

K R Bush 120,000 —

I M Lanaghan (appointed 13 February 2014) 50,000 n/a

N T Morgan 114,882 72,924

J D Murphy 425,200 —

S G Gibson (retired as of 31 March 2015) 100,000 —

G L Heard (retired as of 31 December 2014) 617,497 617,497

Total 1,427,579 690,421

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

Other than as shown above, no Director had any interest in the shares of the Group or any of its subsidiaries at 31 December 2014 or at 31 December 2013.

Keith Bush 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. Keith Bush currently is entitled to 6 months in his service contract unless in the case of a change of control and the Director is removed from office at which point the notice period will be extended to 12 months.

The Group 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 Group’s Memorandum and Articles of Association.

__________________________________________________________________________________________________


Directors’ Report continued

Directors’ interest in transactions

No 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 monthly staff meetings open to all employees and Directors.

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

Substantial interests As at 31 March 2015, the Group has been advised of the following beneficial holdings of three per cent or more of the issued share capital in accordance with the Transparency Obligations Directive (Disclosure and Transparency Rules) Instrument 2009:

Name Shares % of issued

share capital

Cavendish Asset Management Limited 10,189,890 10.69

Midas Investment Management Limited 5,237,169 5.49

Barry James Lonsdale 4,767,875 5.00

Disclosure of Information to Auditor The Directors who held office at the date of the approval of this Directors’ report confirm that, so far as they are each aware, there is no relevant audit information of which the Group’s auditor is unaware; and each Director has taken all steps that they ought to have taken as a Director to make themselves aware of any relevant audit information and to establish that the Group’s auditor is aware of that information.

Auditor

In accordance with Section 489 of the Companies Act 2006, a resolution for the re‐appointment of KPMG LLP as auditor of the Group is to be proposed at the upcoming AGM.

By order of the Board on 17 April 2015.

William Anderson

Secretary to the Board

__________________________________________________________________________________________________


Directors Responsibilities in respect of the Annual Report and the Financial Statements

The Directors are responsible for preparing the annual report, the Strategic Report, the Directors’ Report, the report on Director’s Remuneration and the Group and Parent Company financial statements in accordance with applicable law and regulations.

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

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

select suitable accounting policies and then apply them consistently;

make judgements and estimates that are reasonable and prudent;

for the Group financial statements, state whether they have been prepared in accordance with IFRSs as adopted by the EU;

for the Parent Company financial statements, state whether applicable UK Accounting Standards have been followed, subject to any material departures disclosed and explained in the financial statements; and

prepare the financial statements on the going concern basis unless it is inappropriate to presume that the Group and the Parent Company will continue in business.

The Directors are responsible for keeping adequate accounting records that are sufficient to show and explain the Parent Company’s transactions and disclose with reasonable accuracy at any time the financial position of the Parent Company and enable them to ensure that the 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 Group’s website. Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

__________________________________________________________________________________________________


Independent Auditor’s Report to the Members of Northern Petroleum Plc

Independent auditor’s report to the members of Northern Petroleum PLC

We have audited the financial statements of Northern Petroleum Plc for the year ended 31st December 2014 set out on pages 29 to 76 and pages 78 to 85. The financial reporting framework that has been applied in the preparation of the group financial statements is applicable law and International Financial Reporting Standards (“IFRS”) as adopted by the EU. The financial reporting framework that has been applied in the preparation of the parent company financial statements is applicable law and UK Accounting Standards (UK Generally Accepted Accounting Practice).

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

Respective responsibilities of directors and auditor

As explained more fully in the Directors’ Responsibilities Statement set out on page 27, 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 Ethical Standards for Auditors.

Scope of the audit of the financial statements

A description of the scope of an audit of financial statements is provided on the Financial Reporting Council’s website at www.frc.org.uk/auditscopeukprivate.

Opinion on financial statements

In our opinion:

the financial statements give a true and fair view of the state of the group’s and of the parent company’s affairs as at 31st December 2014 and of the group’s loss for the year then ended;

the group financial statements have been properly prepared in accordance with IFRSs as adopted by the EU;

the parent company financial statements have been properly prepared in accordance with UK Generally Accepted Accounting Practice; and

the financial statements have been prepared in accordance with the requirements of the Companies Act 2006.

Opinion on other matter prescribed by the Companies Act 2006

In our opinion the information given in the Strategic Report and 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 exception

We have nothing to report in respect of the following matters where the Companies Act 2006 requires us to report to you if, in our opinion:

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

the parent company financial statements are not in agreement with the accounting records and returns; or

certain disclosures of directors’ remuneration specified by law are not made; or

we have not received all the information and explanations we require for our audit.

Nigel Harker (Senior Statutory Auditor) for and on behalf of KPMG LLP, Statutory Auditor

Chartered Accountants 15 Canada Square

London E14 5GL

17 April 2015

__________________________________________________________________________________________________


Consolidated Statement of Profit or Loss for the year ended 31 December 2014 Year ended Year ended 31 December 31 December 2014 2013 Notes $’000 $’000 Represented*

Continuing operations Revenue 2 2,731 818

Production costs (2,696) (1,041)

Cost of sales 2 (2,696) (1,041)

Gross profit / ( loss) 35 (223) Pre‐licence costs (76) (623) Administrative expenses 3 (5,947) (7,952) Profit on disposal of subsidiaries and other assets 4 2,344 14 Other operating expenses 5 (1,067) (2,222) Impairment losses 12 & 13 (52,597) (24,403)

Loss from operations 2 & 3 (57,308) (35,409) Finance costs 8 (1,767) (2,164) Finance income 9 6 15 Share of operating loss of joint ventures and associates ‐ (44)

Loss before tax

(59,069) (37,602)

Tax credit

10

121 1,045

Loss for the year from continuing operations

(58,948) (36,557)

Discontinued operations Loss for the year from discontinued operation, net of tax ‐ (2,793)

Continuing and discontinued operations Loss for the year (58,948) (39,350)

Attributable to Equity shareholders of the Company (42,958) (39,331) Non‐controlling interests (15,990) (19)

(58,948) (39,350)

Earnings per share Basic earnings per share on loss for the year 11 (45.0) cents (41.2) cents

Earnings per share – continuing operations Basic earnings per share on loss for the year 11 (45.0) cents (38.3) cents

As the Group is loss making, there is no dilution of earnings from potential ordinary shares and diluted earnings per share has not been presented. See note 11 for further information. *Following the change in presentational currency, as detailed in note 1, the comparative Statement of Profit or Loss has been represented in US Dollars. The notes on pages 36 to 76 form part of these financial statements.

__________________________________________________________________________________________________


Consolidated Statement of Other Comprehensive Income for the year ended 31 December 2014 Year ended Year ended 31 December 31 December 2014 2013 $’000 $’000 Represented*

Loss for the year (58,948) (39,350) Other comprehensive (loss): Items that may be reclassified subsequently to profit or loss: Exchange differences on translation of foreign operations (4,407) (571)

Other comprehensive loss for the year, net of income tax (4,407) (571)

Total comprehensive loss for the year (63,355) (39,921)

Attributable to Equity shareholders of the Company (47,365) (39,767) Non‐controlling interests (15,990) (154)

(63,355) (39,921)

The notes on pages 36 to 76 form part of these financial statements. *Following the change in presentational currency, as detailed in note 1, the comparative Statement of Other Comprehensive Income has been represented in US Dollars.

__________________________________________________________________________________________________


Consolidated Statement of Financial Position

at 31 December 2014 2014 2013 Notes $’000 $’000 Represented*

Assets Non‐current assets Intangible assets 12 32,347 72,910 Property, plant and equipment 13 3,994 848 Investments in associates and others 14 ‐ 183

36,341 73,941 Current assets Inventories 15 ‐ 44 Trade and other receivables 16 1,573 2,355 Cash and cash equivalents 12,143 35,841

13,716 38,240

Total assets 50,057 112,181

Liabilities Current liabilities Trade and other payables 17 5,233 3,530 Provisions 18 ‐ 501 Corporation tax liability 17 ‐ 145

5,233 4,176 Non‐current liabilities Trade and other payables 17 930 1,248 Provisions 18 1,300 651 Deferred tax liabilities 19 2,927 3,333

5,157 5,232

Total liabilities 10,390 9,408

Net assets 39,667 102,773

Capital and reserves Share capital 20 8,225 8,225 Share premium 17,312 17,312 Merger reserve 14,190 14,190 Share incentive plan reserve 484 861 Foreign currency translation reserve (5,026) (619) Retained earnings and other distributable reserves

4,489 47,062

Equity attributable to owners of the parent 39,674 87,031

Non‐controlling interests (7) 15,742

Total equity 39,667 102,773

*Following the change in presentational currency, as detailed in note 1, the comparative Statement of Financial Position has been represented in US Dollars.

The notes on pages 36 to 76 form part of these financial statements.

These financial statements were approved and authorised for issue by the Board of Directors on 17 April 2015 and were signed on its behalf by:

K R Bush N T Morgan Director Director

REGISTERED NO. 02933545

__________________________________________________________________________________________________


Consolidated Cash Flow Statement for the year ended 31 December 2014 Year ended Year ended 31 December 31 December 2014 2013 Notes $’000 $’000 Represented*

Cash flow from operating activities Cash generated from operations 24 (2,578) 3,151 Interest received 6 66 Interest paid (12) (25) Taxes paid (91) (6,358)

Net cash outflow from operating activities (2,675) (3,166)

Cash flows from investing activities Purchase of property, plant and equipment (10,996) (2,571) Expenditure on exploration and evaluation assets (11,023) (8,847) Purchase of other intangible assets ‐ (1) Investment in joint venture company and others ‐ (7,428) Acquisition of former joint venture company, cash acquired ‐ 11 Acquisition of Canadian subsidiary, net of cash acquired ‐ (172) Disposal of discontinued operation, net of cash disposed of ‐ 23,465 Sale of subsidiaries, investments and property, plant and equipment, net of cash disposed of

2,465 30

Net cash (outflow) / inflow from investing activities (19,554) 4,487

Cash flows from financing activities Proceeds of repayment of loans to joint ventures ‐ 192 Proceeds from award of government grants and loans 401 4,557 Repayment of government loan (421) (163) Capital contributions from non controlling interests 230 ‐

Net cash inflow from financing activities 210 4,586

Net (decrease) / increase in cash and cash equivalents (22,019) 5,907 Cash and cash equivalents at start of year 35,841 30,992 Effect of exchange rate movements (1,679) (1,058)

Cash and cash equivalents at end of year 12,143 35,841

*Following the change in presentational currency, as detailed in note 1, the comparative Consolidated Cash Flow Statement has been represented in US Dollars. There have been no significant non‐cash transactions during either year.

__________________________________________________________________________________________________


Consolidated Statement of Changes in Equity for the year ended 31 December 2014 Retained Share Foreign earnings Share incentive currency and other Non ‐ Share premium Merger plan translation distributable controlling Total capital account reserve reserve reserve reserves Total interests equity $’000 $’000 $’000 $’000 $’000 $’000 $’000 $’000 $’000 Represented

At 1 January 2013 8,225 17,312 14,190 1,881 (186) 85,065 126,487 ‐ 126,487

Total comprehensive income for the year ‐ ‐ ‐ ‐ (436) (39,331) (39,767) (154) (39,921)

Contributions by and distributions to owners of the Company Equity share warrants lapsed or cancelled ‐ ‐ ‐ (1,411) ‐ 1,411 ‐ ‐ ‐ Share‐based payments ‐ ‐ ‐ 391 ‐ ‐ 391 ‐ 391

Total contributions by and distributions to owners of the Company ‐ ‐ ‐ (1,020) ‐ 1,411 391 ‐ 391

Changes in ownership interests in subsidiaries Acquisition of subsidiary with non‐ controlling interests* ‐ ‐ ‐ ‐ ‐ ‐ ‐ 15,816 15,816 Acquisition of non‐controlling interests without a change in control** ‐ ‐ ‐ ‐ 3 (83) (80) 80 ‐

Total changes in ownership interests in subsidiaries ‐ ‐ ‐ ‐ 3 (83) (80) 15,896 15,816

At 31 December 2013 8,225 17,312 14,190 861 (619) 47,062 87,031 15,742 102,773

*Initial acquisition of Northpet Investments Limited (French Guiana) / ** Subsequent increases in equity in Northpet Investments Limited. Details of changes in presentation to the Consolidated Statement of Changes in Equity and other restatements are given in note 1.

__________________________________________________________________________________________________


Consolidated Statement of Changes in Equity continued for the year ended 31 December 2014 Retained Share Foreign earnings Share incentive currency and other Non ‐ Share premium Merger plan translation distributable controlling Total capital account reserve reserve reserve reserves Total interests equity $’000 $’000 $’000 $’000 $’000 $’000 $’000 $’000 $’000

At 1 January 2014 8,225 17,312 14,190 861 (619) 47,062 87,031 15,742 102,773

Total comprehensive income for the year ‐ ‐ ‐ ‐ (4,407) (42,958) (47,365) (15,990) (63,355)

Contributions by and distributions to owners of the Company Equity share warrants lapsed or cancelled ‐ ‐ ‐ (396) ‐ 396 ‐ ‐ ‐ Share‐based payments ‐ ‐ ‐ 19 ‐ ‐ 19 ‐ 19

Total contributions by and distributions to owners of the Company ‐ ‐ ‐ (377) ‐ 396 19 ‐ 19

Changes in ownership interests in subsidiaries Capital contributions from non‐controlling interests ‐ ‐ ‐ ‐ ‐ ‐ ‐ 230 230 Acquisition of non‐controlling interests without a change in control* ‐ ‐ ‐ ‐ ‐ (11) (11) 11 ‐

Total changes in ownership interests in subsidiaries ‐ ‐ ‐ ‐ ‐ (11) (11) 241 230

At 31 December 2014 8,225 17,312 14,190 484 (5,026) 4,489 39,674 (7) 39,667

* Increase in equity in Northpet Investments Limited.

__________________________________________________________________________________________________


Consolidated Statement of Changes in Equity for the year ended 31 December 2014

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.

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 Statement of Profit or Loss 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‐US Dollar functional currency operations (including comparatives) are recognised through the Consolidated Statement of Other Comprehensive Income.

Retained earnings and other distributable reserves Cumulative net gains and losses recognised in the financial statements; plus other distributable reserves relating 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.

Non‐controlling interests Amounts attributable to minority shareholders of fully consolidated subsidiaries. This represents the equity of Hague and London Oil PLC (formerly Wessex Exploration PLC) in Northpet Investments Limited. The Group held 55.9% of the ordinary share capital of Northpet Investments Limited at 31 December 2013.

__________________________________________________________________________________________________


Notes to the Accounts for the year ended 31 December 2014

1. Accounting Policies The 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 preparation The consolidated financial statements have been prepared under the historical cost convention and in accordance with International Financial Reporting Standards ("IFRS") as adopted by the European Union (EU) 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 Generally Accepted Accounting Principles ("UK GAAP"); these are presented on pages 78 to 85. 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 preparation The Group’s business activities, together with the factors likely to affect its future development and performance are set out in the Chairman’s and Chief Executive’s Statements and the Review of Operations. The financial position of the Group, its net cash position and liabilities are described in the Financial Review and in notes 16 and 17. Further information on the Group’s exposure to financial risks and the management thereof is provided in note 23. Taking into consideration the Group’s year end cash position of $12.1 million and future revenue from existing oil and gas fields, the Group has adequate financial resources and the Directors believe that the Group is well placed to meet the costs of the Group’s current financial commitments. However, further development or drilling in Canada and appraisal activities on the Group’s assets in Italy will require external capital, which may come from the farm out of existing assets, the sale of non‐core assets or debt or equity. The Board’s review of the accounts, budgets and financial plan lead the Directors to believe that the Group has sufficient resources to continue in operation at least until the end of 2016. The financial statements are therefore prepared on a going concern basis. Changes in functional and presentational currency The functional currency is the currency of the primary economic environment in which an entity operates. Following the successful well programme completed in Canada in Q1 2014 and the change in the Group’s strategy, which included the sale of the Netherlands subsidiary in Q4 2013, the Directors considered The Company’s functional currency. From the start of 2014 the majority of the Group’s and by extension the Company’s underlying transactions were expected to be denominated in or heavily influenced by the US Dollar. Therefore the Directors took the decision to prospectively change the Company functional currency to US Dollars from 1 January 2014. The following subsidiary of the Company has also changed its functional currency to US Dollars with effect from 1 January 2014:

NP Oil & Gas Holdings Limited (“NPOGH”) – parent company of Ouro Preto Resources Inc. (Canada) and Ouro Preto Resources PTY Limited, (Australia).

Consistent with the change in the Company’s and subsidiary’s functional currencies, the Group has also changed its presentation currency from Euro to US Dollar with effect from 1 January 2014. Comparative figures for all 2013 primary statements, plus the opening 2013 balance sheet have therefore been re‐presented in US Dollars at a rate of 1.3791 USD to 1 EUR as reported by the US Federal Reserve System on their website http://www.federalreserve.gov. The change of the Group’s presentation currency and that of the Company’s functional currency were accounted for in accordance with IAS 21 “The Effects of Changes in Foreign Exchange Rates” and SSAP 20 “Foreign Currency Translation” respectively. On the change of the Group’s presentation currency, the Group consolidated prior year comparative accounts have been represented: The Company’s and NPOGH’s comparative figures previously reported in Euro have been translated into US Dollars at the exchange rate at the date of change over, 1 January 2014; the balance sheets of subsidiaries which have maintained Euro as their functional currency have been translated to US Dollars at the closing rate of the year and their income statements have been translated at the average rate for the year; and subsidiaries that already had US Dollars as their functional currency have been consolidated without adjustment. The change of the Company’s functional currency was accounted for prospectively from 1 January 2014. Accordingly the assets, liabilities and equity items of the Company as at 31 December 2013 were translated from Euro into US Dollars at the closing exchange rate on that date of $:€ 1.3791 as reported by the US Federal Reserve System on their website http://www.federalreserve.gov. Details of the current and prior year exchange rates used in these accounts are disclosed in note 23.

__________________________________________________________________________________________________


Notes to the Accounts for the year ended 31 December 2014

1. Accounting Policies continued Changes in accounting policies

Adoption 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: IFRS 10 – Consolidated Financial Statements;

IFRS 11 – Joint Arrangements;

IFRS 12 – Disclosure of Interests in Other Entities; and

IAS 27 – Separate Financial Statements

These standards replace the existing accounting for subsidiaries and joint ventures, and make limited amendments in relation to associates. IFRS 10 supersedes IAS 27 Consolidated and Separate Financial Statements. All parties to a joint arrangement are within the scope of IFRS 11. IAS 27 (2011) carries forward the existing accounting and disclosure requirements of IAS 27 for separate financial statements, with some minor clarifications. The standards were effective for annual periods beginning on or after 1 January 2014 and have been endorsed by the EU.

B. At the date of approval of these financial statements, the following Standards or Interpretations were in issue but not yet effective:

IFRS 9 – Financial Instruments The new standard, which has not yet been endorsed, 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. A financial asset is measured at amortised cost if the following conditions are met:

it is held within a business model whose objective is to hold assets in order to collect contractual cash flows; and

its contractual terms give rise on specified dates to cash flows that are solely payments of principal and interest on the principal outstanding.

All other financial assets are measured at fair value. IFRS 11 – Joint Arrangements (amended) The amendments to this standard require business combination accounting to be applied to acquisitions of interests in a joint operation that constitutes a business. IAS 16 – Property, Plant and Equipment and IAS 38 – Intangible Assets The amendments introduce a rebuttable presumption that the use of revenue‐based amortisation methods for intangible assets is inappropriate. This presumption can be overcome only when revenue and the consumption of the economic benefits of the intangible asset are “highly correlated”, or when the intangible asset is expressed as a measure of revenue. While this is not an outright ban, it creates a high hurdle for when these methods may be used for intangible assets. The amendments also ban the use of revenue‐based amortisation for property, plant and equipment. IAS 27 – Separate Financial Statements (amended) The amendments allow the use of the equity method in separate financial statements, and apply to the accounting not only for associates and joint ventures, but also for subsidiaries.

__________________________________________________________________________________________________


Notes to the Accounts continued for the year ended 31 December 2014 1. Accounting Policies continued Basis of consolidation The consolidated financial statements include the financial statements of the Company, its subsidiaries and interests in joint ventures and associates made up to 31 December 2014. Subsidiaries The Company determines whether it is a parent by assessing whether it controls one or more investees, (potential subsidiaries). The Company considers all relevant facts and circumstances when assessing whether it controls an investee. The Company controls an investee, (subsidiary), when it is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. 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. Non‐controlling interests For each business combination, the Group elects to measure any non‐controlling interests in the acquiree either:

at fair value; or

at their proportionate share of the acquiree’s identifiable net assets, which are generally at fair value.

Changes in the Group’s interest in a subsidiary that do not result in a loss of control are accounted for as transactions with owners in their capacity as owners. Adjustments to non‐controlling interests are based on a proportionate amount of the net assets of the subsidiary. No adjustments are made to goodwill and no gain or loss is recognised in profit or loss. Intangible assets Oil and gas assets: exploration and evaluation The Group has continued to apply the 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. The appropriate cash generating unit grouping is based on geological basins and play types. The Group considers that Virgo ‐ Alberta (Canada), South Australia (Australia), French Guiana (France), Southern Adriatic Sea (Italy), Italy (excluding the Southern Adriatic) and United Kingdom are cost pools. 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 statement of profit or loss as they are incurred. Intangible E&E assets relating 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. The carrying value of costs within each cash‐generating unit grouping is reviewed annually against the progress or otherwise of a particular project within each country. 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 or when the Group decides that it no longer has interest or activity in a specific region or basin. Such indicators include the point at which a determination is made as to whether or not commercial reserves exist.

__________________________________________________________________________________________________


Notes to the Accounts for the year ended 31 December 2014 1. Accounting Policies continued

Intangible assets (continued) 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 a rate of 10% (2013: between 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 statement of profit or loss and separately disclosed. Where the Group reaches an agreement to farm out an oil and gas permit and receives a refund of a proportion of its expenditure to date in the form of back costs, the back costs are applied to reduce the carrying value of the relevant cost pool. If the receipts of back costs exceeds the cost held in the cost pool, the excess costs recovered are credited to the statement of profit or loss under other operating income. Software implementation The Group has capitalised expenditure on the implementation of a 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. Property, plant and equipment Oil and gas assets: development and production Development 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 a rate of 10% (2013: between 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. Decommissioning Where 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.

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Notes to the Accounts continued for the year ended 31 December 2014 1. Accounting Policies continued Property, plant and equipment (continued) Non‐oil and gas assets Property, plant and equipment are included in the statement of financial position at cost, less accumulated depreciation and any provisions for impairment. Business combinations The acquisition of subsidiaries is accounted for using the purchase method. The consideration of the acquisition is measured at the aggregate of the fair values, at the date of exchange, of assets given, liabilities incurred or assumed and equity instruments issued by the Group in exchange for control of the acquiree. Acquisition costs incurred are expensed and included in other operating expenses. The acquiree’s identifiable assets, liabilities and contingent liabilities that meet the conditions for recognition under IFRS 3 are recognised at their fair value at the acquisition date, except for non‐current assets (or disposal groups) that are classified as held for sale in accordance with IFRS 5 Non‐current assets held for sale and discontinued operations, which are recognised and measured at fair value less costs to sell. Goodwill arising on acquisition is recognised as an asset and initially measured at cost, being the excess of the cost of the business combination over the Group’s interest in the net fair value of the identifiable assets, liabilities and contingent liabilities recognised. If, after reassessment, the Group’s interest in the net fair value of the acquiree’s identifiable assets, liabilities and contingent liabilities exceeds the cost of the business combination, the excess is recognised immediately in the Statement of Profit or Loss. Discontinued operations A discontinued operation is a component of the Group’s business, the operations and cash flows of which can be clearly distinguished from the rest of the Group and which:

represents a separate major line of business or geographical area of operations; or

is part of a single co‐ordinated plan to dispose of a separate major line of business or geographical area of operations. Classification as a discontinued operation occurs on disposal or when the operation meets the criteria to be classified as held‐for‐sale, if earlier. When an operation is classified as a discontinued operation, the Consolidated Statement of Profit or Loss and the Consolidated Statement of Other Comprehensive Income are re‐presented as if the operation had been discontinued from the start of the comparative year.

Revenue Revenue comprises net invoiced sales of hydrocarbons to customers, excluding value added and similar taxes, but before the deduction of royalties. Also disclosed within production and pre‐production segment revenue is income recognised, excluding value added and similar taxes, for charges in respect of fees for acting as operator of both production and pre‐production activities, and fees for other related services, to third parties by the Group. 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 reporting In 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: Canada, Italy, French Guiana, United Kingdom and Others including Australia.

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Notes to the Accounts for the year ended 31 December 2014 1. Accounting Policies continued Share‐based payments The Group has both equity settled and cash settled share based payment schemes. Equity settled share‐based payments: In 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 Statement of Profit or Loss equal to the fair value of the benefit awarded. The expense is recognised in the statement of profit or loss 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. If a warrant is cancelled before the end of its vesting period, the remaining fair value expense not yet charged to the Statement of Profit or Loss 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. Cash settled share‐based payments: In accordance with IFRS 2 “Share‐based payments”, for cash‐settled share‐based payment transactions, the Group measures the goods or services acquired and the liability incurred at the fair value of the liability. Until the liability is settled, the Group remeasures the fair value of the liability at each reporting date and at the date of settlement, with any changes in fair value recognised in profit or loss for the period. Fair value is measured by use of a Black Scholes model which takes into account the terms and conditions on which the share appreciation rights were granted, and the extent to which the employees have rendered service to date. 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. An accrual for employers’ National Insurance is made in respect of share warrants granted to employees that are in profit at the year end. Pensions A 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 Statement of Profit or Loss 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. Depreciation The cost of property, plant and equipment, other than costs directly related to oil and gas assets, is written off by equal annual instalments over the expected useful lives of the assets, as follows:

Leasehold improvements – over the term of the lease

Computer hardware and software – four to five years

Office equipment – four years The carrying values of property, plant and equipment are reviewed for impairment if events or changes in circumstances indicate the carrying value may not be recoverable. Inventories Inventories 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. Net realisable value is the estimated selling price in the ordinary course of business less marketing costs. Lease commitments The annual rentals under operating leases are charged to the Statement of Profit or Loss on a straight‐line basis over the term of the lease.

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Notes to the Accounts continued for the year ended 31 December 2014 1. Accounting Policies continued Financial instruments Financial assets The 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 Statement of Profit or Loss. 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 liabilities The 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 Statement of Profit or Loss. Government grants and disclosure of government assistance A government grant is recognised only when there is reasonable assurance that (a) the entity will comply with any conditions attached to the grant and (b) the grant will be received. Government grants received in respect of intangible assets or property, plant and equipment are offset against the costs of the related assets. This accounting policy has been adopted for the first time by the Group after receiving grants from the Italian government in 2013. Government loans received at below market rates of interest are fair valued at the date of inception. The fair value discount element of the loan is offset against the cost of the asset to which it relates as it is treated as a grant. The fair value of the loan is unwound as an implied interest cost over the life of the loan. The market rate of interest is determined to be 10%. Share capital Financial 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.

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Notes to the Accounts for the year ended 31 December 2014 1. Accounting Policies continued Foreign currencies Foreign currency transactions of individual companies within the Group are translated in the individual companys’ 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 Statement of Profit or Loss. On 1 January 2014 the Company changed its functional currency and the Group changed presentational currency from Euro to US Dollars. See page 36 for further details. The functional currency of the Parent Company is considered to be the US Dollar and the Group financial statements have been presented in US Dollars. On consolidation, assets and liabilities of subsidiaries, associate undertakings and joint ventures which are denominated in other currencies are translated into US Dollars 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. Taxation The 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, at the balance sheet date. Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit, and is accounted for using the balance sheet liability method. Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised. Such assets and liabilities are not recognised if the temporary difference arises from goodwill or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither the tax profit nor the accounting profit. Deferred tax assets and liabilities are recognised for taxable temporary differences arising on investments in subsidiaries and associates, and interests in joint ventures, except where the Group is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future. The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered. Deferred tax is calculated on an undiscounted basis at the tax rates that are expected to apply in the period when the liability is anticipated to be settled or the asset is anticipated to be realised, based on tax rates and laws enacted or substantively enacted at the balance sheet date. Deferred tax is charged or credited in the Statement of Profit or Loss, 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 equivalents Cash, 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.

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Notes to the Accounts continued for the year ended 31 December 2014 1. Accounting Policies continued Critical accounting judgments and key sources of estimation uncertainty The 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 may, 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 13); Carrying value of intangible exploration and evaluation assets (Note 12); Valuation of petroleum and natural gas properties: consideration of future cash flows used to assess impairment includes estimates relating to oil and gas reserves, future production rates, overall costs and oil and natural gas prices. 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 there may be a need to recognise an impairment. The timing of an impairment review and the judgement of when there could be a significant change affecting the carrying value of plant property and equipment or intangible exploration assets is critical accounting judgement in itself. Commercial reserves estimates; A number of critical accounting policies are dependent upon oil and gas reserve estimates. These include intangible assets and property, plant and equipment. 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. Management consults third party experts and obtains external technical assurance when making these judgements. 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. 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 18); 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. Management consults third party experts when making these judgements. Share‐based payments (Notes 3 and 20); The fair value of share‐based payments recognised in the Statement of Profit or Loss 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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Notes to the Accounts for the year ended 31 December 2014 2. Segmental Information During 2014 the Group has maintained the management reporting information, provided to the Chief Executive Officer (CEO), with five of the six geographic reporting segments used in 2013. The United Kingdom was involved in production, development and exploration activity, until the disposal of three UK subsidiaries to UK Oil & Gas Investments PLC in October 2014, (see note 4), with the United Kingdom also the home of the head office; Italy is involved in exploration and appraisal operations; Canada is involved in production, development and exploration operations; French Guiana is involved in exploration operations; the “Other” segment comprises exploration operations in Australia, plus some pre‐licence expenditure in respect of exploration and production possibilities in new countries. The sixth segment, The Netherlands, was involved in production, development and exploration activity and was disposed of during 2013 (discontinued operations). The segment disclosures are based on the components of the business that the CEO 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

2014

United Kingdom

$’000 Italy$’000

Canada $’000

French Guiana $’000

Other Incl.

Australia $’000

Total $’000

Revenue from external customers Oil 476 ‐ 2,237 ‐ ‐ 2,713 Gas and gas condensate ‐ ‐ ‐ ‐ ‐ ‐ Tariffs ‐ ‐ ‐ ‐ ‐ ‐ Project operator fees 18 ‐ ‐ ‐ ‐ 18

494 ‐ 2,237 ‐ ‐ 2,731

Cost of sales Production costs 262 ‐ 2,434 ‐ ‐ (2,696)

262 ‐ 2,434 ‐ ‐ (2,696)

Gross profit / (loss) 232 ‐ (197) ‐ ‐ 35 Pre‐licence costs ‐ (76) ‐ ‐ ‐ (76) Administrative expenses (4,958) (293) (508) (136) (52) (5,947) Profit / (loss) on disposal of subsidiaries and other assets 2,383 ‐ ‐ ‐ (39) 2,344 Other operating expenses ‐ (225) (69) ‐ (773) (1,067) Impairment losses (942) (7) (15,313) (36,335) ‐ (52,597)

Loss from operations (3,285) (601) (16,087) (36,471) (864) (57,308)

Finance costs (1,664) (129) 2 27 (3) (1,767) Finance income 6 ‐ ‐ ‐ ‐ 6 Share of operating loss of joint ventures and associates ‐ ‐ ‐ ‐ ‐ ‐

Loss before tax (4,943) (730) (16,085) (36,444) (867) (59,069)

Tax credit 121 ‐ ‐ ‐ ‐ 121

Loss for the year from continuing operations (4,822) (730) (16,085) (36,444) (867) (58,948)

Loss for the year from discontinued operation, net of tax ‐ ‐ ‐ ‐ ‐ ‐

Loss for the year (4,822) (730) (16,085) (36,444) (867) (58,948)

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Notes to the Accounts continued for the year ended 31 December 2014 2. Segmental Information continued Assets and liabilities at 31 December 2014

United Kingdom

$’000

Italy $’000

Canada $’000


Other Incl.

Australia $’000

Total $’000

Segment assets 2,074 26,969 7,811 ‐ 1,060 37,914 Cash and cash equivalents 9,983 287 1,692 91 90 12,143

Total assets 12,057 27,256 9,503 91 1,150 50,057

Segment liabilities (826) (1,523) (5,006) (97) (11) (7,463) Deferred tax liabilities ‐ (2,881) (46) ‐ ‐ (2,927)

Total liabilities (826) (4,404) (5,052) (97) (11) (10,390)

Non controlling interests ‐ ‐ ‐ 7 ‐ 7

Other segment items Capital expenditure 265 481 21,354 (188) 921 22,833

Depreciation, depletion and amortisation 1,122 ‐ 785 ‐ ‐ 1,907

Impairment losses 942 7 15,313 36,335 ‐ 52,597

Exchange differences on translation of foreign operations ‐ 3,296 1,430 138 162 5,026

Share‐based payments 19 ‐ ‐ ‐ ‐ 19

Included in segment assets above Investment in associates and others ‐ ‐ ‐ ‐ ‐ ‐

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Notes to the Accounts for the year ended 31 December 2014 2. Segmental Information continued Exploration, development and production

2013

United

Kingdom $’000

Italy $’000

Netherlands $’000

Canada $’000

French Guiana$’000

Other $’000

Total $’000

Discontinued operations

$’000

Continuingoperations

$’000

Revenue from external customers Oil 774 ‐ ‐ ‐ ‐ ‐ 774 ‐ 774Gas & gas condensate ‐ ‐ 11,535 ‐ ‐ ‐ 11,535 11,535 ‐Tariffs ‐ ‐ 266 ‐ ‐ ‐ 266 266 ‐Project operator fees 41 3 105 ‐ ‐ ‐ 149 105 44

815 3 11,906 ‐ ‐ ‐ 12,724 11,906 818

Cost of sales Production costs (339) ‐ (7,509) ‐ ‐ ‐ (7,848) (6,807) (1,041)

(339) ‐ (7,509) ‐ ‐ ‐ (7,848) (6,807) (1,041)

Gross profit / (loss) 476 3 4,397 ‐ ‐ ‐ 4,876 5,099 (223) Pre‐licence costs ‐ (340) ‐ ‐ ‐ (283) (623) ‐ (623)Administrative expenses (6,265) (552) (1,088) (342) (25) (37) (8,309) (357) (7,952)Profit on sale of tangible assets 14 ‐ ‐ ‐ ‐ ‐ 14 ‐ 14Other operating income ‐ ‐ 1,586 ‐ ‐ ‐ 1,586 1,586 ‐Other operating expenses (273) (512) (7) (181) ‐ (1,249) (2,222) ‐ (2,222)Impairment losses (13,271) (11,013) ‐ ‐ ‐ (119) (24,403) ‐ (24,403)

(Loss) / profit from operations (19,319) (12,414) 4,888 (523) (25) (1,688) (29,081) 6,328 (35,409)

Finance costs (1,273) (141) (608) (1) (749) ‐ (2,772) (608) (2,164)Finance income 15 ‐ 51 ‐ ‐ ‐ 66 51 15Share of operating loss in joint ventures and associates ‐ ‐ ‐ ‐ (44) ‐ (44) ‐ (44)

(Loss) / profit before tax (20,577) (12,555) 4,331 (524) (818) (1,688) (31,831) 5,771 (37,602)

Income tax (charge) / credit (167) 492 (1,918) ‐ ‐ ‐ (1,593) (2,638) 1,045

(Loss) / profit for the year from continuing operations (20,744) (12,063) 2,413 (524) (818) (1,688) (33,424) 3,133 (36,557)

(Loss) for the year from discontinued operation, net of tax ‐ ‐ ‐ ‐ ‐ ‐ (5,926) (5,926) ‐

(Loss) for the year ‐ ‐ ‐ ‐ ‐ ‐ (39,350) (2,793) (36,557)

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Notes to the Accounts continued for the year ended 31 December 2014 2. Segmental Information continued

Assets and liabilities at 31 December 2013

United Kingdom

$’000

Italy

$’000 Canada $’000


Other $’000

Total continuing operations

$’000

Discontinued Operations

$’000

Total $’000

Segment assets 5,601 31,318 2,889 36,290 242 76,340 ‐ 76,340 Cash and cash equivalents 33,880 1,051 836 23 51 35,841 ‐ 35,841

Total assets 39,481 32,369 3,725 36,313 293 112,181 ‐ 112,181

Segment liabilities (2,435) (2,069) (401) (1,141) (29) (6,075) ‐ (6,075) Deferred tax liabilities ‐ (3,283) (50) ‐ ‐ (3,333) ‐ (3,333)

Total liabilities (2,435) (5,352) (451) (1,141) (29) (9,408) ‐ (9,408)

Non controlling interests ‐ ‐ ‐ (15,742) ‐ (15,742) ‐ (15,742)

Other segment items Capital expenditure 1,035 1,853 3,202 4,088 255 10,433 1,977 12,410

Depreciation, depletion and amortisation 1,220 ‐ ‐ ‐ ‐ 1,220 3,227 4,447

Impairment losses 13,271 11,013 ‐ ‐ 119 24,403 ‐ 24,403

Exchange differences on translation of foreign operations 138 ‐ 325 138 18 619 ‐ 619

Share‐based payments 391 ‐ ‐ ‐ ‐ 391 ‐ 391

Included in segment assets above Investment in associates and others ‐ ‐ ‐ ‐ 183 183 ‐ 183

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Notes to the Accounts for the year ended 31 December 2014 3. Profit / (Loss) from Continuing Operations This is stated after charging: Year ended Year ended 31 December 31 December 2014 2013 $’000 $’000

Depreciation of IT systems (note 12b) 827 827 Impairment of IT systems (note 12b) 744 ‐ Depreciation of non‐oil and gas property, plant and equipment (note 13b) 285 359 Impairment of non‐oil and gas property, plant and equipment (note 13b) 90 ‐ Operating lease rentals – land and buildings 580 843 Operating lease rentals – other 56 101

Equity settled share‐based payments – National Insurance (30) 43 Equity settled share‐based payments – IFRS 2 19 391

Administrative expenses – share incentives (11) 434

Auditor’s Remuneration Year ended Year ended 31 December 31 December 2014 2013 $’000 $’000

Audit fees payable to the Company’s auditor for the audit of the Company’s financial statements 73 88 Fees payable to the Company’s auditor and its associates for other services:

the audit of the Company’s subsidiaries, pursuant to legislation 50 50 audit‐related assurance services 34 15 taxation services ‐ ‐

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

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Notes to the Accounts continued for the year ended 31 December 2014 4. Profit on Disposal of Subsidiaries, Investments and Other Assets Year ended Year ended 31 December 31 December 2014 2013 $’000 $’000

Disposal of subsidiaries Sale proceeds 2,486 ‐ Net book value of liabilities disposed of 63 ‐ Cash disposed of (31) ‐ Disposal costs (135) ‐

Profit on disposal of subsidiaries 2,383 ‐

Disposal of Investments Sale proceeds 150 ‐ Net book value of assets disposed of (184) ‐ Disposal costs (5) ‐

Loss on disposal of investments (39) ‐

Disposal of plant, property and equipment Sale proceeds ‐ 30 Net book value of assets disposed of ‐ (16)

Profit on disposal of property, plant and equipment ‐ 14

Profit on disposal of subsidiaries, investments and other assets 2,344 14

The profit on disposal of subsidiaries relates to the sale of the Group’s UK subsidiaries; Northern Petroleum (GB) Limited, NP Solent Limited and NP Weald Limited, to UK Oil and Gas Investments PLC, (“UKOG”), which was completed on 19 October 2014. No tax charge or credit arises on these disposals as Substantial Shareholder Exemption is available provided the proceeds are reinvested by the Group in oil and gas assets within an appropriate time scale. The loss on disposal of investments relates to the sale of the Group’s interest in Liberty GTL Inc., a company developing small scale gas to liquids technology. No tax credit has been recognised in respect of this disposal. 5. Other Operating Expenses Year ended Year ended 31 December 31 December 2014 2013 $’000 $’000

New business expenses 530 1,484 Farm out expenses 441 470 Business acquisition expenses ‐ 14 Business disposal costs 96 254

Other operating expenses 1,067 2,222

Other operating expenses comprise new business expenditure, farm out expenditure incurred to attract partners to help progress projects and business acquisition and disposal expenses. This includes allocated payroll and other overhead costs incurred during the screening of new opportunities, including Canada. Business disposal costs comprise professional fees, allocated payroll and other overhead costs incurred to complete the disposal of Northern Petroleum Nederland B.V.

__________________________________________________________________________________________________


Notes to the Accounts for the year ended 31 December 2014 6. Directors’ Remuneration Year ended Year ended 31 December 31 December 2014 2013 $’000 $’000

Executive salaries 1,150 1,642 Non Executive fees 200 225 Defined contribution pension costs 10 ‐ Bonus ‐ 119 Benefits in kind 41 75

Emoluments 1,401 2,061 Compensation for loss of office 381 1,575

Total 1,782 3,636

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 $761,000 which included a loss of office payment of $381,000 (2013: $874,000 including a loss of office payment of $616,000).

Year ended 31 December 2014 Year ended 31 December 2013

Salary or Taxable

Loss of office Salary or Taxable

Loss of office

fees benefits Pension payment Total fees benefit Bonus payment Total $’000 $’000 $’000 $’000 $’000 $’000 $’000 $’000 $’000 $’000

Current Executive Directors (salaries): K R Bush 406 17 5 ‐ 428 346 8 48 ‐ 402 G L Heard 372 8 ‐ 381 761 359 11 32 ‐ 402 N T Morgan 372 16 5 ‐ 393 324 7 39 ‐ 370

1,150 41 10 381 1,582 1,029 26 119 ‐ 1,174

Current Non‐Executive Directors (fees): S G Gibson 58 ‐ ‐ ‐ 58 1 ‐ ‐ ‐ 1 I M Lanaghan 51 ‐ ‐ ‐ 51 ‐ ‐ ‐ ‐ ‐ J D Murphy 91 ‐ ‐ ‐ 91 22 ‐ ‐ ‐ 22

200 ‐ ‐ ‐ 200 23 ‐ ‐ ‐ 23

Total Current Directors 1,350 41 10 381 1,782 1,052 26 119 ‐ 1,197

Former Executive Directors (salaries): M L Eaton ‐ ‐ ‐ ‐ ‐ 171 7 ‐ 248 426 C J Foss ‐ ‐ ‐ ‐ ‐ 203 8 ‐ 492 703 D R Musgrove ‐ ‐ ‐ ‐ ‐ 239 19 ‐ 616 874

‐ ‐ ‐ ‐ ‐ 613 34 ‐ 1,356 2,003

Former Non‐Executive Directors (fees): A N Brewer ‐ ‐ ‐ ‐ ‐ 57 6 ‐ 48 111 R W Gaisford ‐ ‐ ‐ ‐ ‐ 33 ‐ ‐ 33 66 R H R Latham ‐ ‐ ‐ ‐ ‐ 51 8 ‐ 87 146 J M White ‐ ‐ ‐ ‐ ‐ 61 1 ‐ 51 113

‐ ‐ ‐ ‐ ‐ 202 15 ‐ 219 436

Total Former Directors ‐ ‐ ‐ ‐ ‐ 815 49 ‐ 1,575 2,439

Total All Directors 1,350 41 10 381 1,782 1,867 75 119 1,575 3,636

Additional information on directors’ remuneration can be found in the Report on Directors’ Remuneration on page 21‐24.

__________________________________________________________________________________________________


Notes to the Accounts continued for the year ended 31 December 2014 7. Staff Costs and Numbers (continuing operations – including Directors) Year ended Year ended 31 December 31 December 2014 2013 $’000 $’000

Salaries 3,709 5,203 Compensation for loss of office 862 1,576 Social security costs 583 878 Defined contribution pension costs 39 12 Other benefits in kind 224 258

5,417 7,927 Charge for share‐based payments (note 3) 19 391 National insurance accrual release on share‐based payments (30) 43

5,406 8,361

Based on time writing, a certain element of salaries is capitalised, predominantly at the subsidiary level, to reflect the time spent on capital projects. The amounts shown above include net salary cost to Northern Petroleum capitalised in the year of $1,618,000 (2013: $1,854,000). Up to the end of May 2014 the Group operated a defined contribution stakeholder pension scheme for one UK employee. In August 2014 the Group introduced a new defined contribution group pension scheme in the UK to which it contributes 3% of a member employee’s salary in accordance with its future Workplace Pensions obligation. Directors and senior staff were given the option of either joining the new scheme or having the 3% contributions paid into their personal (defined contribution) pension schemes. The pension cost charge for the period represents contributions payable by the Group to UK defined contribution pension schemes and amounted to $32,000 (2013: $12,000). In addition the Group made payments to defined contribution schemes for its Canadian and Australian employees. Contributions in Canada amounted to $2,000 (2013: $Nil), while contributions in Australia amounted to $5,000 (2013: $Nil). There were $3,000 (2013: $Nil) outstanding contributions at the end of the financial year. There were no prepaid contributions at either the beginning or end of the financial year. Excluding the Directors, there were 20 (2013: 27) full time members of staff at the end of the year. The average number of persons employed by the Group during the year, including Executive Directors, was made up as follows: 2014 2013

Technical 7 8 Professional 5 8 Operations 4 4 Administration 8 12

24 32

8. Finance Costs Year ended Year ended 31 December 31 December 2014 2013 $’000 $’000

Loan interest 12 10 Unwinding of discount on decommissioning provisions 7 3 Unwinding of discount on below market interest rate government loans 157 109 Foreign exchange loss 1,591 2,042

1,767 2,164

__________________________________________________________________________________________________


Notes to the Accounts for the year ended 31 December 2014 8. Finance Costs continued In 2013 the Group received loans totalling €1,652,000 ($1,999,000) from the Italian government. In 2014 further Italian government loans were received, totalling €145,000 ($176,000) (see note 12). The loans are repayable in five annual instalments and interest is charged at 0.5% per annum. The unwinding of the fair value discount over the life of the loan is shown above as "unwinding of discount on below market interest rate government loans" and the actual interest paid is shown as "loan interest". The foreign exchange loss reflects the effect of the movement in the Canadian Dollar and Euro against the US Dollar with respect to cash balances which were and are being held in the expectation of their investment in exploration and development.

9. Finance Income and Other Finance Gains Year ended Year ended 31 December 31 December 2014 2013 $’000 $’000

Interest receivable 6 15

The realised gain on disposal of subsidiaries was previously recognised in the Consolidated Statement of Other Comprehensive Income as an exchange difference on translation of a foreign operation. On disposal of the Group’s subsidiaries, Northern Petroleum (GB) Limited, NP Solent Limited and NP Weald Limited, the gain on translation of these UK Sterling investments was realised and transferred to finance charges above. For more information, see note 4.

10. Tax Credit a) Analysis of tax credit Year ended Year ended 31 December 2014 31 December 2013 $’000 $’000

Current tax: UK tax ‐ current year ‐ (145) Tax on overseas operations on profits for the year – current year ‐ 720 Current tax ‐ adjustment in respect of prior years 121 22

121 553 Deferred tax: UK tax ‐ ‐ Overseas tax – origination and reversal of temporary differences ‐ 492

Total tax credit (note 10b) 121 1,045

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 recovered in the foreseeable future ‐ for analysis of the tax charge by country of operation please see note 2, “Segmental Information”. For more information see note 19.

__________________________________________________________________________________________________


Notes to the Accounts continued for the year ended 31 December 2014 10. Tax Credit continued b) Factors affecting tax credit The tax credit for the year is lower than the standard rate of corporation tax in the UK of 21.5% (2013: 23.25%). The difference is explained below: Year ended Year ended 31 December 2014 31 December 2013 $’000 $’000

Group loss before taxation (59,069) (37,602)

Tax on Group loss before taxation at an effective rate of 21.5% (2013: 23.25%)

12,700 8,742

Effects of: Expenses not deductible for corporate income tax purposes ‐ (724) Impact of net movements in deferred tax not recognised (13,880) (10,131) Utilisation of substantial shareholder relief 489 ‐ Utilisation of brought forward losses ‐ (24) Effects of higher supplementary charges to corporation tax ‐ (145) Effects of different corporate tax rates on UK and overseas earnings 691 2,857 Adjustment in respect of prior years – current tax 121 (22) Effects of overseas deferred tax – origination and reversal of temporary differences ‐ 492

Total current tax credit for year 121 1,045

c) Factors that may affect future tax expense The Group has gross corporate income tax and supplementary hydrocarbon tax losses of $63.5 million (2013: $64.1 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 foreseeable future. Corporate tax amendments: UK: A reduction in the UK corporation tax rate from 23% to 21% (effective from 1 April 2014) was substantively enacted on 2 July 2013. A further reduction to 20% (effective from 1 April 2015) was also substantively enacted on 2 July 2013. This will reduce the Group’s future tax charge.

Other countries of operation: Italy: On 23 March 2015 the Italian Constitutional Court issued a decision ruling that the 10.5% “Robin Hood” tax on companies operating in the fields of hydrocarbons exploration and development, oil refining, production and sale of petrol, oil, diesel, lubricants, liquefied natural gas and liquefied petroleum gas and the production and sale of electricity, was an illegitimate tax. Since the issue of the last Annual Report, there have been no other 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.

__________________________________________________________________________________________________


Notes to the Accounts for the year ended 31 December 2014 11. Basic (Loss) / Earnings Per Share Basic 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. 2014 2013 $’000 $’000

Net loss attributable to equity holders used in basic calculation (42,958) (39,331)

Net loss attributable to equity holders used in dilutive calculation (42,958) (39,331)

Number Number ‘000 ‘000

Basic weighted average number of shares 95,366 95,366 Dilutive potential of ordinary shares: Warrants exercisable under Company schemes

‐ ‐

Diluted weighted average number of shares 95,366 95,366

At 31 December 2014 and 31 December 2013 there were no warrants with exercise prices below the average share trading price for those years, hence the number of potential dilutive ordinary shares is Nil (2013: Nil). 2014 2013

Earnings per share Basic earnings per share on loss for the year (cents) (45.0) cents (41.2) cents Diluted earnings per share on loss for the year (cents) (45.0) cents (41.2) cents

Earnings per share – continuing operations Basic earnings per share on loss for the year (cents) (45.0) cents (38.3) cents Diluted earnings per share on loss for the year (cents) (45.0) cents (38.3) cents

As the Group is loss making, there is no dilution of earnings from potential ordinary shares.

__________________________________________________________________________________________________


Notes to the Accounts continued for the year ended 31 December 2014 12. Intangible Assets a) Exploration and Evaluation Assets Intangible assets consist of the Group's exploration projects which are pending determination of technical feasibility and commercial viability of extracting a mineral resource.

Notes

United Kingdom Italy Canada

French Guiana

Other incl. Australia Total

$’000 $’000 $’000 $’000 $’000 $’000

Cost:

At 1 January 2014 7,700 40,913 3,223 36,531 395 88,762

Additions (11) 481 9,318 (188) 921 10,521

Government grants and assistance 8 ‐ (255) ‐ ‐ ‐ (255)

Disposals (7,457) (9,671) ‐ ‐ ‐ (17,128)

Transfers 13 ‐ ‐ (7,684) ‐ ‐ (7,684)

Exchange movement (232) (5,034) (1,116) (8) (103) (6,493)

At 31 December 2014 ‐ 26,434 3,741 36,335 1,213 67,723

Exploration expenditure written off:

At 1 January 2014 7,370 11,012 ‐ ‐ 158 18,540

Impairment losses 108 7 ‐ 36,335 ‐ 36,450

Disposals (7,247) (9,671) ‐ ‐ ‐ (16,918)

Exchange movement (231) (1,348) ‐ ‐ ‐ (1,579)

At 31 December 2014 ‐ ‐ ‐ 36,335 158 36,493

Net book value:

At 31 December 2014 ‐ 26,434 3,741 ‐ 1,055 31,230

Negative cost additions for the year in respect of UK and French Guiana assets arise as a result of adjustments to joint venture partner 2013 year end cost estimates notified by the operators.

During the year the Group received further rebates and discounted loans from the Italian government as part of a scheme to encourage the acquisition of seismic surveys. The Group successfully applied using the scheme in respect of the seismic survey acquired in 2012 over licences in the Southern Adriatic. Government grants relating to intangibles and property, plant and equipment are recognised as a reduction in the costs of the related assets. Government loans advanced at below market interest rates are measured in accordance with IAS39, "Financial Instruments: Recognition & Measurement". The benefits of the below market rate of interest shall be measured as the difference between the initial carrying value of the loan determined in accordance with IAS39 and the proceeds received. The benefit is also treated as a government grant and recognised as a reduction in the cost of the asset.

Disposals in the year relating to the UK assets are in relation to the sale of three UK subsidiaries to UK Oil & Gas Investments PLC, (UKOG), in October 2014, (see note 4). Disposals in the year in Italy relate to licences that had either expired or been relinquished and that were fully impaired at the end of 2013. UK and Italian costs incurred in the year on licences that were subsequently relinquished were fully impaired before disposal.

Additions for Canadian exploration and wells drilled in Q1 2014 of $7,684,000 were subsequently transferred to property, plant and equipment.

The Group tests intangible assets for impairment when there is an indication that assets might be impaired. An impairment loss of $36.3 million has been recognised against the French Guiana cost pool. The French Guiana drilling programme was completed in 2013 and Shell, the operator, is currently incorporating the results from the 2013 wells into its geological model to better understand the considerable remaining prospectivity and determine the future licence work programme. While subsurface analysis is still ongoing any future exploration or appraisal wells are contingent on the satisfactory outcome of this analysis and would most likely require an extension of the licence which expires in mid 2016. With this level of uncertainty concerning future exploration, it has been deemed appropriate to impair the full value of this asset at this time.

__________________________________________________________________________________________________


Notes to the Accounts for the year ended 31 December 2014 12. Intangible Assets continued The Directors continue to pursue ways of realising the value of its interest in the French Guiana licence. The assets in French Guiana are held through Northpet Investments Limited 55.9% of which is owned by the Group. As the Group has a controlling interest in Northpet Investments, this company is fully consolidated in the Group accounts as a subsidiary and the 44.1% Non‐controlling interest of Hague and London Oil PLC, (“HALO”), (formerly Wessex Exploration PLC), is separately disclosed on the face of the Consolidated Statement of Profit or Loss and in Equity on the face of the Consolidated Statement of Financial Position. Of the $36.5 million loss in the year in respect of French Guiana, (see note 2), which includes the impairment losses of $36.3 million shown in this note, $20.5 million relates to the Group’s interest and $16.0 million to HALO’s Non‐controlling interest in Northpet Investments Limited. At the year end the contractual commitments for capital expenditure in respect of intangible assets was $47,000 (2013: $2,169,000), of which the Group’s share was $26,300 (2013: $2,131,000). The comparative tables for 2013 are detailed below:

Netherlands $’000

United

Kingdom $’000

Italy $’000

Canada $’000


Other incl. Australia

$’000

Total $’000

Cost: At 1 January 2013 23,833 7,615 15,912 ‐ 181 157 47,698 Additions 287 285 1,310 3,202 4,088 255 9,427 Business acquisitions ‐ ‐ ‐ 356 32,527 ‐ 32,883 Government grants and assistance ‐ ‐ (2,853) ‐ ‐ ‐ (2,853) Disposals (24,120) ‐ ‐ ‐ ‐ ‐ (24,120) Transfers ‐ ‐ 26,544 ‐ ‐ ‐ 26,544 Exploration expenses written off Exchange movement ‐ (200) ‐ (335) (265) (17) (817)

At 31 December 2013 ‐ 7,700 40,913 3,223 36,531 395 88,762

Exploration expenditure written off: At 1 January 2013 137 63 ‐ ‐ ‐ 39 239 Impairment losses ‐ 7,308 11,013 ‐ ‐ 119 18,440 Disposals (137) ‐ ‐ ‐ ‐ ‐ (137) Exchange movement ‐ (2) ‐ ‐ ‐ ‐ (2)

At 31 December 2013 ‐ 7,369 11,013 ‐ ‐ 158 18,540

Net book value: At 31 December 2013 ‐ 331 29,900 3,223 36,531 237 70,222

2013 Impairment The Group tests intangible assets for impairment when there is an indication that the assets might be impaired. The Directors undertook an impairment review to assess the carrying value of intangible assets in relation to the value of prospective resources by cost pool. Following the disposal of the Netherlands in October 2013 the Board reassessed the strategic priorities of the Group. As a result of this decision certain assets were impaired as they no longer had an active exploration or development programme. Impairments of $7,308,000 were recognised in the UK in respect of the Sandhills and Bouldnor Copse wells drilled in 2005, the Havant prospect and past and current exploration licences. An impairment of $11,013,000 was recognised in Italy for Po Valley exploration, (including the Savio and La Tosca wells), the Sicily Channel "Thrust Belt", and other onshore exploration licences.

__________________________________________________________________________________________________


Notes to the Accounts continued for the year ended 31 December 2014 12. Intangible Assets continued b) IT Systems Computer software $’000

Cost: At 1 January 2014 4,136 Additions ‐

At 31 December 2014 4,136

Amortisation:

At 1 January 2014 1,448 Charge for the year 827 Impairment losses 744


Net book value:



Impairment losses in the year relate to accounting and procurement IT systems implemented in early 2012. Following the disposals of three UK operating subsidiaries during the year and of the Netherlands subsidiary in 2013, the Directors have impaired the carrying value of these systems by 40% to reflect the redundancy of system modules and functionality previously used to meet joint venture agreement requirements.

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Notes to the Accounts for the year ended 31 December 2014 13. Property, Plant and Equipment a) Oil and Gas Assets

Notes UK ‐ UK ‐ Canada – Canada –

Developed Undeveloped Developed Undeveloped Total $’000 $’000 $’000 $’000 $’000

Cost:

At 1 January 2014 1,152 5,964 ‐ 33 7,149

Additions ‐ 186 11,885 141 12,212

Disposals (1,080) (5,989) ‐ ‐ (7,069)

Transfers 12 ‐ ‐ 7,684 ‐ 7,684

Exchange movement (72) (161) (117) (29) (379)

At 31 December 2014 ‐ ‐ 19,452 145 19,597

Depletion and amortisation:

At 1 January 2014 1,070 5,963 ‐ ‐ 7,033

Charge for the year 12 ‐ 783 ‐ 795

Impairment losses ‐ ‐ 15,313 ‐ 15,313

Disposals (1,018) (5,801) ‐ ‐ (6,819)

Exchange movement (64) (162) (36) ‐ (262)

At 31 December 2014 ‐ ‐ 16,060 ‐ 16,060

Net book value:

At 31 December 2014 ‐ ‐ 3,392 145 3,537

Additions for Canadian mineral rights, exploration expenditure and wells drilled in Q1 2014 of $7,684,000 initially recorded as expenditure on intangible oil and gas assets, was subsequently transferred to property, plant and equipment following the successful testing of the wells. Canadian cost additions of $11,885,000 included the development wells in the second half of 2014. Following the drilling of the development wells, the halving of the oil price in late 2014 and after a review of the performance of all the producing wells, the Directors have considered whether each of the Canadian wells should be impaired. Having regard to the work carried out by GLJ Petroleum Consultants Limited, the Group’s reserve auditors in Canada, and the Canadian Oil and Gas Evaluation Handbook (COGEH) guidelines, the Directors have recognised impairment losses of $15.3 million against Canadian developed assets. In reaching these judgments the Directors have used a discount rate of 10% and average oil prices of $50 in 2015 rising to $85 by 2017. Disposals in the year relate to licences in UK that were held by the Group's three subsidiaries sold to UK Oil & Gas Investments PLC on 19 October 2014. At the year end the contractual commitments for capital expenditure in respect of property, plant and equipment was $327,000 (2013: $Nil), of which the Group’s share was $327,000 (2013: $Nil).

__________________________________________________________________________________________________


Notes to the Accounts continued for the year ended 31 December 2014 13. Property, Plant and Equipment continued The comparative tables for 2013 are detailed below:

Netherlands ‐Developed

Netherlands ‐Undeveloped

UK ‐ Developed

UK ‐ Undeveloped

Italy ‐Undeveloped

Canada – Undeveloped

Total

$’000 $’000 $’000 $’000 $’000 $’000 $’000

Cost: At 1 January 2013 50,504 10,503 1,205 5,493 24,568 ‐ 92,273 Additions 1,506 123 4 583 543 ‐ 2,759 Business acquisitions ‐ ‐ ‐ ‐ ‐ 37 37 Disposals (52,010) (10,626) ‐ ‐ ‐ ‐ (62,636) Transfers ‐ ‐ ‐ ‐ (25,111) ‐ (25,111) Exchange movement ‐ ‐ (57) (112) ‐ (4) (173)

At 31 December 2013 ‐ ‐ 1,152 5,964 ‐ 33 7,149

Depletion and amortisation: At 1 January 2013 26,799 ‐ 998 ‐ ‐ ‐ 27,797 Charge for the year 3,166 ‐ 95 ‐ ‐ ‐ 3,261 Impairment losses ‐ ‐ ‐ 5,963 ‐ ‐ 5,963 Disposals (29,965) ‐ ‐ ‐ ‐ ‐ (29,965) Exchange movement ‐ ‐ (23) ‐ ‐ ‐ (23)

At 31 December 2013 ‐ ‐ 1,070 5,963 ‐ ‐ 7,033

Net book value: At 31 December 2013 ‐ ‐ 82 1 ‐ 33 116

2013 Impairment On 9th April 2014 the Group announced that following an operating committee meeting with the operator of licence PEDL233 containing the Baxters Copse discovery, and subsequent to an internal exercise analysing the Markwells Wood discovery in PEDL126, the 4.3 million barrels of 2P reserves assigned to these assets had been reclassified as 2C contingent resource. While both assets had the potential to be commercial discoveries, the Group believed that further appraisal needed to be undertaken to produce a viable development plan which would lead to commercial production. The UK undeveloped oil and gas assets were fully impaired resulting in a charge of $5,963,000.

__________________________________________________________________________________________________


Notes to the Accounts for the year ended 31 December 2014 13. Property, Plant and Equipment continued b) Non‐Oil and Gas Assests

Leasehold

improvements Computer and

office equipment Total $’000 $’000 $’000

Cost: At 1 January 2014 545 1,754 2,299 Additions 3 97 100 Disposals (58) ‐ (58)

At 31 December 2014 490 1,851 2,341

Depreciation:

At 1 January 2014 440 1,127 1,567 Charge for the year 18 267 285 Impairment losses 90 ‐ 90 Disposals (58) ‐ (58)

At 31 December 2014 490 1,394 1,884

Net book value:

At 31 December 2014 ‐ 457 457

At 31 December 2013 105 627 732

Impairment losses in the year relate to the fit out of the Group’s head office. The Directors have decided to impair the carrying value of leasehold improvements following the disposal of one of the office floor leases and the planned relocation of the head office in April 2015.

__________________________________________________________________________________________________


Notes to the Accounts continued for the year ended 31 December 2014 14. Investments Unlisted Investments $’000

Unlisted investments – cost: At 1 January 2014 183 Disposals (184) Exchange movement 1

At 31 December 2014 ‐

On 9 May 2014 the Group disposed of its investment in Liberty GTL Inc. for a consideration of $150,000 (note 4). On 15 July 2014, Oil & Gas Investments Limited (O&GI), an associated undertaking of the Group was dissolved. In 2013 as part of the impairment review of certain UK assets, the Group had made a full provision against the value of its investment in O&GI ($20,000), as it was deemed irrecoverable. The Group’s material subsidiary undertakings which are included within these consolidated accounts are:

Country of Principal Description and Incorporation / Principal country proportion of registration activity of operation shares held

Northern Petroleum (UK) Limited England & Wales Oil and gas exploration

Italy Ordinary shares of £0.001–100%

NP Netherlands Limited England & Wales Oil and gas exploration UK Ordinary shares of £1–100%

NP Offshore Holdings (UK) Limited England & Wales Holding company UK Ordinary shares of £1–100%

NP Oil & Gas Holdings Limited England & Wales Holding company UK Ordinary shares of £1–100%

Northern Petroleum E&P Holdings Limited

England & Wales Holding company UK Ordinary shares of £0.0025‐100%

ATI Oil (Onshore) Limited England & Wales Holding company UK Ordinary shares of £1–100%

Northpet Investments Limited England & Wales Oil and gas exploration France (French Guiana)

Ordinary shares of £1–55.90%

Ouro Preto Resources Inc Canada Oil and gas exploration, development and

production

Canada (Alberta)

Ordinary shares of $1–100%

Ouro Preto Resources Pty Limited Australia Oil and gas exploration Australia (South

Australia)


On 19 October 2014 three of the Group’s UK operating subsidiaries Northern Petroleum (GB) Limited, NP Solent Limited and NP Weald Limited were sold to UK Oil and Gas Investments PLC, (“UKOG”), see note 4).

__________________________________________________________________________________________________


Notes to the Accounts for the year ended 31 December 2014 14. Investments continued The comparative table for 2013 is detailed below: Unlisted Investments $’000

Cost:

At 1 January 2013 9,255

Additions 7,428

Share of losses of joint ventures (44)

Impairment losses (20)

Disposal (15,816)

Exchange movement (620)

At 31 December 2013 183

15. Inventories 2014 2013 $’000 $’000

Crude oil ‐ 1 Spare parts ‐ 43

‐ 44

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 (2013: $Nil).

16. Trade and Other Receivables 2014 2013 $’000 $’000

Current assets Trade receivables 292 492 Corporation tax receivable 85 ‐ Other receivables 155 39 VAT recoverable 456 1,303 Prepayments and accrued income 585 521

Total trade and other receivables 1,573 2,355

Current trade and other receivables, and loans have a fair value that approximates to their book value at both balance sheet dates. At 31 December 2014 the Group had still to receive payment from the Avobone group for monies owing from the drilling of the Savio 1x well, ($1,709,000). In 2013 $1,433,000 of the sum owing was transferred to intangible assets and subsequently impaired. In March 2015 the Group agreed a settlement with the Avobone Group involving a cash payment and transfer of a VAT debtor of €869,000 ($1,052,000). The Group is pursuing the recovery of the VAT debtor, but the timing of any cash receipts is uncertain and could take a number of years. During the year the Group's associate company Oil & Gas Investments Limited, (O&GI), was dissolved. $49,000 (2013: $Nil), trade debtors due from O&GI, were written off in the year of which $46,000 had been provided against in 2013. Of the $292,000 owing at 31 December 2014, $242,000 was overdue (2013: $407,000). The $242,000 overdue amount, which was more than one year old, was received in March 2015. Note 23, “Financial Instruments” presents an analysis of the carrying values of the Group’s trade and other receivables and cash and cash equivalents by currency.

__________________________________________________________________________________________________


Notes to the Accounts continued for the year ended 31 December 2014 17. Trade and Other Payables 2014 2013 $’000 $’000

Current Liabilities Trade payables 1,456 345 Corporation tax liability ‐ 145 Taxation and social security 39 189 Italian government loans 401 421 Other payables 13 ‐ Accruals and deferred income 3,324 2,575

5,233 3,675

Non‐Current Liabilities Italian government loans 921 1,229 Accruals and deferred income 9 19

930 1,248

Total trade and other payables 6,163 4,923

Trade and other payables, except for Italian government loans which were initially held at fair value on receipt and whose fair value discount has been unwound during the year at a market interest rate, are measured at amortised cost and their book value approximates to fair value at 31 December 2014 and 2013. All current liability trade and other payables are considered due within three months, apart from the Italian government loans which are repayable in twelve months. Non‐current government loans are repayable over three to five years. Non‐current accruals are payable over two years. Note 23, “Financial Instruments” presents analysis of the carrying values of the Group’s trade and other payables by currency and by timing of utilisation.

__________________________________________________________________________________________________


Notes to the Accounts for the year ended 31 December 2014 18. Provisions 2014 2013 $’000 $’000

At 1 January 1,152 13,010 Additions 1,316 1,043 Acquisitions ‐ 37 Disposals (593) (13,310) Utilised (502) (50) Unwinding of timing discount 7 437 Exchange movement (80) (15)

At 31 December 1,300 1,152

The amount provided at 31 December 2014 represents the Group’s share of decommissioning liabilities in respect of its Canadian wells. Additions in the year relate to decommissioning liabilities in respect of the Canadian wells drilled during 2014 in north west Alberta. Disposals in the year are in respect of UK wells and sites at Markwells Wood, Havant, Horndean and Avington, following the sale of three Group subsidiaries to UK Oil & Gas Investments PLC in October 2014, (see note 4). Amounts utilised in the year relate to French Guiana supply bases in Cayenne and Trinidad and final amounts in respect of the Italy La Tosca well site. As part of the Group’s entry into Alberta, Canada, the group signed an introductory agreement with Grail Energy Canada Limited, a Canadian private company owned by certain current and former employees and contractors of the Group. The agreement provided for a payment to be made to Grail Energy no earlier than 2016 based on a percentage of the value of certain Canadian based assets, taking into account the future net income and capital invested associated with those assets. The Directors believe that at this time there is no value for this potential future payment and therefore no provision has been made. The estimated timing of utilisation of decommissioning provisions is analysed as follows: 2014 2013 $’000 $’000

<1 year ‐ 502 1 to 2 years ‐ 537 3 to 5 years 670 ‐ 6 to 10 years 422 33 11 to 20 years 208 ‐ >20 years ‐ 44 Awaiting determination ‐ 36

Total decommissioning provisions 1,300 1,152

The carrying values of the Group’s decommissioning provisions are denominated in the following currencies: 2014 2013 $’000 $’000

Euro ‐ 10 UK Sterling ‐ 614 US Dollar ‐ 492 Canadian Dollar 1,300 36

Total decommissioning provisions 1,300 1,152

__________________________________________________________________________________________________


Notes to the Accounts continued for the year ended 31 December 2014 19. Deferred Taxation 2014 2013 $’000 $’000

Balance at start of year (3,333) (18,918) Deferred tax liability recognised in statement of profit or loss ‐ 458 Movement in overseas tax liability ‐ 492 Additions ‐ (55) Disposals ‐ 14,683 Exchange movement 406 7

Balance at end of year (2,927) (3,333)

Comprising: Other temporary differences (2,927) (3,333)

Movements in deferred tax not recognised (2,927) (3,333)

Of the $2,927,000 other temporary differences, $2,881,000 (2013: $3,283,000) arises on the fair value adjustment for the assets acquired in Italy as part of the ATI acquisition and $46,000 (2013: $50,000) arises on the fair value adjustment for the assets acquired in Canada. These deferred tax adjustments arising on the fair value of assets acquired 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: 2014 2013 $’000 $’000

Other timing differences 39,266 861 Tax losses 63,540 53,600

Gross unrecognised temporary differences 102,806 54,461

__________________________________________________________________________________________________


Notes to the Accounts for the year ended 31 December 2014 20. Share Capital 2014 2013 $’000 $’000

Allotted, issued, called up and fully paid: 95,365,660 (2013: 95,365,660) ordinary shares of 5p each 8,225 8,225

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. 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 2014 are as follows:

Exercise

price

At 1 January

2014

New issues

Exercised

Lapsed or cancelled

At 31 December

2014 Issue date Final exercise date pence ‘000s ’000s ‘000s ‘000s ‘000s

12 December 2008 30 June 2014 67.0p 45 ‐ ‐ (45) ‐

31 December 2008 30 June 2014 68.5p 168 ‐ ‐ (168) ‐

24 June 2009 01 July 2014 252.0p 31.3 ‐ ‐ (31.3) ‐

24 June 2009 01 July 2015 252.0p 31.3 ‐ ‐ ‐ 31.3

06 October 2009 31 December 2014 152.0p 10 ‐ ‐ (10) ‐

12 April 2010 31 December 2014 127.5p 175 ‐ ‐ (175) ‐

04 January 2011 31 December 2015 108.88p 30 ‐ ‐ ‐ 30

04 January 2011 30 June 2016 108.88p 30 ‐ ‐ ‐ 30

15 August 2011 31 December 2014 69.88p 50 ‐ ‐ (50) ‐

21 May 2012 31 December 2014 85.0p 75 ‐ ‐ (75) ‐

18 September 2012 15 July 2016 67.5p 37.5 ‐ ‐ ‐ 37.5

18 September 2012 15 July 2017 67.5p 37.5 ‐ ‐ ‐ 37.5

14 November 2012 15 July 2016 66.0p 37.5 ‐ ‐ ‐ 37.5

14 November 2012 15 July 2016 66.0p 37.5 ‐ ‐ ‐ 37.5

21 May 2013 30 June 2016 100.0p 100 ‐ ‐ ‐ 100

21 May 2013 30 June 2017 100.0p 100 ‐ ‐ ‐ 100

995.6 ‐ ‐ (554.3) 441.3

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 48% (2013: 48%). Risk free investment rates between 0.52% and 2.79% (2013: 0.35% and 3.37%) have also been assumed in the calculations. The weighted average exercise price of all the warrants outstanding as at 31 December 2013 was 100.67p (2013: 100.97p). The weighted average remaining contractual life of all the warrants outstanding as at 31 December 2013 was 1 year 10 months. There are no outstanding conditions attached to the exercise of the warrants remaining in issue at year end.

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Notes to the Accounts continued for the year ended 31 December 2014 21. Commitments Operating leases The Group’s commitments for rental payments under non‐cancellable operating leases payable during the year to 31 December 2013 are as follows: 2014 2014 2013 2013 Other operating

leases Land and buildings

Other operating leases

Land and buildings

$’000 $’000 $’000 $’000

Payable : Within one year 30 465 41 833 Between one and five years 90 620 164 2,019 After five years ‐ ‐ ‐ ‐

120 1,085 205 2,852

All leases are "operating leases" and the relevant annual rentals are charged to the statement of profit or loss on a straight line basis over the lease term. The Group has one leased office in the UK. General renewal clauses exist on all leases. 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 for the landlord. 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 UK office lease is in respect of two floors of Martin House, the Group's registered office; one floor is currently occupied by the Group Head Office. In March 2014 the lease on the other floor was assigned to a third party. The third party will incur all associated costs of the floor they occupy until the end of the lease term with Northern Petroleum acting as a guarantor. The Group leases an office in Canada the agreement for which expires on 29 February 2016.The Group’s offices in Rome and Australia are rented from month to month. Following the year end the lease relating to the remaining floor in Martin House was under negotiation to be assigned to a third party and negotiations are ongoing.

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Notes to the Accounts for the year ended 31 December 2014 22. Related Party Transactions Details of transactions and year end balances with Directors and senior management of the Company, or with companies that were at some stage during 2014 non‐wholly owned subsidiaries or joint ventures or associates, are as follows: Oil & Gas Investments

Limited (Group)

$’000

Receivables balance at 31 December 2014 ‐

Receivables balance at 31 December 2013 48

Amounts invoiced to Northern Petroleum Group in 2014: ‐billings for services ‐ Amounts invoiced by Northern Petroleum Group in 2014: ‐ project billings under Joint Operating Agreements 5 ‐ other billings ‐

Amounts invoiced to Northern Petroleum Group in 2013: ‐billings for services ‐ Amounts invoiced by Northern Petroleum Group in 2013: ‐ project billings under Joint Operating Agreements 11 ‐ other billings ‐

On 15 July 2014, Oil & Gas Investments Limited (O&GI), an associated undertaking of the Group, was dissolved. There were no terms or conditions attached to the outstanding balances above and none of the balances are secured. The Directors consider that 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 14. 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.

__________________________________________________________________________________________________


Notes to the Accounts continued for the year ended 31 December 2014 23. Financial Instruments Financial instruments – Risk Management The Group is exposed through its operations to the following financial risks:

Credit risk

Cash flow interest rate risk

Foreign exchange risk

Liquidity risk

Price risk This note describes the Group’s objectives, policies and processes for managing those risks and the methods used to measure them. 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 instruments The principal financial instruments used by the Group, from which financial instrument risk can arise are as follows:

Loans and receivables

Trade and other receivables

Cash and cash equivalents

Short term investments

Trade and other payables

General objectives, policies and processes The Board has overall responsibility for the determination of the Group’s risk management objectives and policies and, while 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 Finance Director through which it reviews the effectiveness of the processes put in place and the appropriateness of the objectives and policies it sets. The overall objective of the Board is to set policies that seek to reduce risk as far as possible without unduly affecting the Group’s competitiveness and flexibility. Further details regarding these policies are set out below: Credit risk Credit 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. 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 are disclosed in note 16. In the event of any disputes with customers, the Group will always attempt to resolve these in accordance with contractual default procedures, but if ultimately unsuccessful would then resort to legal proceedings.

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Notes to the Accounts for the year ended 31 December 2014 23. Financial Instruments continued Credit risk (continued) 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 envisages losses from non‐performance of counterparties at the lower end of the range between $Nil and $229,000. Cash flow interest rate risk The 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 is not at present exposed to cash flow interest rate risk on borrowings as it only has fixed interest debt at a rate of 0.5% per annum from the Italian government. 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 liabilities The 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 Financial assets which floating rate on which no interest is earned Interest is earned Total $’000 $’000 $’000

2014 Euro 2,646 538 3,184 UK Sterling 1,914 504 2,418 US Dollar 1,074 23 1,097 Canadian Dollar 6,402 510 6,912 Australian Dollar 95 10 105

12,131 1,585 13,716

2013 Euro 8,735 1,457 10,192 UK Sterling 5,932 783 6,715 US Dollar 1,889 105 1,994 Canadian Dollar 19,222 65 19,287 Australian Dollar 50 2 52

35,828 2,412 38,240

The financial assets for each currency largely comprise cash on call accounts and placed on money markets on call and short term debtors.

__________________________________________________________________________________________________


Notes to the Accounts continued for the year ended 31 December 2014 23. Financial Instruments continued Cash flow interest rate risk (continued) The Group earned interest on its interest bearing financial assets at rates between 0% and 0.25% (2013: 0% and 0.6%) during the year. All financial assets on which no interest is earned are considered immediately available to turn into cash on demand. If average interest rates, approximately 0.25% in 2014, had been 100% higher, i.e. 0.5%, the Group’s finance income of $6,000 would have been $12,000. Had average interest rates in 2014 been 50% lower, the Group’s finance income would have been $3,000 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 risk Foreign 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 US Dollars. Only in exceptional circumstances will the Group consider hedging its net investments in non‐US Dollar 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 treasury of the parent company. 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: Australian

Dollar Canadian

Dollar Euro UK Sterling

Foreign currency units to $1 US Dollar (rounded to two decimal places)

Average for 2014 1.11 1.10 0.75 0.61

At 31 December 2014 1.22 1.16 0.83 0.64

Average for 2013 1.03 1.03 0.75 0.64

At 31 December 2013 1.12 1.06 0.72 0.60

__________________________________________________________________________________________________


Notes to the Accounts for the year ended 31 December 2014 23. Financial Instruments continued Foreign exchange risk (continued) Currency exposures The monetary assets and liabilities of the Group that are not denominated in US Dollars are therefore exposed to currency fluctuations and are shown below. The amounts shown represent the US Dollar equivalent of local currency balances.

UK Sterling

Euro Canadian

Dollar Australian

Dollar

Total $’000 $’000 $’000 $’000 $’000

US Dollar equivalent of exposed net monetary assets and liabilities

At 31 December 2014 1,914 2,646 6,402 95 11,057

At 31 December 2013 5,932 8,735 19,222 50 33,939

During the year the US Dollar strengthened in value against the Canadian Dollar (8%) and the Euro (12%), resulting in an overall foreign exchange loss for the year of $1,591,000 and exchange differences on translation of foreign operations of $4,407,000 (loss).

Had the US Dollar risen in value against the Canadian Dollar by 10% the overall foreign exchange loss would have been $443,000 higher. Had the US Dollar fallen in value against the Canadian Dollar by 5% the overall foreign exchange loss would have been $3,490,000 lower.

Had the US Dollar risen in value against the Euro by 10% the overall foreign exchange loss would have been $696,000 lower. Had the US Dollar fallen in value against the Euro by 5% the overall foreign exchange loss would have been $5,490,000 lower.

A number of the Company’s subsidiaries use Sterling, Canadian Dollars or Euros as their functional currency so movements in the US Dollar / Sterling, US Dollar / Canadian Dollar and Euro / US Dollar exchange rates most significantly affect the Group’s statement of financial position, with exchange differences that arise on consolidation being taken to reserves. Canadian oil revenues in Canadian Dollars are set by reference to US Dollar index prices, while the majority of costs incurred on the Canadian assets will be in Canadian Dollars. In addition, the anticipated exploration programme in the Southern Adriatic, Italy is expected to have Euro capital expenditure requirements going forward. As a consequence of all of the above, exchange gains or losses will continue to be reported within future statements of profit or loss. 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, other than the loans from the Italian government forwarded under the scheme to encourage oil and gas exploration in Italy.

__________________________________________________________________________________________________


Notes to the Accounts continued for the year ended 31 December 2014 23. Financial Instruments continued Liquidity risk (continued) While the Group has cash resources of approximately $12 million (2013: $36 million) and low levels of external debt at the year end, the Board recognise that the cost base and structure of the business must be appropriately positioned for efficient use of these funds and the Directors have implemented further overhead reduction measures. These will bring some immediate cash savings during 2015. All long term commitments continue to be monitored in order to make sure that no expenditure is incurred which would take the Group’s cash balance below a level necessary to maintain ongoing operations. Costs and commitments are monitored on a frequent basis and more so while the Group is going through the current phase of change. Taking into consideration the Group’s year end cash position and future revenue from existing oil and gas fields, the Group has adequate financial resources to meet the costs of the Group’s current financial commitments. However, further development or drilling in Canada and appraisal activities on the Group’s assets in Italy will require external capital, which may come from the farm out of existing assets, the sale of non‐core assets or debt or equity. The Board’s review of the accounts, budgets and financial plan lead the Directors to believe that the Group has sufficient resources to continue in operation at least until the end of 2015. The financial statements are therefore prepared on a going concern basis. Price risk Oil revenue is subject to energy market price risk. Had average oil prices in 2014 been 10% higher, the Group’s oil revenue of $2,713,000 would have been $271,300 higher. Had average oil prices in 2014 been 10% lower, the Group’s oil revenue would have been $271,300 lower. Given current production levels 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 2015 and beyond given the Group’s current cash flow. Financial liabilities The Group’s financial liabilities consist of trade and other payables. The interest rate profile at 31 December of these liabilities was as follows: Financial Financial liabilities on liabilities on which interest which no interest is paid is paid $’000 $’000

2014 Euro 1,322 223 UK Sterling ‐ 805 US Dollar ‐ 101 Canadian Dollar ‐ 3,705 Australian Dollar ‐ 7

1,322 4,841

2013 Euro 1,650 660 UK Sterling US Dollar

‐ ‐

1,819 401

Canadian Dollar Australian Dollar

‐ ‐

365 28

1,650 3,273

The Group’s short term creditors are considered payable on demand.

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Notes to the Accounts for the year ended 31 December 2014 23. Financial Instruments continued Capital management policies 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. In order to achieve and seek to maximise this return objective, the Group may 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, or increases or reductions in debt, the Group considers not only its short term position but also its medium and longer term operational and strategic objectives. 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. Cash Generated from Operations (note to consolidated cash flow statement)

Year ended Year ended31 December 31 December

2014 2013Notes $’000 $’000

Cash flows from operating activities Loss for the year (58,948) (39,350) Tax (credit) / charge 10 (121) 1,593 Depletion and amortisation 13 795 3,262 Depreciation – non‐oil and gas property, plant and equipment 12 & 13 1,112 1,186 Impairment losses on intangible assets 12 37,194 18,440 Impairment losses on property, plant and equipment 13 15,403 5,963 Impairment losses on investments ‐ 19 Provision for bad debts 23 3 46 Profit on disposal of subsidiaries, investments and property, plant and equipment 4 (2,344) (14) Loss on disposal of discontinued operation, net of tax ‐ 5,926 Foreign exchange loss 8 1,591 1,474 Finance income 9 (6) (66) Finance charges 8 176 1,298 Share‐based payments 3 & 20 19 391 Share of operating loss in joint ventures ‐ 44

Net cash (outflow) / inflow before movements in working capital (5,126) 212 Increase in inventories ‐ (41) Decrease in trade and other receivables 739 5,621 Increase / (decrease) in trade and other payables 1,809 (2,641)

Net cash inflow from changes in working capital 2,548 2,939

Cash generated from operations (2,578) 3,151

__________________________________________________________________________________________________


Notes to the Accounts continued for the year ended 31 December 2014 25. Post Balance Sheet Events Since the balance sheet date 31 December 2014 and the date that these financial statements have been signed, the following developments have been announced which have a material impact on, or the understanding of, these financial statements: Italy onshore farm out On 5 March 2015 the Group announced the farm out of an 80 per cent equity interest in the Cascina Alberto permit and transfer of operatorship to Shell Italia. Shell Italia will pay US$850,000 in cash on completion and will carry Northern Petroleum for the costs of the exploration campaign, which will include a carry on the acquisition of any new seismic until the seismic costs reach US$4 million and a carry on any exploration well until the well costs reach US$50 million. Shell Italia have a pre‐emptive right over the Company's remaining interest in the Cascina Alberto permit in the event of any change in control at the asset or corporate level. Completion is subject to approval of the interest transfer by the Italian regulatory authority. Canada operations update On 10 February 2015 the Group announced that the Well 102/11‐30, targeting a reef previously undrilled by the Group, was drilled and tested as planned. A significant reef section was encountered, as forecast from seismic interpretation. Two separate zones isolated and tested: a lower zone which was water wet and an upper zone which produced oil, but with too high a water cut to be economic in the current oil price environment. The well was suspended for further evaluation. Included in the impairment to Plant, Property and Equipment, note 13, is an impairment of $825,000 for the 102/11‐30 well long lead items and preliminary work incurred prior to the year end. A full assessment of the impairment of the completed well will be made once the review of the well results has been completed and will be included in the Interim Report. Corporate update and Board change On 31 March 2015 the Group released a corporate update on activity in Canada and Italy and announced that Stewart Gibson was stepping down from the Board as part of a wider cost saving exercise which included the planned relocation of the Group’s Head Office.

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Unaudited Statement of Net Commercial Oil & Gas Reserve Quantities – Proven and Probable Reserves At 31 December 2014 Volumes – Group Petroleum Million

boe

At 31 December 2013 0.06 Changes during the period: Additions 0.32 Disposals (0.05) Production (0.04)

At 31 December 2014 0.29

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. The classification of reserves has been done in accordance with Canadian Oil and Gas Evaluation Handbook (COGEH) guidelines as referenced in (Canadian) National Instrument 51‐101 (NI‐51‐101).

2. Canadian proven and probable reserves are the most recent estimates as determined during the first quarter of 2015 in an

independent review by GLJ Petroleum Consultants Ltd. of Calgary, Alberta, Canada.

3. During the year the Group disposed of its subsidiary Northern Petroleum (GB) Limited with interests in the Horndean and Avington UK onshore oil fields to UK Oil & Gas Investments PLC.

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Company Balance Sheet at 31 December 2014 Notes 2014 2013 $’000 $’000 Represented*

Fixed assets Intangible assets 2 1,117 2,688 Tangible assets 3 433 725 Investments 4 45,356 65,477

Total fixed assets 46,906 68,890 Current assets Debtors – due within one year 5 1,943 21,318 Cash at bank and in hand 9,823 15,996

11,766 37,314 Creditors: amounts falling due within one year 6 (3,460) (4,587)

Net current assets 8,306 32,727

Total assets less current liabilities Creditors: amounts falling due after more than one year 6 (8) (19)

Net assets 55,204 101,598

Capital and reserves Called up share capital 7 8,225 8,225 Share premium 8 17,312 17,312 Merger reserve 8 14,190 14,190 Share incentive plan reserve 8 484 861 Profit and loss account & other distributable reserves 8 14,993 61,010

Shareholders’ funds 9 55,204 101,598

*Following the change in presentational currency, as detailed in note 1, the comparative Statement of Financial Position has been represented in US Dollars.

The notes on pages 79 to 85 form part of these financial statements. These financial statements were approved and authorised for issue by the Board of Directors on 17 April 2015 and were signed on its behalf by:

K R Bush N T Morgan Director Director

REGISTERED NO. 02933545

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Notes to the Company Accounts at 31 December 2014 1. Accounting Policies The 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 preparation The 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 $46,413,000 (2013: profit of $14,551,000). 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 preparation After making appropriate enquiries, the Directors have a reasonable expectation that the Company has adequate resources to meet all of its commitments and to continue in operational existence for the foreseeable future. Accordingly the Board continue to believe that it is appropriate to adopt the going concern basis in preparing the Annual Report and Accounts. For further details of the going concern basis of preparation see note 1 to the Group financial statements. Changes in functional and presentational currency The functional currency is the currency of the primary economic environment in which an entity operates. Following the successful well programme completed in Canada in Q1 2014 and the change in the Group’s strategy, which included the sale of the Netherlands subsidiary in Q4 2013, the Directors considered The Company’s functional currency. From the start of 2014 the majority of the Group’s and by extension the Company’s underlying transactions were expected to be denominated in or heavily influenced by the US Dollar. Therefore the Directors took the decision to prospectively change the Company functional currency from 1 January 2014. Consistent with the change in the Company’s functional currency, the Company has also changed its presentation currency from Euro to US Dollars with effect from 1 January 2014. Comparative figures for all 2013 primary statements, plus the opening 2013 balance sheet have therefore been re‐presented in US Dollars at a rate of 1.3791 USD to 1 EUR as reported by the US Federal Reserve System on their website http://www.federalreserve.gov. The change of the Company’s functional currency was accounted for in accordance with SSAP 20 “Foreign Currency Translation”. On the change of the Company’s presentation currency, the Company prior year comparative accounts have been represented. The change of the Company’s functional currency was accounted for prospectively from 1 January 2014. Accordingly the assets, liabilities and equity items of the Company as at 31 December 2013 were translated from Euro into US Dollars at the closing exchange rate on that date. Turnover Turnover 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 payments The Group has both equity settled and cash settled share based payment schemes.

__________________________________________________________________________________________________


Notes to the Company Accounts continued at 31 December 2014 1. Accounting Policies continued Equity settled share‐based payments In 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. Cash settled share‐based payments In accordance with FRS 20 “Share‐based payments”, for cash‐settled share‐based payment transactions, the Group measures the goods or services acquired and the liability incurred at the fair value of the liability. Until the liability is settled, the Group remeasures the fair value of the liability at each reporting date and at the date of settlement, with any changes in fair value recognised in profit or loss for the period. Fair value is measured by use of a Black Scholes model which takes into account the terms and conditions on which the share appreciation rights were granted, and the extent to which the employees have rendered service to date. 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. Depreciation The cost of fixed assets is written off by equal annual instalments over their expected useful lives, as follows:

Leasehold improvements – over the term of the lease

Computer hardware and software – four or five years

Office equipment – four years The carrying values of tangible fixed assets are reviewed for impairment if events or changes in circumstances indicate the carrying value may not be recoverable. Tangible fixed assets Tangible fixed assets are included in the statement of financial position at cost, less accumulated depreciation and any provisions for impairment. Intangible fixed assets Intangible fixed assets are included in the statement of financial position at cost, less accumulated depreciation and any provisions for impairment. Investments Fixed asset investments are included in the statement of financial position at cost, less any amounts written off. Current asset investments are stated at the lower of cost and net realisable value. Lease Commitments The 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 currencies Foreign 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.

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Notes to the Company Accounts at 31 December 2014 1. Accounting Policies continued Deferred taxation Deferred tax is recognised in respect of all timing differences that have originated but not reversed at the balance sheet date where transactions or events have occurred at that date that will result in an obligation to pay more, or a right to pay less or to receive more, tax, with the following exceptions:

provision is made for deferred tax that would arise on remittance of the retained earnings of overseas subsidiaries, associates and joint ventures only to the extent that, at the balance sheet date, dividends have been accrued as receivable; and

deferred tax assets are recognised only to the extent that the Directors consider that it is more likely than not that there will be suitable taxable profits from which the future reversal of the underlying timing differences can be deducted.

Deferred tax is measured on an undiscounted basis at the tax rates that are expected to apply in the periods in which timing differences reverse, based on tax rates and laws enacted or substantively enacted at the balance sheet date.

2. Intangible Fixed Assets Computer software $’000

Cost: At 1 January 2014 4,136 Additions ‐


Amortisation:

At 1 January 2014 1,448 Charge for the year 827 Impairment losses 744


Net book value:



Impairment losses in the year relate to accounting and procurement IT systems implemented in early 2012. Following the disposals of three UK operating subsidiaries during the year and of the Netherlands subsidiary in 2013, the Directors have impaired the carrying value of these systems by 40% to reflect the redundancy of system modules and functionality previously used to meet joint venture agreement requirements.

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Notes to the Company Accounts continued at 31 December 2014 3. Tangible Fixed Assets

Leasehold

improvements Computer and

office equipment Total $’000 $’000 $’000

Cost: At 1 January 2014 545 1,748 2,293 Additions 3 77 80 Disposals (58) ‐ (58)

At 31 December 2014 490 1,825 2,315

Depreciation:

At 1 January 2014 440 1,127 1,567 Charge for the year 18 265 283 Impairment losses 90 ‐ 90 Disposals (58) (58)

At 31 December 2014 490 1,392 1,882

Net book value:

At 31 December 2014 ‐ 433 433

At 31 December 2013 105 620 725

Impairment losses in the year relate to the fit out of the Group’s head office. The Directors have decided to impair the carrying value of leasehold improvements following the disposal of one of the office floor leases and the planned relocation of the head office in April 2015.

4. Investments Unlisted

Investments Investments in

subsidiaries Total

Investments $’000 $’000 $’000

Cost: At 1 January 2014 20 79,429 79,449 Additions ‐ 7,536 7,536 Disposals (20) (8,792) (8,812)

At 31 December 2014 ‐ 78,173 78,173

Impairment: At 1 January 2014 20 13,952 13,972 Impairment charge ‐ 27,575 27,575 Disposals (20) (8,710) (8,730)

At 31 December 2014 ‐ 32,817 32,817

Carrying value at 31 December 2014 ‐ 45,356 45,356

Carrying value at 31 December 2013 ‐ 65,477 65,477

During 2014 further investments were made in subsidiaries to provide working capital, clear intercompany balances and in the case of NP Oil & Gas Holdings Limited, to ultimately fund the drilling campaign in Alberta, Canada. Impairments of investments were recognised in respect of French Guiana, held via NP Offshore Holdings (UK) Limited, and Canada, held via NP Oil & Gas Holdings Limited.

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Notes to the Company Accounts at 31 December 2014 4. Investments continued 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: Country of Principal Description and Incorporation / Principal country proportion of registration activity of operation shares held

Northern Petroleum (UK) Limited England & Wales Oil and gas exploration Italy Ordinary shares of £0.001–100%

NP Offshore Holdings (UK) Limited England & Wales Holding company UK Ordinary shares of £1–100% NP Oil & Gas Holdings Limited England & Wales Holding company UK Ordinary shares of £1–100% Northpet Investments Limited* England & Wales Oil and gas exploration France

(French Guiana)

Ordinary shares of £1–55.90%

Ouro Preto Resources Inc** Canada Oil and gas exploration, development and production

Canada (Alberta)


* Shares held indirectly through its ownership of NP Offshore Holdings (UK) Limited. ** Shares held indirectly through its ownership of NP Oil & Gas Holdings Limited. The Company has accounted for its investments in subsidiaries at cost, less any amounts written off. On 15 July 2014, Oil & Gas Investments Limited (O&GI), an associated undertaking of the Group was dissolved. In 2013 as part of the impairment review of certain UK assets, the Group had made a full provision against the value of its investment in O&GI ($20,000), as it was deemed irrecoverable.

5. Debtors 2014 2013 $’000 $’000

Amounts falling due within one year: Trade debtors 28 ‐ Other debtors 6 212 VAT recoverable 128 160 Amounts due from subsidiary undertakings 1,506 20,487 Prepayments and accrued income 275 459

Total debtors 1,943 21,318

6. Creditors 2014 2013 $’000 $’000

Amounts falling due within one year: Trade creditors 110 81 Taxation and social security ‐ 174 Other creditors 51 ‐ Amounts due to subsidiary undertakings 2,653 3,278 Accruals and deferred income 646 1,054

3,460 4,587 Amounts falling due after one year: Accruals and deferred income 8 19

3,468 4,606

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Notes to the Company Accounts continued at 31 December 2014 7. Share Capital 2014 2013 $’000 $’000

Allotted, issued, called up and fully paid: 95,365,660 (2013: 95,365,660) ordinary shares of 5p each 8,225 8,225

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 2014 are as disclosed in note 20 of the Group financial statements.

8. Reserves Profit and loss account Share Share and other premium Merger incentive distributable account reserve plan reserve reserves $’000 $’000 $’000 $’000

At 1 January 2014 17,312 14,190 861 61,010 Share‐based payments ‐ ‐ 19 ‐ Transfer between reserves for share warrants lapsed or cancelled during the year ‐ ‐ (396) 396 Loss for the year ‐ ‐ ‐ (46,413)

At 31 December 2014 17,312 14,190 484 14,993

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

9. Reconciliation of Movement in Shareholders’ Funds $’000

Shareholders’ funds at 1 January 2013 86,657 Profit for the year 14,550 Share‐based payments 391

Shareholders’ funds at 1 January 2014 101,598 Loss for the year (46,413) Share‐based payments 19

Shareholders’ funds at 31 December 2014 55,204

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Notes to the Company Accounts at 31 December 2014 10. Commitments Operating leases The Company’s annual commitments for rental payments under non‐cancellable operating leases payable are as follows: 2014 2014 2013 2013 Other Operating

leases Land andBuildings

Other Operating

leases

Land and Buildings

$’000 $’000 $’000 $’000

Leases expiring: Within one year ‐ ‐ ‐ ‐ Within the second to fifth years inclusive 39 407 41 786 In more than five years ‐ ‐ ‐ ‐

39 407 41 786

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 for the landlord. Neither party exercised their break clauses falling in 2012, and following negotiations in 2013, 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.

11. Related Party Transactions There were no transactions with the Group’s related parties in 2014.

12. Post Balance Sheet Events Since the balance sheet date 31 December 2014 and the date that these financial statements have been signed, there have been no developments announced witch have a material impact on, or the understanding of, these financial statements: Corporate update and Board change On 31 March 2015 the Company announced that Stewart Gibson was stepping down from the Board as part of a wider cost saving exercise which included the relocation of the Group’s Head Office. Further details of the Group post balance sheet events can be found in note 25 to the Group financial statements. Further details of these post balance sheet events are disclosed in the Chairman’s Statement on page 4.

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Glossary 2C Mid value contingent resource 2D, 3D Two, three dimensional 2P Proven plus probable reserves $ US Dollar AGM Annual General Meeting AIM The Alternative Investment Market of the London Stock Exchange plc B, b – defined as 10

9 Billion boe (barrels of oil equivalent) A term used to summarise the amount of energy that is equivalent to the amount of energy found in a barrel of crude oil. bbls Barrel(s) boepd Barrel(s) of oil equivalent per day bopd Barrel(s) of oil per day bcf Billion cubic feet Cdn Canadian dollar EIA Environmental Impact Assessment Eni Eni S.p.A. ERCE ERC Equipoise Limited EU European Union FCA Financial Conduct Authority FRS Financial Reporting Standard GAAP Generally Accepted Accounting Practice GLJ GLJ Petroleum Consultants Ltd. HSE Health, Safety and the Environment

IAS International Accounting Standards IFRS International Financial Reporting Standards ISIN International Securities Identification Number ISO 14001 International Standards Organisation Environmental Management Standard OHSAS 18001 British Standard for Occupational Health and Safety Management Systems Km Kilometre KPI Key Performance Indicator KPMG KPMG LLP stb Stock Tank Barrels mmbbls Million barrels mmbo Million barrels of oil mmboe Million barrels of oil equivalent mmscfd Millions of standard cubic feet per day (of gas) Northern or the Group The Company and its subsidiaries, Northern Petroleum Plc Probable Probable reserves are those unproven 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 50% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves Prospect Potential or actual drilling target that is defined by seismic data and / or log data with a sufficient level of detail for the evaluation of economic viability

Proven Proved 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 Reserves Estimated remaining quantities of oil and natural gas and related substances anticipated to be technically and economically recoverable from known accumulations, as of a given date RPS RPS Energy scf Standard cubic feet scfd Standard cubic feet per day Shell Shell E&P France SAS Shell Italia Shell Italia E&P S.p.A STOOIP Stock Tank Oil Originally In Place WTI West Texas Intermediate – a grade of crude oil used as a benchmark in oil pricing

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Directors, Offices and Advisers

Directors

J D Murphy Non‐executive Chairman K R Bush Chief Executive Officer

N T Morgan Finance Director

I M Lanaghan Non‐executive Director Company Secretary

W J Anderson Registered office

Martin House 5 Martin Lane London EC4R 0DP Telephone: +44(0)20 7469 2900 Facsimile: +44(0)20 7469 2901 Email: [email protected] Registered number

02933545 Legal form

Public limited company

Country of incorporation of Parent Company

England Office Locations

Northern Petroleum London Office Martin House 5 Martin Lane London EC4R 0DP United Kingdom Regional office, Australia Ouro Preto Resources Pty Ltd PO Box 394 Burleigh, Heads 4220 Australia Regional office, Canada Ouro Preto Resources Inc 1000, 640 – 8

th Avenue SW Calgary, Alberta T2P 1G7 Canada Regional office, Italy Viale Trastevre 249 00153 Rome Italy Independent auditor

KPMG LLP 15 Canada Square London E14 5GL

Bankers

HSBC Bank Plc 8 Canada Square London E14 5GL Lloyds Banking Group 10 Gresham Street London EC2V 7AE UniCredit Banca Piazza Cavour B Roma, Italy ATB Financial 2202 20 Street Nanton, Alberta T0L 1R0 Nominated adviser and brokers

Westhouse Securities Limited The Heron Tower 110 Bishopsgate London EC2N 4AY FirstEnergy Capital LLP 85 London Wall London EC2M 7AD Solicitors

Gordons Partnership LLP 22 Great James Street London WC1N 3ES Bond Dickinson LLP 4 More London Riverside London SE1 2AV Registrars

Neville Registrars Neville House Laurel Lane, Halesowen West Midlands B63 3DA Financial Public Relations

Camarco Limited 107 Cheapside London EC2V 6DN

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Licence Table

STATUS INTEREST OPERATOR

CANADA Onshore North West Alberta 94 Leases 100% Northern

ITALY Onshore

Cascina Alberto Permit 100%* Northern

Offshore

Southern Adriatic F.R39.NP Permit 100% Northern F.R40.NP Permit 100% Northern d149D.R‐.NP Application 100% Northern d60F.R‐.NP Application 100% Northern d61F.R‐.NP Application 100% Northern d65F.R‐.NP Application 100% Northern d66F.R‐.NP Application 100% Northern Sicily Channel C.R.146.NP Permit 100% Northern C.R149.NP Permit 100% Northern d358C.R‐.EL Application 50% Petroceltic Plcd29G.R‐.NP Application 50% Northern d30G.R‐.NP Application 100% Northern Ionian Sea d59F.R‐.NP Application 100% Northern *the Group signed a farm out agreement with Shell Italia in 2015 for 80% of the interest in the Cascina Alberto permit.

FRENCH GUIANA

Offshore

Guyane EEL Licence 1.4%* Shell*Northern Petroleum owns a majority interest in Northpet Investments Limited, a company which has a 2.5% interest in the Guyane licence.

AUSTRALIA Onshore

PEL629 Licence 100% Northern

Annual Report - FINAL DRAFT - Cabot Energy Plc · 4 Northern Petroleum Plc Annual Report and Accounts 2014 Chairman’s Statement Farm out negotiations immediately began for the onshore

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