Cabot Energy Regulatory News (CAB)

Northern Petroleum Plc

("Northern Petroleum" or "the Group" or "the Company")

Preliminary Results for the Year Ended 31 December 2014

Northern Petroleum (AIM: NOP) announces its Preliminary Results for the year ended 31 December 2014.

Highlights

Operations

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

· In Alberta, drilling operations started in January and production started in April with five wells drilled and one recompleted during the year

· Field production potential of 500 barrels of oil per day ("bopd"); 250 bopd currently economic and to be brought online

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

· Farm out of Italian onshore permit to Shell post year end to realise $0.9 million in cash and a future work programme carry

· Virgo assigned 2P reserves of 0.3 million barrels of oil ("mmbbls") by Calgary reserves auditor

Corporate and Financial

· Sale of the UK assets for £1.5 million, including the transfer of Markwells Wood well

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

· Restructuring of the Group to significantly reduce cost base in line with prevailing oil price environment

· Cash on the balance sheet at the year end was $12.1 million

· Production sales revenue for the year of $2.7 million (2013: $0.8 million)

· Significant impairment charge for 2014 relating to French Guiana and Canada

· Change in the Group's presentational currency to US$

Keith Bush, Chief Executive Officer of Northern Petroleum, commented:

"Last year the Company had an extremely active operational year, with five wells drilled and one recompleted in Canada and two new exploration permits awarded in Italy. Ultimately though, towards the end of the year, the good progress made in both Canada and Italy was undermined by the extreme drop in the oil price, something that has continued into 2015 and has affected the whole industry.

"Many difficult decisions have been made regarding the structure of the Company, both as a result of the divestment of non-core assets and the impact of the reduced oil price on the cash flow. As a result, the cost base has been significantly reduced, while the key expertise required to redevelop the Virgo asset and to continue to push for progress with our Italian permits and applications have been retained.

"The action taken now should enable the Company to bring more of the Virgo production back on line economically and also determine the best redevelopment plan such that viable production growth can be realised, even in the current oil price environment. More than ever, a stable production base is required to provide sustainable revenue and allow the Company to realise the value inherent within the portfolio, something demonstrated recently by the farm out of the Cascina Alberto permit to Shell Italia.

"The Company is now better positioned to weather the current storm and be able to establish a production base that will support the significantly reduced cost base. In turn this will allow time for progress to be made, not only with our current asset base, but also with any asset or corporate opportunity that may arise."

For further information please contact:

Northern Petroleum Plc Tel: +44 (0)20 7469 2900

Keith Bush, Chief Executive Officer

Nick Morgan, Finance Director

Westhouse Securities Limited (Nomad and Joint Broker) Tel: +44 (0)20 7601 6100

Alastair Stratton

Robert Finlay

FirstEnergy Capital LLP (Joint Broker) Tel: +44 (0)20 7448 0200

Jonathan Wright

David van Erp

Camarco Tel: +44 (0)20 3757 4980

Billy Clegg

Georgia Mann

In Accordance with AIM Rules - Guidance for Mining and Oil & Gas Companies, the information contained in this announcement has been reviewed and signed off by the CEO of Northern Petroleum, Mr Keith Bush, who has 23 years' experience as a petroleum engineer. He has read and approved the technical disclosure in this regulatory announcement. The technical disclosure in this announcement complies with the SPE/WPC standard.

Note to Editors:

Northern Petroleum is an oil and gas company focused on production led growth. The Company is undertaking a redevelopment and production project in north west Alberta and has a broader portfolio of exploration and appraisal opportunities in countries of relatively low political risk, primarily Italy. Comprehensive information on Northern Petroleum and its oil and gas operations, including press releases, annual reports and interim reports are available from Northern Petroleum's website: www.northernpetroleum.com 

Chairman's Statement

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 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 cashflow 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. 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 cashflow 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 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 outs 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 cashflow 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 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

Non-executive Chairman

Chief Executive Officer's Statement

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.

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 2P reserves of 0.3 mmbbls 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 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.

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 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

Chief Executive Officer

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 stock tank oil original in place 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 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 upswept 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 cashflow.

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.

Italy

2014 activity

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 ERC Equipoise Limited ("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 979 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 S.p.A. ("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 25 km to the southeast.

In early 2015 the Group announced a farm out deal with Shell Italia E&P S.p.A. ("Shell Italia" or "Shell") 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.

Sicily Channel

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.

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.

Australia

The 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 provided 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.

The UK

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

Keith Bush

Chief Executive Officer

Financial Review

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.

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 cashflows 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.

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 cashflow 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.

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.

Nick Morgan

Finance Director

Consolidated Statement of Profit or Loss

for the year ended 31 December 2014

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.

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

Consolidated Statement of Other Comprehensive Income

for the year ended 31 December 2014

*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

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

REGISTERED NO. 02933545

Consolidated Cash Flow Statement

for the year ended 31 December 2014

*Following the change in presentational currency, as detailed in note 1, the comparative Statement of Financial Position 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

*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.

* Increase in equity in Northpet Investments Limited.

Notes to the Accounts

1. BASIS OF PREPARATION

The financial information which comprises the Consolidated Statement of Profit or Loss, the Consolidated Statement of Other Comprehensive Income, the Consolidated Statement of Financial Position, the Consolidated Cash Flow Statement, the Consolidated Statement of Changes in Equity and related notes is derived from the full Group consolidated financial statements for the year ended 31 December 2014, which have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the EU and those parts of the Companies Act 2006 applicable to companies reporting under IFRS.

The financial information has been prepared applying the accounting policies and presentation that were applied in the preparation of the Group's consolidated financial statements for the year ended 31 December 2014 and are not the Group's statutory accounts. The accounting policies are detailed in the Group's consolidated financial statements for the year ended 31 December 2014 which will be presented on the Group's website (www.northernpetroleum.com).

The financial information set out above does not constitute the Company's statutory accounts for the years ended 31 December 2014 or 2013. Statutory accounts for 2013 have been delivered to the registrar of companies, and those for 2014 will be delivered in due course. The auditor has reported on those accounts; their reports were (i) unqualified, (ii) did not include a reference to any matters to which the auditor drew attention by way of emphasis without qualifying their report, and (iii) did not contain a statement under Section 498(2) or (3) of the Companies Act 2006.

This financial information does not constitute full accounts within the meaning of section 434 of the Companies Act 2006 and has been agreed with the auditor for release.

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 parent company's functional currency. From the start of 2014 the majority of the Group's and by extension the parent 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 parent company's functional currency to US Dollars from 1 January 2014.

The following subsidiary of the parent 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 parent company's and subsidiary's functional currencies, the Group has also changed its presentational 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 Group's presentational currency and that of the parent 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 presentational currency, the Group consolidated prior year comparative accounts have been represented: The parent 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.

2. 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.

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. 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 E&P France SAS, 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. Costs relating to the Zaedyus discovery and associated licence have been written-off due to current oil prices and as no capital is being allocated by the Group and its partners to this area before the licence expiry date in mid-2016.

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, 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:

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.

b) IT systems

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.

3. PROPERTY, PLANT AND EQUIPMENT

a) Oil and Gas Assets

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 were incurred to drill 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 WTI 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).

The comparative tables for 2013 are detailed below:

 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.

b) Non-Oil and Gas Assets

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. CASH GENERATED FROM OPERATIONS

(NOTE TO CONSOLIDATED CASH FLOW STATEMENT)