Cabot Energy Regulatory News (CAB)

Northern Petroleum Plc

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

Preliminary Results for the Year Ended 31 December 2013

Northern Petroleum (AIM: NOP) announces its Preliminary Results for the year ended 31 December 2013.

Highlights

Board and Governance

· Restructure of the Board, including the appointment of a new CEO, an independent Non-executive Chairman and two new independent Non-executive Directors

· Reduction in Board members from ten to six including three executive and three Non-executive Directors

Financial

· Sale of the Netherlands operating subsidiary for €19.5 million in cash

· Cash on the balance sheet at the year end was €26.0 million (31 December 2012: €22.5 million)

· Impairment of historic capitalised costs for certain assets resulting in a charge to the profit or loss account of €17.7 million

Health, Safety and Environment

· The Group maintained its record of no lost time incidents on its operations throughout the year, including over nine months of operations in the Netherlands

· Care and maintenance of the Markwells Wood site in the UK including the cleaning and removal of storage tanks and flowlines

· Abandonment of the La Tosca well site, including the reinstatement of the site to its original condition

Operational

· Entry into Canada with a land position acquired in north west Alberta and execution of a successful proof of concept well programme in early 2014

· Sale of the Netherlands operating subsidiary to Vermilion Energy Inc. 

· Refocusing of the Italian portfolio to the Southern Adriatic where existing permits contain two oil discoveries and one world class exploration prospect 

· Completion of the four well exploration programme offshore French Guiana following up on the original Zaedyus discovery

· Award of a 1.4 million acre exploration licence in South Australia, targeting an unconventional shale oil play

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

"Last year was a period of significant change for Northern Petroleum. The Board and management started a process that was necessary to position the business for growth. In addition to the main actions of selling the Netherlands subsidiary, establishing a new board and starting production in Canada, much work has been undertaken internally to create a company that can operate in a competitive industry environment and has credibility in a tough investment market.

"In recent years the investment community has moved away from volatile, exploration led strategies, especially at the smaller end of the market, and it is not clear if or when this will change. Investors are interested in companies with sustainable business models and with a realistic chance of growth in an appropriate timeframe. As a result the Company's business model has been revised, with the focus now on production led growth, initially onshore, reflecting the experience and skill set of the Board and senior management.

"This will allow the Company to create a sustainable business model focused on providing core, demonstrable value from operations which are more in the control of the Company and provide a faster return on investment.

"Along with the more predictable growth that increasing production will bring, the Company aims to provide investors with the opportunity of high returns to match the inherent risks of investing at the smaller end of the market. To achieve this, there will be a continued effort to identify and develop exploration and appraisal opportunities, primarily offshore, but with only a controlled outlay of the Group's capital. The timing and results of this type of activity are less within the management's control and typically take longer to mature to a point where a return on investment can be realised. However, in conjunction with the primary strategic focus of production led growth, this exploration and appraisal activity will provide the opportunity for significant upside.

"Through the successful implementation of this strategy, Northern Petroleum aims to provide its shareholders with exciting short term activity and value growth, while building a well balanced exploration and production business of material size over the medium to long term."

For further information please contact:

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

Keith Bush, Chief Executive Officer

Nick Morgan, Finance Director

Graham Heard, Exploration and Technical Director

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

Richard Baty, Corporate Finance

Henry Willcocks, Corporate Broking

FTI Consulting Tel: +44 (0)20 3727 1000

Edward Westropp/ Shannon Brushe

Northern Petroleum is intending to provide a corporate presentation to its shareholders in early May. If you would like to attend this event, please register with your shareholder details to CorpCom@northpet.com to receive your invitation. Northern Petroleum also intends to present at the Proactive Investors event on 1 May 2013 at 6.00pm.

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 Exploration and Technical Director of Northern Petroleum, Mr Graham Heard CGeol. FGS, who has over 35 years' experience as a petroleum geologist. He has compiled, 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

Significant board changes have been made during the year, designed to support and challenge the new management team in their drive to create value for shareholders. The Board recognises the challenges that the Group faces and using our collective experience we are working together to realise the value of the opportunity that currently presents itself. We firmly believe that the strategy of production led growth will enable the Group to deliver shareholder value.

There were several material events during 2013 which affected areas ranging from operations through to corporate governance. In operations, the Group sold the Dutch operating subsidiary to Vermillion Energy Inc. and acquired petroleum and natural gas lease acreage in Canada that offers production, development and exploration opportunities. Additionally the Italian portfolio was refocused to concentrate on the Southern Adriatic and the four well follow up exploration programme in French Guiana was completed. From a corporate governance perspective, Northern Petroleum was completely re-shaped, with a restructured and reduced board including a new Non-executive Chairman and Chief Executive Officer.

The proceeds from the sale of the Dutch assets have provided sufficient funding to carry out the proof of concept programme and initial development activity in Canada, while supporting the efforts in Italy for the acquisition of 3D seismic. Further investment in Canada will allow the project to become a material part of the business with development and production growth and provide a foundation for further production areas and additional core value.

This approach is taken in line with our strategy of production led growth. The business model employed by the Group encourages focus on the assets that offer the optimum chance of adding material value, while we continue to review the best way to monetise and divest assets that no longer fit with the corporate strategy.

The Board changes in 2013 have led to the creation of a management team that can positively pursue this strategy. I would like to thank the former members of the Board who endeavoured to set the groundwork for the current team to build on. With active portfolio management, the new team have now been able to position the Group to grow.

The experience and background of the new non-executive members of the Board complement the skills and competence of management to create an effective team in the support of the delivery of shareholder value. The industry proven ability of the non-executive team provides the guidance to support the enthusiasm and drive of the management team.

The experience of the Board ensures that we are aware of our responsibility to look after all our stakeholders, manage risk and undertake our activities in a manner consistent with globally recognised best practice. These responsibilities are something that we consider very important to the health of the business.

We are confident that 2014 will see the positive impact of changes initiated in 2013. We continue to refine our approach and operations in order to create and deliver value from our existing portfolio while working hard to upgrade our assets by pursuing new opportunities which fit our revised strategy. I am very excited about working with this new team and I have every confidence that we will deliver opportunities that are capable of adding significant value to Northern Petroleum.

The particular challenges the Group faced in 2013 are largely behind us and 2014 is set to be an exciting and rewarding year. 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 starting to develop the production that will lead the Group to sustainable value creation.

Jon Murphy

Non-executive Chairman

Chief Executive Officer's Statement

2013 was a year of significant change for Northern Petroleum. The Group said farewell to the Chairman and Managing Director who had been with the Company for 18 years and 14 years respectively. Further significant Board changes were made during the year with the Board reduced from 10 members at the start of the year to the final complement of six members in early 2014. The incoming Non-executive Directors have brought in a wealth of experience and expertise from industry and financing, that will provide the necessary guidance and governance to support the management team and staff as the business grows.

Operationally the Group refocused from the Netherlands to Canada with the acquisition of petroleum and natural gas leases in north west Alberta during the first quarter, followed by the completion of the sale of the Netherlands operating subsidiary in the last quarter. Much work was conducted on the Canadian assets during the year, with both subsurface and operational preparative work performed to allow drilling operations to commence in the first quarter of 2014.

A consolidation of the Italian portfolio was also conducted during the year with a number of permits and applications relinquished in order to allow a more focused approach to the remaining interests. The key area in Italy is now the permits and applications held in the Southern Adriatic where significant progress has been made throughout the year in understanding the potential of the area. This has been done in conjunction with a concerted effort to develop relationships within Italy to allow progress through the approvals process. We believe that the Group's objectives and the value that could be realised by the development of the discoveries are now fully recognised within the Italian government. In particular in the Southern Adriatic, independent assessment of the Giove discovery has estimated a recoverable contingent resource of 26 million barrels of oil.

In addition to the core areas in Canada and Italy, the Group also gained an exploration licence in South Australia where there is shale oil, condensate and gas potential. The work programme for the first year will assess this potential and the Group will determine the forward plan from this. In French Guiana, the operator completed the exploration drilling programme without commercial success. A large desktop study consolidating the seismic and well data gathered to date has now been undertaken by the partnership to establish future exploration targets in the licence. Finally in the UK, the Group is looking at the best way to maximise the value of the licences through a sale or farm out.

The need for change at Northern Petroleum has become clear over a number of years. The producing fields in the Netherlands did not perform as expected leading to reserve write downs and the capital cost of developing the fields was too great for the Group, in an investment environment where raising money for small companies was very challenging. Progress in Italy stalled with the changes in legislation after the Gulf of Mexico spill and the decision by Shell not to drill a farm in well offshore west of Sicily. Further, the need for good corporate governance required a shake up of the Board.

All these issues and a number of others contributed to the operational and Board changes that were effected during 2013. The spirit of change engendered by this has been captured well by the management and staff and everyone is very motivated to work towards a new era for the business. These events have provided the first steps to position Northern Petroleum for the future.

Much of the work performed in 2013 and continued in early 2014 has been to enable growth. When the new management team came together in July, a review with investors concluded that the Group needed to be clear in communication with shareholders and deliver on promises made.

Three short term operational goals were set by the team: the sale of the Netherlands subsidiary, the start-up of operations in Canada and making progress with the Italian Southern Adriatic permits. Two of those three objectives have now been met with the sale of the Netherlands subsidiary concluding in October and operations in Canada commencing in February 2014. The third objective is still of great importance to the growth of the business and much effort has been made to move the work programme in Italy forward. This has included running through a tender process with seismic acquisition companies to have a vessel available to conduct the 3D seismic survey in the fourth quarter of 2013. Unfortunately the environmental approval process is still pending within the Italian government and it has not yet been possible to conduct the survey; something that has had a direct affect not only on Northern Petroleum, but also on the service suppliers. Many other companies and industries have been impacted by the impasse within the Italian Environment Ministry. However, we continue to work hard with the Italian authorities to allow the survey to progress as planned in 2014, with the recent changes in the Italian administration and government viewed as positive to the industry.

Along with the operational goals, and essential to positioning the Group appropriately, the management team also endeavoured to increase the standards of corporate governance within the business. Key to corporate governance is the composition of the Board and particularly the Non-executive Directors. With the three new Non-executive Directors in place, I believe that the Group has an exceptionally strong Board for its size, with the right skill set to complement, challenge and ultimately support the executive members.

To further enhance the capacity to grow the business from a strong and credible foundation, gaining an up to date picture of the reserve and resource base of the business was critical. This has been achieved through third party review, and while the change in categorisation and reduction of the Southern Adriatic resource was a material change, it has given the management team a clear picture of where the true value lies.

The changes in the primary financial statements this year reflect the significant operational changes that the business has undergone during 2013. Three key events have driven these changes: the sale of the operating subsidiary in the Netherlands, the strategic exercise reviewing the direction of the business which has led to the impairment of certain assets, and the consolidation of the now controlled joint venture which owns the French Guiana interest. While these changes have produced significant non-cash losses in the profit or loss account for 2013, with the focus in the future being towards production, the primary financial statements will be more closely aligned with measuring the performance of the business across each year as opposed to across a multi-year exploration campaign.

Northern Petroleum is now moving into a new era where the strategy of production led growth will be a significant component of future success. In a market where the appetite for risk has reduced, the companies that show focused use of capital to create sustainable growth offer more to investors.

This new strategy for the Group is already making progress with the start up of operations to grow production in north west Alberta. The positive results of the proof of concept project where all three of the wells encountered economically recoverable light oil, now support plans for the full redevelopment of these lands to be finalised and implemented. This will be a key focus for the Group over the coming year. 

To enhance the Group's production capability further, opportunities will be evaluated with a view to establishing an additional core area. This will reduce the risk of reliance on one area and allow technical skills proven in north west Alberta to be utilised elsewhere.

In addition to production led growth, we recognise that growth through a sensible exploration and appraisal strategy is also required to provide the potential for very large returns on investment. The opportunity that the Southern Adriatic presents is world class and we will continue to pursue this through working together with the Italian authorities to gain approval to shoot the 3D seismic. There will also be a sustained effort to demonstrate the value to other industry players such that we can develop an appropriate joint venture to fully evaluate the Cygnus prospect and Giove discovery through the drill bit.

Further to the Italian opportunities, a review of exploration potential is being conducted to identify the key focus areas that the Group may enter in the future. This will identify exploration opportunities at an early stage to ensure that we are able to keep our exploration portfolio in the right shape to generate new opportunities without significant capital commitment.

Northern Petroleum has been through a transformational year during 2013. The new strategic approach to focus on production led growth will be very important for the future as the new Board and management team aim to deliver an exploration and production company that provides investors the value that they expect. I look forward to updating existing and new shareholders regularly as our Group develops in this exciting new environment.

Keith Bush

Chief Executive Officer

Review of Operations

Canada

2013 activity

As part of a review of development opportunities around the world, Canada was considered the most suitable country for four main reasons: the ease of access to data, the established industry and infrastructure, the low cost of proving opportunity concepts, and the running room to create core value and significant cash flow for the Group. Canada provides the Group with the opportunity to quickly replace the production from the Netherlands and build an increasing production base that can sustain growth.

The decision to enter into Canada was taken in the first quarter of 2013 with the acquisition of 9,320 acres of oil and gas leases in the Virgo area of north west Alberta. Activity post the first quarter was focused on preparing the optimum test programme for the newly acquired lands. A full subsurface work programme was conducted to examine how best to evaluate the Keg River redevelopment opportunity. This included the purchase and interpretation of 3D seismic over the lands, the creation of static and dynamic reservoir models to evaluate the remaining potential in the oil pools and preparation for operations, with a focus on existing well locations that could be most effectively worked on.

The original concept of the play was to re-enter existing wells to reinstate production from the Keg River reefs. Subsurface work during the summer of 2013 showed that there were further opportunities available with the drilling of new wells into previously produced reefs, rather than just conducting re-entry operations. Drilling of new wells would also reduce the operational risk as the condition of all the downhole equipment is known. The work also showed that well re-entry was still a viable option and therefore a three well proof of concept programme was developed. The programme was designed to test the commercial viability of reinstating production in Keg River carbonate reefs, which were mainly drilled and produced in the 1960s, 70s and 80s. The programme comprised the re-entry of an old production well, 14-22, the drilling of a new well into a previously produced reef, 13-33, and the drilling of a new well into a newly identified reef, 16-19.

The proof of concept programme was approved by the Board at the end of the third quarter and well licencing work commenced at that point. This included full consultation with the local population along with the appropriate environmental surveys and reporting. At the time of the applications for the three well licences, there was an unprecedented backlog at the Alberta Energy Regulator, due to a change in procedure process combined with a large number of industry applications. This caused the process to take longer than forecast and meant that the proof of concept work programme moved into early 2014.

Planned activity

During the production operations in the first quarter of 2014, two new wells were successfully drilled, 16-19 and 13-33, and one well was successfully re-entered, 14-22, where production from all previously producing horizons was shut off apart from the Keg River.

The results from well 14-22 proved the concept of oil re-equilibration over time, which supports the option of re-entering other wells across the Group's acreage and bringing them back into commercial production. The results from well 13-33 proved that the larger reefs, which have historically only been produced by one well, will support multiple new wells targeting unswept oil zones. While it is not expected that there will be many more new reefs found, well 16-19, which was drilled into a previously undrilled reef, successfully calibrated the Group's 3D seismic interpretation, which will be beneficial for the location of future wells on existing reefs and is a standalone economically viable discovery.

The Group acquired its initial land position of 9,320 acres through three Alberta Crown land lease sales in 2013. The Group has participated in four further land sales this year, targeting specific land sections to help augment the Group's position in this play. Total land acquisition costs have been Cdn$2.8 million including fees and initial rental payments. The average price paid by the Company in 2013 in acquiring its initial land position was Cdn$186 per hectare. The highest average price paid in a land sale in the area in 2014 has been Cdn$475 per hectare.

The Group's aggregate land position now comprises 26,454 acres with an Alberta Energy Regulator calculated 101 mmbbls STOOIP, from which 17.5 mmbbls of oil has been produced, giving an average recovery factor of 17 per cent. Our internal review has identified more than 100 reefs or partial reefs which are now being graded for future drilling and production.

The ongoing work programme in 2014 will be to evaluate the results of the production testing and focus on the redevelopment plan for the Virgo area. The primary focus is to increase the recovery factor by an initial five per cent through primary recovery techniques. In addition, work in 2014 will consider the potential of secondary recovery from water flood, which has been done on a limited basis and with some success in the wider area. Redevelopment programme planning is expected to continue for the remainder of the year. A further drilling programme is being planned for later this year and will target reefs that enhance the understanding of the area and provide good production opportunities.

Italy

2013 activity

The Southern Adriatic permits and applications have been the focus of attention as they have the potential to be transformational for the Group. The Group's management has expended significant effort, including regular dialogue with the Italian Ministries and British Embassy in Rome, to gain the required environmental approvals for the planned 3D seismic operations and for the award of the adjacent application areas. However, the key requirement of ministerial signature for the environmental impact assessments has not been achieved, therefore it has not yet been possible to conduct the 3D seismic work programme nor have the applications converted to permits.

The Southern Adriatic acreage takes precedence within the Italian acreage portfolio as it lies within a proven hydrocarbon province containing the producing Aquila oil field. The Cygnus prospect is up dip of it and evidence from the development wells for the field indicate that Cygnus could have a shared oil water contact with Aquila. During 2013 ERC Equipoise Limited ("ERCE") assessed the prospective resources for the Cygnus prospect, recognising in their high case estimate a common oil water contact with the Aquila field giving a prospective resource of 979 million barrels with 790 million barrels of recoverable oil within the 100per cent owned permit F.R39.NP. The ERCE prospective resource estimate for the mean case, using a shallower contact giving partial hydrocarbon fill and a separation from the Aquila field from the mapped prospect, is 446 million barrels, of which 401 million barrels is within the permit. The Cygnus prospect is a stratigraphic trap with its reservoir comprising resedimented carbonates derived from the adjacent Apulian platform. The distal and basin equivalent of these sequences are productive in the Aquila field. ERCE estimate a chance of success of 12 per cent for the Cygnus prospect.

Significant technical work has been conducted on the discoveries within the Southern Adriatic permits in 2013. Studies on the Giove discovery have indicated the potential for larger oil in place than previously recognised and a review of the well results has indicated a better recovery factor may be applied, further increasing the potential. Therefore in order to obtain a consistent picture through the Southern Adriatic permits, ERCE were also contracted to review the Giove and Rovesti discoveries and the new work performed by the Group.

The review performed by ERCE gave positive results for Giove, with an increase in the expected recoverable resource to 26 million barrels. However the recoverable resource from Rovesti was reduced due to a re-interpretation of the available log data. ERCE has re-classified both Giove and Rovesti as contingent resource volumes. Previously both assets had been categorised as reserves. The reclassification is reflected on the balance sheet by transferring the historical acquisition and development costs from tangible to intangible. This now allows the Group to focus on moving the Giove discovery through the appraisal phase to establish whether there is a viable development for the field, and realise the potential value that this will bring.

As part of the effort to focus within a particular area in Italy, a number of the pending applications have been withdrawn. These include two in the Southern Adriatic where the potential for oil was not considered as good as the other application and permit areas.

Planned activity

Italy has experienced a period of political transition, culminating in a change in the Prime Minister and other government ministers, including the Environment Minister and the Minister for Economic Development. The Group view these changes as positive, and along with some of the initiatives proposed and fully supported by Northern Petroleum, believe that the new National Energy Strategy will have a positive impact on exploration and production in Italy. We look forward to the implementation of the plans that will enhance the ability of the Group to grow its presence in the country by reducing the administrative hurdles.

Southern Adriatic: 

The permits containing the Cygnus prospect and the Giove discovery are the prime targets of the planned 3D seismic survey. The survey will be acquired in 2014 assuming that the appropriate environmental approval is obtained, and a survey vessel can be contracted. Once acquired the seismic will be processed and interpreted as soon as possible in order to establish drilling locations, both to test the Cygnus prospect and also appraise the Giove discovery. In conjunction with this work, the farm out process will continue in order to bring in additional experience and funding into the permits.

Ionian Sea: 

Three gas discoveries (Fedra, Florida and Fiorenza) and exploration prospects are contained within the application d59F.R.-NP. These are in deep water adjacent to the producing Luna, Hera Lacinia and Linda gas fields operated by Eni. 3D seismic coverage acquired by Eni will be evaluated once this application has been awarded.

Sicily Channel: 

Permit C.R146.NP contains the Vesta oil prospect, interpreted as having the same age reservoir sequence as the on trend Vega oil field. The permit is currently suspended and is also subject to farm in interest. Closer to the Sicily coast, applications are awaiting award and contain leads similar to the on trend Palma oil discovery. Following the strategic change in the focus of the business historic exploration costs in the Sicily Channel in licences that have been relinquished have been written off.

Po Valley:

Cascina Alberto is the only application onshore and contains a prospect previously interpreted by Eni as being 300 million barrels of prospective resource. The trap is similar to structures such as the Villafortuna-Trecate oil field. Once the application is awarded, the Group will continue the technical work to establish a possible drill location to evaluate the prospect. The Longastrino permit contains additional leads not currently considered for further evaluation. With no firm exploration efforts in this permit, it has been decided to write off historic exploration costs.

French Guiana

2013 activity

The Zaedyus oil discovery in 2011 was made with the first deepwater well in this basin. That gave encouragement to execute an exploration programme comprising an extensive 3D seismic acquisition covering the deepwater margin and a four well drilling campaign to follow up on the initial success. The 3D seismic has demonstrated that numerous deepwater fan systems exist with the potential for stratigraphic traps similar to Zaedyus. The drilling programme has demonstrated that early success can be difficult to replicate. However a great deal of information has been gained that will substantially de-risk future exploration and make the acreage potentially attractive to a purchaser who can benefit from the knowledge gained from the previous five well exploration programme.

The discovery well Zaedyus-1 (GM-ES-1) encountered 72 meters of net oil pay in two turbidite sand sequences within a large fan system (Cingulata) that contains multiple turbidite lobes. The follow on four well exploration programme targeted three locations within the Cingulata fan and one on a separate fan system, Cebus, located on the first of two 3D seismic surveys acquired in 2012. These wells all encountered reservoir sequences, some with oil shows, but resulted in no commercial discovery.

The shareholding held by the company in Northpet Investments Limited ("Northpet") has increased resulting from an arrangement entered into in 2008 whereby each of the two shareholders, Northern Petroleum and Wessex Exploration Plc ("Wessex") had an option to elect not to fund its share of joint venture cash calls in return for the other shareholder receiving an increased shareholding in Northpet, the jointly owned investment vehicle. Wessex elected to take advantage of this option in October 2013, which resulted in the Group now owning a net beneficial interest of 1.4 per cent in the licence. This arrangement has been superceded and the equity held by shareholders in Northpet is now fixed. Future cash calls will have to be honoured or the defaulting party will lose their equity in Northpet. This change has resulted in the consolidation of Northpet onto the balance sheet as the Group now owns 55.9 per cent of the vehicle. 

Planned activity

Shell and its joint venture partners have integrated the data from the five wells with the newly processed 3D seismic. This data has been interpreted and mapped resulting in the identification of a portfolio of prospects and leads in the Central Slope area of the Guyane Maritime permit. Northern Petroleum will decide on how best to proceed with its involvement in the acreage once the seismic interpretation is completed by the operator.

The Netherlands

2013 activities

The Netherlands provided the Group with production revenue from six gas fields, discoveries to be developed and exploration potential. To fully realise the potential of the acreage funds were required beyond those available to the Group. Production revenue was also expected to reduce as Nederlandse Aardolie Maatschappij B.V. took a revenue share, post development payback, on four of the fields, unless increased investment was applied to them. Therefore the decision was made to divest the portfolio while the opportunity existed for the purchaser to build on what Northern Petroleum had achieved and therefore pay a price that reflected the future potential that could be realised through a greater level of investment.

Northern Petroleum Netherland BV was sold to Vermilion Oil & Gas Netherlands BV for €19.5 million while retaining a net profits interest in the undeveloped Papekop oil and gas field and any development of the Posidonia unconventional shale oil play. The economic date for the transaction was 1 January 2013, however the sale completed on 10 October 2013. The net effect of the financial performance of the Netherlands subsidiary for the period up to 10 October 2013 and the disposal is shown with the profit or loss account under discontinued operations. 

The UK

2013 activity

The UK portfolio provided oil production from the Horndean and Avington oil fields during 2013. The primary reservoir play for the Weald Basin has historically been the Great Oolite carbonate, a low permeability reservoir that can contain large volumes of oil in place. Recovery factors are low as are production rates, which generally have a slow decline. The majority of the fields in the area produce from this reservoir, including Horndean and Avington. Net production to the Group from these fields during 2013 was approximately 20 barrels of oil per day.

In conjunction with the operator of licence PEDL233 containing the Baxters Copse discovery, and following an internal exercise analysing the Markwells Wood discovery, the Group has decided to reclassify the 4.3 million barrels of 2P reserves assigned to these assets as 2C contingent resource. While both assets have the potential to be commercial discoveries, further appraisal needs to be undertaken to confirm a viable development plan which would lead to commercial production.

The Group has also relinquished the onshore licences PEDL256 and PEDL155, which contain the Havant prospect, after extensive consultation with the licence joint venture partners.

The wider UK asset portfolio, including the minority interests in the producing Horndean and Avington oil fields and the offshore Isle of Wight exploration licence is not a primary focus for the Group. These UK assets are being considered for sale and the Group has invited expressions of interest, however no acceptable offer has progressed to a final divestment. With limited capital commitment forecast, limited management time required on the assets and positive cashflow from the production, management is prepared to wait to receive a fair offer for the assets.

Historical exploration and appraisal costs relating to the UK which have been previously capitalised in the balance sheet have now been written off in the profit or loss account.

Australia

2013 activity

Having recognised that unconventional resources are best developed where sufficient land access is available, the Group resolved to consider countries that would provide the opportunity to evaluate a large area. Australia was also recognised as providing extremely supportive state governments and free access to seismic and well data to evaluate the onshore acreage. Having learnt from evaluating shale sequences in the Netherlands and the UK, the Group applied for what was considered to be an unexplored unconventional resource play, concentrating on where this would have light oil and liquid rich gas potential. The Otway Basin licence covering 1.4 million acres in South Australia was awarded in September 2013 and has a five year term.

Planned activity

The first year work programme is to undertake an integrated interpretation of all the previous seismic and drilling information concentrating on two formations, the Sawpit and Casterton shale sequences, known as good quality source rocks and the associated sandstone reservoirs. New work includes seismic reprocessing, geochemistry and regional studies to incorporate any results from new wells drilled on the adjoining acreage. The Group is also seeking to bring into the licence an experienced operator with current unconventional operations, to assist with the planned work programme that envisages a first well in the third year of the licence. Recent drilling activity in the adjacent acreage operated by Beach Energy Limited ("Beach Energy") has further enhanced the potential of the licence. The Jolly-1 well drilled to 4,026 metres recovered core in the Sawpit and Casterton Formations and had elevated mud gas readings over 340 metres of the Lower Sawpit Shale including extensive sandstone intervals. Beach Energy is drilling the Bungaloo-1 well to further evaluate the primary Casterton Formation with the Lower Sawpit Shale now a secondary target. Beach Energy considers that the well result indicates that a substantial deep basin gas play may be present in the Penola Trough, part of the Otway Basin. In the Group's acreage within the Otway Basin three troughs are present, the Robe, the St Clair, and Rivoli-Tantanoola, all of which may have potential for unconventional resource plays.

Graham Heard

Exploration and Technical Director

Financial Review

The material changes in the primary financial statements year on year reflect the significant operational changes that the business has undergone during 2013. Three key events have driven these changes: the sale of the operating subsidiary in the Netherlands, a strategic exercise reviewing the direction of the business which has led to the impairment of certain assets, and the consolidation as a subsidiary of the now controlled joint venture which owns the French Guiana interest.

Sale of the Netherlands

On 10 October 2013, Northern Petroleum completed the sale of its Dutch operating subsidiary, which contributed 95% of the Group's revenue in 2012. The financial performance of the Netherlands for the period up to 10 October and the net financial effect of the sale have been presented within discontinued operations in the profit or loss account. Revenue and other items have been restated accordingly in respect of the prior year which has led to a significant fall in revenue and production costs when compared with 2012. The remaining net profits interests in any future development of the Papekop field or the Posidonia shale do have a value, however the value of such interests is too uncertain at this stage to capitalise as an asset on the balance sheet.

While the completion date of the Dutch disposal was 10 October 2013, the economic date for the transaction upon which the purchase consideration was calculated was 1 January 2013. The trading of the subsidiary throughout 2013 to the point of sale contributed to a final loss on sale of €4.3 million when compared with the consolidated book value of the assets within the Group. The subsidiary company within the Group which owned the Dutch business has not incurred a taxable gain on the disposal through the use of the Substantial Shareholdings Exemption, which will also require the reinvestment of the sale proceeds within three years of the transaction.

Impairment

Following the changes of the Board during 2013 and the disposal of the Netherlands, an internal exercise was undertaken to determine the best strategic direction for the business and evaluate the Group's assets. The results of the exercise and the relinquishment of certain licences meant that the focus of the business was no longer prioritised on certain areas and assets where the Group had previously incurred and capitalised exploration and drilling costs. These changes have led to the impairment of assets in certain areas, including in the Po Valley and Sicily in Italy and in the Wessex and Weald Basins in the UK, where future material investment to progress exploration and appraisal opportunities is not currently deemed likely. The total charge to the profit or loss account in 2013 for impairment was €17.7 million.

A further result of the strategic exercise is the decision to adjust the methodology behind testing the impairment of the Group's intangible oil and gas assets. Historically, exploration costs have been capitalised and grouped in country pools and judged against the cash generating potential of the assets in that country taken as a whole. In future, the capital pools will be reduced to a regional basis, mirroring the geological basins of a particular play. This is not a change in the Group's accounting policy, but a more focused approach in determining the likely future commercial viability of any project.

The licence offshore French Guiana is regarded as one regional play and given the ongoing nature of the exploration campaign here and further drilling being considered by the operator and partners, the exploration costs to date remain capitalised on the balance sheet in line with the Group's full cost accounting policy. However if no further drilling activity is planned by the operator, this cost will be written off through the profit or loss account when such an outcome is confirmed.

Costs

Following the Board changes and the sale of the Group's key revenue generating subsidiary, there is an ongoing focus on cost. In prior years, a significant amount of staff cost and associated overhead expenditure was capitalised as part of ongoing exploration and development projects or was directed to supporting production in the Netherlands. While there has been a significant reduction in these costs on an actual basis, with less operational activity, the balance and nature of these costs have resulted in more cost being expensed through the profit or loss account in 2013. Further one-off costs were incurred in the year due to the Board changes and associated termination payments. Irrespective of whether staff costs and associated overheads can be capitalised, there will continue to be a focus on ensuring the Group's cost base is in line with its operational activity.

Dividends

No dividend is proposed to be paid for the year ended 31 December 2013 (2012: €nil).

Consolidation of French Guiana

During 2013, Wessex, Northern Petroleum's joint venture partner in Northpet, the French Guiana licence vehicle, exercised its right under the joint venture agreement to not meet its cashcalls and dilute its equity interest in Northpet. As a result, Northern Petroleum now owns 55.9 per cent of Northpet and Wessex owns 44.1 per cent. With this ownership change Northpet is now deemed to be controlled by Northern Petroleum and is no longer equity accounted for as a joint venture, but a fully consolidated subsidiary. The mechanism through which this was achieved also crystallised a foreign exchange loss previously recognised in reserves.

Treatment of the Southern Adriatic

In 2013, an independent reservoir evaluation specialist was mandated to review the Group's discoveries in the Southern Adriatic offshore Italy. The results of that exercise established that the reserves previously held by the Group for the discoveries should be reclassified as contingent resources. The capitalised costs relating to the acquisition of an ongoing work programme on these assets were shown under property, plant and equipment. Following this reclassification, these capitalised costs have been moved to intangible assets to reflect the change in certainty around the future development of the discoveries.

Cash and debt

Cash at the year end was €26.0million (2012: €22.5 million). Throughout the year the biggest individual investment for the Group was the ongoing operations in French Guiana which involved the drilling of three wells incurring a total investment of €8.4 million. The Group has sufficient funds to not only meet its financial commitments as they currently stand but also undertake the planned operational activity set out in the operational review. However the optimum pace of development and investment to maximise returns in the Group's assets may require further external capital from equity or debt at some point in the future.

During 2013 the Group acquired a relatively small amount of debt totalling €1.5 million at the year end. This relates to an Italian Government scheme, which has since been withdrawn, whereby seismic costs were partially refunded via a grant and long term government loans. The loans are repaid over five years with an interest cost of 0.5 per cent per annum. The below market interest rate element of this loan has been fair valued and recognised as a grant towards the cost of the Italian assets.

At the year end, net current assets were €24.7 million (2012: €23.7million) and net assets were €74.5 million (2012: €91.7 million).

Nick Morgan

Finance Director

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.

* The comparative results for 2012 have been restated to show continuing and discontinued operations. The overall loss for the year is unchanged.

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

 Consolidated Statement of Changes in Equity

for the year ended 31 December 2013

*Initial acquisition of Northpet Investments Limited (French Guiana) / ** Subsequent increases in equity in Northpet Investments Limited, note 3.

Notes

for the year ended 31 December 2013

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 2013, 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 2013 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 2013 which will be presented on the Group's website (www.northernpetroleum.com).

The full and annual consolidated financial statements for the year ended 31 December 2013 on which the report of the auditor was (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) 498 (3) of the Companies Act 2006 will be delivered to the Registrar of Companies in due course.

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.

2. DISCONTINUED OPERATION

On 11 October the Group announced that it had satisfied the terms of a binding sale and purchase agreement with Vermilion Oil & Gas Netherlands BV ("Vermilion"), a wholly owned subsidiary of Vermilion Energy Inc., for the sale of Northern Petroleum Nederland BV ("NPN"), the Company's wholly owned Netherlands operating subsidiary. The consideration for the sale was satisfied as follows: Canadian $27.5 million paid in cash on completion; a net profit interest in the Papekop Production Licence, ("Papekop NPI"); and a net profit interest over any future production from unconventional reservoirs, ("Posidonia NPI"). The Netherlands segment was not previously classified as held for sale or as a discontinued operation. The comparative Consolidated Statement of Profit or Loss and Consolidated Statement of Other Comprehensive Income have been restated to show the discontinued operation separately from continuing operations. The economic effective date for the transaction was 1 January 2013.

Rationale for sale

The Company acquired the majority of its Netherlands portfolio in 2005 from Nederlandse Aardolie Maatschappij BV ("NAM"), the Netherlands based joint venture between Exxon and Shell. The agreements allowed Northern Petroleum to bring into production undeveloped discoveries and pursue exploration opportunities. Since that time, the assets in The Netherlands have provided valuable cash inflow for the Company from production and partial asset sales. The portfolio consisted of five producing gas fields onshore, one gas field offshore, for which Northern Petroleum received deemed production compensation, and two further discoveries which were awaiting appraisal and development.

The NPN portfolio as a whole required significant levels of capital to develop and increase production to more material levels. Without these levels of required investment, which were beyond the capacity of the Group, the net economic benefits to the Group had been reducing and therefore it was the right time to conclude a sale.

Net Profit Interests

The Papekop NPI grants Northern Petroleum a 20 per cent interest in any net operating profit generated from the Papekop oil and gas discovery, if it is developed and brought into production. This is calculated after the deduction of operating expenditure and the recovery of development expenditure. If the interest in the licence is sold within one year, Northern Petroleum will receive 80 per cent of the proceeds, after Vermilion has recovered its expenditure to that point. If the interest is sold by Vermilion after one year, but before a field development plan is approved, Northern Petroleum will receive 20 per cent of the proceeds after cost recovery by Vermilion and keep a 20 per cent net profit interest.

The Posidonia NPI grants Northern Petroleum a 10 per cent interest in any net operating profit generated from the production of oil or gas from unconventional reservoirs, which is primarily the Posidonia shale sequence. This payment will be calculated net of operating and development capital expenditure.

As the timing and magnitude of future cash flows from the Papekop and Posidonia NPIs are uncertain, the Group has not recognised any contingent consideration in respect of either NPI.

Results of discontinued operation

All amounts are attributable to equity shareholders of the parent.

No tax charge or credit arises on the disposal of NPN. Substantial Shareholdings Exemption is available to offset the taxable gain on sale of NPN shares in the books of its immediate parent company NP Netherlands Limited, provided that the proceeds for the sale are reinvested by the Group in oil and gas assets within an appropriate time scale.

a) Results of discontinued operations

The results have been presented together with comparatives above.

b) Earnings per share in respect of discontinued operations

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.

c) Cash flows (used in) / from discontinued operation

d) Effect of disposal on the financial position of the Group

The consideration of €19,511,000 was received as $27,500,000 Canadian Dollars and has been retranslated at $1.41 to €1. No consideration has been recognised in respect of the net profit interests due to the uncertainty of their monetisation.

3. FRENCH GUIANA ACQUISITION

On 18 October 2013 the Group acquired control of Northpet Investments Limited, ("Northpet"). Northpet is the owner of a 2.5% interest in the Guyane Maritime Licence offshore French Guiana. The acquisition of Northpet was a consequence of the Group ensuring that Northpet did not default under the French Guiana joint venture agreement following Wessex Exploration PLC's ("Wessex") decision not to meet its share of a joint venture cash call. By preventing the default the Group maintained Northpet's participation in the licence.

Prior to 18 October 2013 Northpet had been a 50% owned joint venture with Wessex and had been accounted for using the equity method. Under the terms of the Northpet shareholder agreement, shareholders agreed to fund the working capital of Northpet on an equal basis by subscribing for new ordinary shares. If one shareholder declined to meet a funding call the other shareholder could subscribe for both sets of new ordinary shares thus increasing their percentage ownership. Wessex formally notified Northern Petroleum on 15 October 2013 that it intended not to fund future cash calls until Wessex's investment contribution in the work programme had reduced by "up to £1,500,000". On 18 October 2013 Northern Petroleum took up the share subscription for the cash call increasing its share to 52.1% triggering the change in control.

The change in control requires the disposal of the equity accounted investment as it no longer represents a joint venture. The control then requires the subsidiary to be acquired and consolidated from the date of change in control under IFRS 3, "Business combinations", resulting in the disposal and acquisition.

Effect of the acquisition:

Consideration:

Identifiable assets acquired and liabilities assumed:

In accordance with IFRS 3, "Business combinations", assets and liabilities which have been acquired with Northpet have been measured at its acquisition date fair value.

The intangible assets acquired comprise exploration costs offshore French Guiana.

No goodwill has been recognised as result of the acquisition and no significant acquisition related costs have been incurred.

For the purposes of these financial statements the Directors consider the fair value to reflect the value that is recorded in Northpet's financial statements. The Directors considered a number of factors to support this judgement including:

- there is no readily available "fair market value" as the assets have not been sold externally;

- the valuation of exploration and evaluation assets is highly subjective and could range from nil to hundreds of millions of Euro;

- the net value presented (minus the minority interest) is consistent with the value that would have been presented had the French Guiana asset continued to be recorded using a full cost accounting methodology.

On disposal, €527,000 previously unrealised foreign exchange losses on the translation of foreign joint ventures included in the Consolidated Statement of Other Comprehensive Income have been recognised as realised losses and transferred to the Consolidated Statement of Profit or Loss.

The revenue generated and expenses incurred by this operation since the date of acquisition (18 October 2013) were €Nil and €31,000 respectively. Of the €31,000 expenses, €15,000 relates to administration costs and €16,000 relates to foreign exchange losses. Cash outflow from the operation post acquisition was €2,813,000 and comprised the administration costs and investments in oil and gas assets. If the acquisition had occurred on 1 January 2013, management estimates that consolidated revenue would have been unchanged and the consolidated costs for the year would have been €32,000 higher.

Following the change in control the Group fully consolidated Northpet. Post change of control Northern Petroleum subscribed for additional ordinary shares in Northpet, increasing its percentage ownership to 55.2% at year end and 55.9% post year end.

4. 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.

During the year the Group received 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 surveys acquired in 2009 and 2010 over licences in the Sicily Channel. 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.

During the year the reserves in respect of the Southern Adriatic have been reclassified from 2P (proven, plus probable) to 2C (proven, plus probable, contingent on development). As a result of this change in assessment, management have reclassified the undeveloped Italian contingent resources as intangible assets, a transfer of €18,208,000 from plant, property and equipment.

Included in transfers in Italy for the year is €1,039,000 in respect of some of the costs of the Savio 1x well owing from Avobone Italy. Despite obtaining a UK High Court judgement and European Enforcement Order to recover the debt, the Group has still to obtain settlement and the Directors have decided to transfer this part of the cost from trade and other payables to intangible assets.

The Group tests intangible assets for impairment when there is an indication that the assets might be impaired. The Directors have undertaken 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 have reassessed the strategic priorities of the Group. As a result of this decision certain assets have been impaired as they no longer have an active exploration or development programme. Impairments of €5,298,000 have been 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 €7,986,000 has been recognised in Italy for Po Valley exploration, (including the Savio and La Tosca wells), the Sicily Channel "Thrust Belt", and other onshore exploration licences.

At the year end the contractual commitments for capital expenditure in respect of intangible assets was €1,573,000 (2012: €763,000), of which the Group's share was €1,545,000 (2012: €444,000). Of the €1,545,000, €218,000 is expected to be paid by Wessex Exploration PLC, (the non controlling interest), in respect of French Guiana.

At 31 December 2013 the Group had fully impaired its investment in and share of the exploration and evaluation assets of associate companies.

The comparative tables for 2012 are detailed below:

* The Group's investment in French Guiana via its holding in Northpet Investments Limited was included in Investments at 31 December 2012.

b) IT systems

5. PROPERTY, PLANT AND EQUIPMENT

a) Oil and Gas Assets

*note 2.

At the year end the contractual commitments for capital expenditure in respect of property, plant and equipment was €nil (2012: €1,783,000), of which the Group's share was €nil (2012: €666,000).

During the year the reserves in respect of the Southern Adriatic have been reclassified from 2P (proven, plus probable) to 2C (proven, plus probable, contingent on development). As a result of this change in assessment, management have reclassified the undeveloped Italian contingent resources as intangible assets, see note 4.

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

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

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

The carrying value of proven developed oil and gas assets in the Canada represents cost incurred in respect of the Bow Valley gas discovery, which is awaiting assessment of options for development.

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 have the potential to be commercial discoveries, the Group believes that further appraisal needs to be undertaken to produce a viable development plan which would lead to commercial production. The UK undeveloped oil and gas assets have been fully impaired resulting in a charge of €4,325,000.

The comparative tables for 2012 are detailed below:

b) Non-Oil and Gas Assets

The comparative table for 2012 is detailed below: