Atlantic Petroleum P/F — Annual Report 2013

Mar 14, 2014

About Atlantic Petroleum3
Listing on Oslo Stock Exchange4
Fueling Growth 5
Chairman's Statement6
Chief Executive Officer's Statement 8
North West Europe Focused 10
Project Portfolio 11
Development & Production12
Emerging Pipeline of High Impact Exploration Prospects14
Atlantic Petroleum Group Structure 16
Directors' Report17
Statement by Management on the Annual and Consolidated Report and Accounts47
Independent Auditor's Report48
Consolidated Income Statement50
Consolidated Statement of Comprehensive Income 51
Consolidated Statement of Financial Position52
Consolidated Statement of Changes in Equity53
Consolidated Statement of Cash Flows 54
Notes to the Consolidated Accounts55

14th March:	2013 Annual Financial Statement
th April: 9	Annual General Meeting
21th May:	st Quarter 2014 Interim Financial Statement 1
27th August:	nd Quarter 2014 Interim Financial Statement 2
12th November:	rd Quarter 2014 Interim Financial Statement 3

A FULL CYCLE EXPLORATION & PRODUCTION COMPANY

THE ATLANTIC PETROLEUM GROUP IN BRIEF

Atlantic Petroleum is a full cycle E&P company. Our portfolio of assets spans the full-cycle E&P value chain of exploration, appraisal, and development through to production and is located in some of the world's most prolific hydrocarbon basins.

Our main focus is on offshore North West Europe where we can provide steady growth from the existing asset base and be prepared to acquire new assets.

At year end 2013 Atlantic Petroleum held a total of 41 oil and gas licences covering 110 blocks and part blocks in the UK, Norway, Faroe Islands, Ireland & the Netherlands, producing oil & gas from three fields in the UK part of the North Sea. Three fields are under development or near development. We participate in joint ventures containing around 30 high quality partners.

With a strong operating cash flow Atlantic Petroleum is well positioned for further growth.

BUSINESS MODEL FOR LONG TERM GROWTH

Atlantic Petroleum has a balanced portfolio where exploration and development is underpinned by a solid production base.

Broad exposure to NW Europe exploration in existing portfolio – balanced between high and moderate risk opportunities.

Solid cash flow and balance sheet.

Strong management team with proven track record and a competent technical team.

A high number of reputable partners.

Atlantic Petroleum is continuously screening for and identifying new farm-in and acquisition opportunities and assessing the viability of possible investments.

STRATEGY & BUILDING BLOCKS

AN IMPORTANT MILESTONE

12th December 2013 - Bell ceremony at the Oslo Stock Exchange: Bente A Landsnes, CEO of Oslo Stock Exchange, Ben Arabo, CEO Atlantic Petroleum, Jonny Hesthammer, MD Atlantic Petroleum Norge AS

12th December 2013 was another milestone for Atlantic Petroleum - following a successfull offering of new shares - Atlantic Petroleum was listed on Oslo Stock Exchange. The Norwegian market can provide a significant investor interest and insight into the E&P sector. There is also a significant focus on the E&P sector from research analysts.

The prime reason for the equity raise is the Company's ambition to accelerate growth by pursuing current farm-in opportunities and other exploration opportunities, especially on the Norwegian Continental Shelf and to boost the balance sheet.

Atlantic Petroleum considers the Norwegian Continental Shelf to offer a number of quality high-impact exploration opportunities, and based on the Group's acquisition of Emergy Exploration (now Atlantic Petroleum Norge AS) in 2012 and establishment of a skilled organisation in Norway, Atlantic Petroleum is well-positioned for expanding its Norwegian footprint.

SIGNIFICANT MILESTONES ACHIEVED IN 2013

Atlantic Petroleum added licences in both Norway and UK and increased our reserves base through the acquisition of Orlando and Kells fields. By raising equity we strengthened our financial position to fuel our growth plans. The entry into the Oslo Stock Exchange marks a major milestone in Atlantic Petroleum's history and is instrumental to executing our ambitious growth strategy

SIGNIFICANT ACHIEVEMENTS IN 2013

• Successful acquisition of 25% working interest in UK licences P1606 and P1607 containing the development assets Orlando and Kells. With the acquisition reserves (P50), contingent and prospective resources more than doubled. Orlando field development has been approved by DECC, with first oil expected in 2016
• Successful in UK 27th Licensing Round awarded 12 blocks in 4 licences bringing the total number of 27th Licencing Round blocks up to 23 in 8 licences
• Successful in Norwegian 22nd Licensing Round awarded 6 blocks in 2 licences
• Successful in Norwegian APA round awarded 4 blocks in 2 licences
• Successfully farmed into two Norwegian licences PL 659 containing several prospects including Langlitinden and PL 528 containing the Ivory prospect
• Drilled two exploration wells in 2013. Magnolia in the UK and Dunquin in Ireland

• Extended field life of Chestnut with FPSO contract extended for at least 1 further year

• Extending field life by drilling two in-fill wells on producing assets - one drilled on the Ettrick field and one committed on the Blackbird field

• Listed on the Oslo Stock Exchange increasing stock liquidity and attracting attention from investor base and analyst coverage
• Completed equity raise net proceeds of NOK 155MM to boost balance sheet and pursue exploration
• Set up exploration debt facility with DNB in Norway of NOK 300MM
• Production 720K boe
• EBITDAX DKK 224MM
• Net result after taxation loss of DKK 26MM
• Operating cash flow DKK 219MM from a realised oil price of USD 109.2 per barrel
• Total equity shareholders´ funds at year end DKK 597MM
• Cash and cash equivalents at year end DKK 185MM

EXPLORATION Drill 4 exploration/appraisal wells targetting 86MMboe of net unrisked resources PRODUCTION Production in 2014 average per day between 1,650 – 1,900 boepd net for the year FINANCIAL EBITDAX in the range DKK 125MM - 175MM (Earnings Before Interest, Taxes, Depreciation, Amortisation and Exploration Expenses)

2013 was a challenging year for small to mid cap oil and gas companies. In a year where equity markets in the industrialised world experienced large gains, with European equities up more than 20% and US equities north of 30%, the shareholders of Atlantic Petroleum experienced a loss of 30%. Atlantic Petroleum severely underperformed the Danish overall stock market as well as the small cap index. Compared to its peer group the underperformance was modest. However the peer group saw a huge dispersion of returns in 2013 ranging from minus 94% to plus 58%.

The underperformance of Atlantic Petroleum's peer group to other sectors reflects the challenging conditions facing oil producers and explorers, however the outlook seems to be improving. Oil prices were stable in 2013 and Brent WTI fluctuated around USD 110 for most of the year. The industry also saw consolidation in 2013 – a development we expect to continue in 2014.

In 2013 Atlantic Petroleum produced 720,000 boe which was slightly below forecast. Write downs on a number of unsuccessful wells affected profitability however cashflow/EBITDAX was around the expected range. Reserves increased by 70%.

Birgir Durhuus, Chairman of the Board

The year marked milestones in Atlantic Petroleum's efforts to secure the long term success of the Company.

In December Atlantic Petroleum was listed on Oslo Stock Exchange on the back of a capital raise which injected almost DKK 120MM of new cash to the Company. The capital is vital to Atlantic Petroleum as it strives to kick off its Norwegian program while maintaining sound and robust finances.

For existing shareholders the Norwegian entry was at a high cost, as investors craved a significant discount to the market value to participate in the capital raise. Even though the first well Langlitinden didn't return instant success, the board and the management are convinced of long term success in its Norwegian adventure.

The capital raise has welcomed a number of new institutional investors to Atlantic Petroleum as well as increased the number of analysts covering the Company. The Oslo listing has had a slow start but we are confident that this will improve in the longer term.

THE BOARD AND THE MANAGEMENT ARE CONVINCED OF LONG TERM SUCCESS IN ITS NORWEGIAN ADVENTURE

In 2013 Atlantic Petroleum was awarded

several new licences in both UK and Norway. On several of these the Company's technical staff have identified high quality prospects to drill over the next few years.

Looking forward the success of Atlantic Petroleum hinges on a number of key pillars. Firstly the existing production must continue to perform in line with expectations. Secondly the exploration drilling programme in Norway and UK must deliver economic discoveries, and thirdly production on Orlando & Kells must be brought on stream without too much delay.

The Company has a robust programme going forward with numerous high quality prospects that could transform the Company and deliver the game changer, that secures the Company's long term success.

Birgir Durhuus Chairman of the Board Copenhagen 14th March 2014

BUILDING MOMENTUM

Production is the backbone of the Company; it provides the cash flow to fund our growth aspirations. I am pleased to report that all three producing fields in our portfolio performed well in 2013. The Chestnut field continues to perform well above expectations. In September 2013 we announced the extension of the contract on the Hummingbird FPSO for a further year (until March 2016). We are confident that Chestnut will continue to produce above our current predictions. Studies are underway to update the existing reservoir models to produce improved forecasts and reserve estimates. It is Atlantic Petroleum's view that the oil initially in place in the Chestnut field could be as much as 70MMBoe, and given a recovery factor based on fields of a similar geologic age, the reserves in the field are likely to increase significantly. Unlocking the upside potential in Chestnut will be a focus area for Atlantic Petroleum going forward.

We continue to invest in the Ettrick and Blackbird fields to extend their producing lives. The Ettrick P9 infill well was drilled in 2013. The well was placed on-stream in late 2013 and has led to a boost in production and reserves. The water injector well in Blackbird was completed in the second quarter of 2013 and provides pressure support for the field. A second Blackbird producer

Ben Arabo, CEO

will be drilled in 2014. Production in all fields was affected by the poor weather late in 2013 and the beginning of 2014.

During 2013 we produced 720,000boe. Despite this our P50 reserves increased from 5.1MMBoe year end 2012 to 6.4MMBoe year end 2013 (excluding Kells).

The acquisition of the Orlando and Kells fields was completed in February of 2013. These fields will provide medium term production growth for Atlantic Petroleum. The production will be relatively high value due to the competitive operating and development costs. The Orlando Field Development Programme was approved by the Regulatory Authority (DECC) in April 2013. The Orlando development is a subsea tieback to the Ninian Central Platform (NCP). Discussions have been in progress with the operator of the NCP to secure commercial terms for the modifications to the platform for a considerable time. The negotiations are proving to be slower to conclude than expected. DECC is

aware of the situation and is assisting in finding a resolution of the outstanding issues. The operator of the Orlando Field continues to push for 2015 first oil however our expectation is that first oil will slip into 2016.

We believe that exploration has the potential to add significant value to the Company. We are in a process of enhancing and high-grading our exploration portfolio to ensure that shareholder's money is only used to drill the highest quality exploration prospects. We acquired the Norwegian company Emergy in late 2012 to facilitate our entry into Norway. Norway is a very attractive area from the exploration perspective. The Norwegian Continental Shelf has not been drilled to the extent of the UK sector, big discoveries are still being made and the Government of Norway provides attractive fiscal incentives for exploration companies.

We continue to add acreage to our exploration portfolio through licensing rounds. In 2013 we added 4 further licences in the UK and 4 in Norway. In Norway, we are acquiring licences in the vicinity of the Aasta Hansteen gas development. Norway is extending its gas export infra-structure into this region to take production from Aasta Hansteen. This presents the opportunity to easily commercialise any discovery in the region. The area is relatively under-explored. We have been able to secure acreage with large prospects supported by geophysical anomalies and electromagnetic responses.

One of the key uses of the funds raised from the capital raise and listing in Oslo was to advance our exploration efforts in Norway. We have used part of the funds to farm into PL 528 which contains the Ivory prospect which will be drilled in late 2014. This block is highly prospective and forms part of our developing position in the Aasta Hansteen area. We also farmed into PL 659 which contained the Langlitinden prospect in the Barents Sea. This area is now becoming very prospective as oil discoveries are being made. The Langlitinden well was drilled in the first quarter of 2014. The discovery of oil is very encouraging for the overall licence even though the reservoir quality found in the well was poor analysis and studies are ongoing and we will know more in due course. There are a significant number of other prospects in the block where better reservoir quality may be present. There is also the possibility that the reservoir quality will vary and improve within the Langlitinden structure.

Later in 2014 the Brugdan II well in the Faroe Islands will be re-entered followings its temporary suspension in 2012. This well will test a very large structure which if positive can have a very large impact on Atlantic Petroleum both with respect to this prospect and the other Faroese shelf acreage held by Atlantic Petroleum. In May we will be drilling the Pegasus appraisal well in the UK. This well follows the discovery well made by Volantis Exploration in 2011. Pegasus can, if successful, offer a production opportunity in the short to mid-term.

Atlantic Petroleum remains one of the more active small cap companies in offshore NW Europe. We remain focused on delivering production growth in the medium term with the potential for large capital growth through exploration.

The 2014 programme has the potential to deliver new discoveries and short term production opportunities. Thanks to the actions in 2013, 2014 has the potential to become a transformational year for Atlantic Petroleum.

Ben Arabo CEO Tórshavn 14th March 2014

OPERATIONS IN PROLIFIC AREAS

A TOTAL OF 45* LICENCES AT REPORT DATE COVERING 125 BLOCKS/PART BLOCKS

UK

3 licences in UK Central North Sea with fields in production. 25 exploration, appraisal & development licences in the UK sector of the North Sea, Central North Sea, Southern North Sea & West of Shetland. One UK field has been sanctioned for development, and two are near development

FAROE ISLANDS

2 exploration licences with significant potential

IRELAND

2 exploration & appraisal licences with several identified prospects

NETHERLANDS

4 exploration licences

NORWAY

9 exploration & appraisal licences in Norwegian Sea, Barents Sea and Norwegian sector of North Sea (*3 are subject to governmental approval). Potential to increase significantly through licensing rounds and farm-ins (numerous interesting opportunities identified)

CHESTNUT FIELD

Central UK sector North Sea Water depth: 120 m Production startup: September 2008 Overall length: 66 m Accommodation: 44 persons Liquid production capacity: 30,000 bbl/day Crude storage capacity: 270,000 bbls/43,000 m3

Norwegian Sea

Barents Sea

Faroe Islands

Porcupine

West of

Norwegian North Sea

UK Southern North Sea

Netherlands

ETTRICK & BLACKBIRD FIELDS Central UK sector North Sea Water depth: 115 m Production startup: August 2009 Ettrick, November 2011 Blackbird Overall length: 248 m Accommodation: 90 persons Liquid production capacity: 35,000 bbl/day Crude storage capacity: 618,000 bbls/98,000 m3

SUBSTANTIAL PIPELINE OF OPPORTUNITIES

Atlantic Petroleum's portfolio of assets covers the full exploration and production spectrum, from frontier exploration to mature production. We have made large efforts in the last two years to increase and highgrade the number of opportunities available, specifically in exploration and development. This means that organic growth from within the portfolio is viable.

BROAD EXPOSURE TO NW EUROPE EXPLORATION IN EXISTING PORTFOLIO

Licence	Block		Area Field/Prospect/Lead	Operator	P50 net MMboe *	%	AP Exploration	Appraisal	Development	Production
P354	22/2a		UK Chestnut Field	Centrica		1,1 15.00
P273 & P317	20/2a,3a		UK Ettrick Field	Nexen		1,1 8.27
P273, P317 & P1580 20/2a,3a,3f			UK Blackbird Field	Nexen		0,4 9.40
P1606	3/3b		UK Orlando Field	Iona		3,8 25.00				Est. 2016
P1607 P218 & P588	3/8d 15/21a,c		UK Kells Field UK Perth Field 1)	Iona Parkmead		2,3 25.00 5,1 13.35			Near Near	Est. 2016/17 Est. TBA
P218 & P1655	15/21a Gamma subarea & 15/21g		UK Gamma Central Discovery	Premier		- 3.24
P218	15/21a		UK North East Perth Discovery	Parkmead		1,7 13.35
P218	15/21a		UK Dolphin Discovery	Parkmead		0,8 13.35
P273	20/3a		UK Bright Discovery	Nexen		1,5 8.27
P1556	29/1c		UK Orchid Discovery	Trap Oil		0,5 10.00
P1655	15/21g,a (part)		UK Spaniards	Premier		0,6 3.24
P1673	44/28a		UK Fulham & Arrol Discoveries	Centrica		0,4 5.00
P1724	43/13b		UK Pegasus North Discovery	Centrica		1,7 10.00
P1727	43/17b,18b		UK Harmonia Flank & Browney Discoveries	Centrica		- 10.00
P1933	205/23		UK Bombardier Discovery	Parkmead		- 43.00
PL 270	35/9	NO	Agat Discovery	VNG Norge		0,4 15.00
PL 270	35/9	NO	Bloody Basin	VNG Norge		1,1 15.00
SEL 2/07	50/11 (part)		IR Hook Head Discovery	Providence		6,4 18.33
SEL 2/07 SEL 2/07	49/9 (part) 50/5 (part) & 50/7 (part)		IR Helvick Main Discovery IR Dunmore Discovery	Providence Providence		0,4 18.33 0,1 18.33
P2108	42/21,22a		UK Prometheus	Centrica		1,3 20.00
FEL 3/04	44/24,29		IR Dunquin South	ExxonMobil		14,5 4.00
P588	15/21c		UK North West Perth Prospect	Parkmead		2,5 13.35
P218	15/21a		UK East Perth Prospect	Parkmead		0,5 13.35
P1556	29/1c		UK Orchid West	Trap Oil		0,8 10.00		development.	1 Joitnt studies are ongoing for a joint Perth/Lowlander
P1610	13/23a		UK Albacora	Dana		- 20.00
P1610	13/23a		UK Minos	Dana		- 20.00		2 ) Relinquished 6t	h January 2014
P1724	43/13b		UK Pegasus West Prospect	Centrica		2,3 10.00		3	) Farm-in option agreement signed 2n	d January 2014.
P1724	43/13b		UK Pegasus Flanks Prospect	Centrica		0,6 10.00			AP shall purchase 5% in PL528 and has an option to
P1734	48/8c		UK Selene Prospect 2)	Centrica		- 10.00		purchase up to 15%
P1734	48/8c		UK Endymion Prospect 2)	Centrica		- 10.00			4) Awarded in the APA 2013 Licensing round announced
P1766	13/22d		UK Magnolia West / Ensign	Dana		- 20.00		21st January 2014
P1767	14/9,14a		UK Anglesey North Prospect	Bridge Energy		4,1 30.00			5) Farm-in agreement is pending government approval.
P1767	14/9,14a		UK Anglesey Central Prospect	Bridge Energy		8,4 30.00
P1767	14/9,14a		UK Anglesey South Prospect	Bridge Energy		2,8 30.00
P1767	14/15		UK Chenas	Bridge Energy		2,3 30.00		Abbreviations:	MMBoe = million barrels of oil equivalents
P1767 P1767	14/15 14/15		UK Fleurie UK Brouilly	Bridge Energy Bridge Energy		3,3 30.00 1,3 30.00
P1767	14/15		UK Morgon	Bridge Energy		2,6 30.00		sub-phases	Note: The four phases have not been categorised into
P1791	21/30e		UK Cracker Lead	Bridge Energy		- 20.00
P1791	21/30e		UK Jaffa Lead	Bridge Energy		- 20.00			* Gaffney, Cline & Associates CPR as at 31st December 2013. P50 Reserves for Development & Production
P1828	36/27,28,29		UK Area Y Leads	Centrica		- 10.00			assets. Contingent Resource or Net Unrisked
P1899	44/4a,5,45/1		UK Lead B	Centrica		- 10.00		assets.	Prospective resources for Exploration & Appraisal
P1906	47/2b,3g,7a,8d		UK A,B,C,E, W of York & Westminister Leads Centrica			- 10.00
P1933	205/24,25		UK Eddystone Prospect	Parkmead		71,4 43.00
P1993	15/16e		UK Birnam Prospect	Parkmead		7,8 33.00
P2069	205/12		UK Davaar	Parkmead		47,7 30.00
P2082	30/12c,13c,18c		UK Skerryvore	Parkmead		4,9 30.50
P2082	30/12c,13c,18c		UK Skerryvore Chalk	Parkmead		20,1 30.50
P2112	43/29a,30b, 44/4b,5a		UK Badger	Centrica		- 20.00
P2126	42/2b,43/3b,42/7,8b,9b		UK Aurora	Centrica		13,4 10.00
P2128 P2128	43/12 43/12		UK Andromeda UK Andromeda South	Centrica Centrica		0,6 10.00 0,6 10.00
PL 270	35/9	NO	Turitella Prospect	VNG Norge		1,7 15.00
PL 270 B	35/2,3 (part)	NO	4)	VNG Norge		- 15.00
PL 528	6707/8,9,10 (part),11	NO	Ivory Prospect 3)	Centrica		- -
PL 528 B	6707/10 (part)	NO	Ivory Prospect 3)	Centrica		- -
PL 559	6608/10, 6008/11	NO	Hendricks Prospect	Rocksource		13,2 10.00
PL 704	6704/12, 6705/10 (part)	NO	Gjallar/Napoleon South	E.ON Ruhrgas		14,1 30.00
PL 705	6705/7 (part),8,9,10 (part)	NO	Gjallar/Napoleon North	Repsol		18,5 30.00
PL 763	6606/2,3 (part)	NO	4)	Repsol		- 30.00
PL659	7121/3,7122/1,2,7221/10,12,7222/11,12 NO		Langlitinden 5)	Det norske		- 10.00
E4	E4		NL Hals Prospect	Centrica		0,5 6.00
E1 & E2	E1 & E2		NL Maes Prospect	Centrica		0,7 6.00
E1 & E4	E1 & E4		NL Vermeer Prospect	Centrica		- 6.00
E1	E1		NL Rembrandt & Steen Prospects	Centrica		- 6.00
E4 & E5	E4 & E5		NL Metsu Prospect	Centrica		0,2 6.00
E5	E5		NL Van Goyen Prospect	Centrica		0,3 6.00
E4 L006	E4 6104/16a,21, 6105/25	FO	NL Cuyp Prospect Brugdan Deep Prospect	Centrica Statoil		0,7 6.00 23,2 1.00
L016	6202/6a,7,8,9,10a,11,12,13,14,15	FO	Kúlubøkan Prospect	Statoil		29,3 4.00
	16,17,18,21a,22a, 6203/14a,15a 16,17,18,19,20,21,22,23,24a,25a

A YEAR OF INVESTMENT

EXPECTED INITIAL PRODUCTION FROM ORLANDO 10,000+ BOPD GROSS

PRODUCING ASSETS

In 2013, Atlantic Petroleum produced a total of 720,000 boe from the Chestnut, Ettrick and Blackbird fields, which is slightly lower than anticipated. (Revised 2013 guidance was 725,000-800,000 boe). This equates to an average production of 1,973 boepd. The main reasons were the unexpected Chestnut shut-down during November and slightly later than anticipated first oil from the new Ettrick E9 infill well.

The Department of Energy and Climate Change (DECC) approved an increased flare consent on the Chestnut field allowing higher annual production rates, but production was temporarily suspended in November, which lead to lower than expected production. The suspension was due to an issue with a mooring line on the Hummingbird FPSO, which was rectified by the end of the month. Due to the excellent reservoir performance, an extension to the Hummingbird FPSO contract was also agreed, allowing production to continue until at least March 2016. Furthermore, we are confident that Chestnut will continue to produce strongly in the future. Studies are underway to update the existing reservoir models to produce improved forecasts and reserve estimates. It is Atlantic Petroleum's view that the oil initially in place in the Chestnut field could be as much as 70MMBoe, and given a recovery factor based on fields of a similar geologic age, the reserves in the field are likely to increase significantly (14.1MMboe has been produced to the end of 2013). Further contract extensions on the Hummingbird FPSO are being negotiated along with other long term options for the field.

The Blackbird Field Development Plan addendum was approved and will result in the drilling of a second production well in 2014 and is expected to be in production 3Q 2014. Blackbird water injection commenced in early 2013 and production improved as a result of increased pressure support.

On Ettrick, the production remained relatively stable and within expectations. The infill well 20/02a-E9 on the Ettrick field was drilled and completed, but slightly later than planned. As a result of the new well, the rate of production from the Ettrick field has increased significantly and has increased the reserves of the Ettrick field.

P/F Atlantic Petroleum Annual and Consolidated Report and Accounts 2013 Issued 14th March 2014 12/83

DEVELOPMENT & NEAR DEVELOPMENT

The development of Orlando was sanctioned by Atlantic Petroleum in February 2013 and by DECC in April 2013. Orlando will be developed as a subsea tie back to the Ninian Central Platform in the Northern North Sea. Discussions have been in progress with the operator of the NCP to secure commercial terms for the modifications to the platform for a considerable time. The negotiations are proving to be slower to conclude than expected. DECC is aware of the situation and is assisting in finding a resolution of the outstanding issues. The operator of the Orlando Field continues to push for 2015 first oil however our expectation is that first oil will slip into 2016. The expected initial rate from Orlando is 10,000+ bopd gross and according to the latest Gaffney Cline & Associates CPR report the Orlando field contains 3.84MMBoe resources net to Atlantic Petroleum.

Operator Iona continued with pre-sanction work on the Kells field in 2013. It is expected that the Kells field development plan will be submitted and sanctioned in late 2014 or early 2015, with first oil planned in late 2016 or 2017.

In early 2013, the Perth partners had been working towards potentially drilling a well in 2014 to evaluate a region of the field called Core Perth Extension. Later in the year, efforts focused on examining options for a joint field development with the nearby Lowlander discovery. As a result of this, plans for the well were suspended and joint studies are now ongoing to determine the feasibility of a joint Perth/Lowlander development.

	PRODUCTION			SANCTIONED FOR DEVELOPMENT	NEAR DEVELOPMENT
	Chestnut	Ettrick	Blackbird	Orlando	Kells	Perth
Discovery	1986	1981	2008	1989	1985	1992
Entry date by Atlantic Petroleum	2003	2003	2003	2013	2013	2003
Atlantic Petroleum equity	15.00%	8.27%	9.39%	25.00%	25.00%	13.35%
Reserves & Resources	1.1MMBoe		1.1MMBoe 0.4MMBoe	3.8MMBoe	2.3MMBoe	5.1MMBoe
Production start	2008	2009	2011	2016	2016/17	TBA
Partners	Centrica (Op) Nexen (Op) Nexen (Op)			Iona (Op)	Iona (Op)	Parkmead (Op)
	Dana	Dana				Faroe Petroleum

P/F Atlantic Petroleum Annual and Consolidated Report and Accounts 2013 Issued 14th March 2014 13/83

EXPLORATION PROGRAMME TARGETS 86MMBOE OF NET UNRISKED RESOURCES

Atlantic Petroleum continues to improve its portfolio of exploration and appraisal licences. By year end 2013 the Group held a total of 110 blocks in 41 licences. By report date this number had increased to 125 blocks in 45 licences.

WE ARE ONE OF THE MOST ACTIVE SMALLCAP COMPANIES IN NWE

The Atlantic Petroleum Group added seven new exploration licences in 2013 of which two are on the highly prospective Norwegian Continental Shelf, one in Ireland and the other four are on the UK Continental Shelf. As part of ongoing portfolio rationalization and

improvement, a total of six exploration licences were relinquished in 2013, five in the UK and one in the Faroe Islands.

In Norway, Atlantic Petroleum was awarded two new licences in the Norwegian 22nd licensing Round. Licences PL 704 and PL 705 both contain multiple high potential prospects that have been de-risked prior to application, and given a discovery, could be tied in to the nearby Aasta Hansteen Field development. At the end of 2013, the Company reached an agreement with Det norske oljeselskap ASA to acquire a 10% interest in the Norwegian Licence PL 659 containing the Langlitinden prospect. The Langlitinden well spudded in January 2014, and is a milestone for Atlantic Petroleum, as it was the Company's first well on the Norwegian Shelf. Following extensive loggin and coring, the well results indicate that the main target was oil bearing, but that the reservoir quality at the well location was worse than expected, so no drill stem testing was undertaken. The agreement is subject to government approval.

		LICENCE			2015
				1Q	2Q	3Q	4Q	1Q
	UK	P1724 Pegasus West (Committed)	Exploration well
	Exploration	PL528 Ivory (Committed)	Exploration well
	Norway	PL659 Langlitinden (Committed)	Exploration well
	Faroe Islands	L006 Brugdan II (Committed)	Exploration well
Production	UK	P317, P273, & P1580 Blackbird (Committed)	Production well

2014 HAS THE POTENTIAL TO BECOME A TRANSFORMATIONAL YEAR FOR ATLANTIC PETROLEUM

In the UK, four new licences were awarded as part of the delayed UKCS 27th Round. The licences are all in the Southern Gas Basin (SGB) of the UKCS and continues the Company's focus on securing opportunities in the emerging Carboniferous gas trend. Two of the new licences have contingent well commitments. An exploration appraisal well will be drilled on the Pegasus structure in 2Q 2014. In 2013 the Company also drilled a well on the Magnolia prospect in the Central North Sea, but unfortunately the well was P&A'd as a dry hole. New 3D seismic surveys were acquired on three of the licences in the SGB and are currently being interpreted by operator Centrica and Atlantic Petroleum.

In Ireland, Atlantic Petroleum entered into licence FEL 3/04 gaining a 4% interest, following a deal with Exxon. During the year, the Dunquin exploration well was drilled and then P&A'd.

In the Faroes, in a concurrent transaction, the Company divested six percent interest in Licence 016 to Exxon. Faroes Licence 014 was also relinquished. Planning is underway for the Brugdan II well re-entry in 2Q 2014, with results expected around mid year.

Work continues on the Netherlands licence portfolio and an extension to the licence terms is being sought.

A EUROPEAN OIL COMPANY

The Atlantic Petroleum Group comprises the Faroes based parent company P/F Atlantic Petroleum and its five 100% owned subsidiaries in UK, Norway, Ireland and Netherlands.

P/F Atlantic Petroleum is listed on NASDAQ OMX Copenhagen under the ticker FO-ATLA CSE and on Oslo Stock Exchange under the ticker ATLA.

Financial Review

Financial Review
KEY NUMBERS/FIGURES	3 months 1st Dec 3	3 months 1st Dec 3	Full year 1st Dec 3	Full year 1st Dec 3	Full year 1st Dec 3	Full year 1st Dec 3	Full year 1st Dec 3
DKK 1,000	2013	2012	2013	2012	2011	2010	2009
PROFIT & LOSS
Revenue	89,126	159,433	417,421	596,745	434,831	422,470	219,252
Gross profit	25,952	141,833	195,655	321,857	173,634	166,030	54,613
EBITDAX (EBIT before Depreciation &
Amortisation and Exploration expenses)	39,710	98,716	223,748	412,452	259,681	276,806	103,076
Operating loss/profit (EBIT - Earnings before
interest and taxes)	1,267	113,828	-1,629	246,771	126,319	147,331	-75,621
Depreciations	32,571	-24,965	105,729	138,472	115,551	129,105	69,594
Loss/profit before taxation	-3,848	112,031	-11,623	227,658	127,526	163,083	-60,442
Loss/profit after taxation	-1,649	28,910	-25,674	66,660	66,635	109,107	-54,870
BALANCE SHEET
Non-current assets	921,804	733,982	921,804	733,982	576,967	513,298	510,566
Current Assets	315,375	387,834	315,375	387,834	199,976	158,524	136,283
Total assets	1,237,179	1,121,816	1,237,179	1,121,816	776,943	671,821	646,848
Current liabilities	141,541	149,479	141,541	149,479	106,917	113,458	154,729
Non-current liabilities	498,293	435,196	498,293	435,196	240,719	180,463	213,159
Total liabilities	639,834	584,676	639,834	584,676	347,636	293,921	367,888
Net assets/equity	597,345	537,140	597,345	537,140	429,307	377,901	278,960
CASH FLOW & DEBT
Cash generated from operations	90,705	48,635	219,146	367,561	269,934	239,686	54,036
Change in cash and cash equivalents	140,842	-59,445	-54,183	127,018	29,048	55,054	14,617
Net cash	81,555	164,521	81,555	164,521	9,345	-107,771	-264,902
Bank debt	103,058	78,000	103,058	78,000	104,968	162,303	283,705
FINANCIAL STATEMENT RELATED FIGURES
Gross Margin % (Gross profit or loss / Sales)	29.1%	89.0%	46.9%	53.9%	39.9%	39.3%	24.9%
EBIT Margin % (Operating Margin) (EBIT/Sales)	1.4%	71.4%	-0.4%	41.4%	29.1%	34.9%	-34.5%
EBITDA Margin % (EBITDA/Sales)	38.0%	55.7%	24.9%	64.6%	55.6%	65.4%	-2.7%
Return on Equity (ROE) (%) (Profit for the period
excl. Minorities/Average Equity excl. Minorities)	-0.3%	5.6%	-5.0%	13.8%	16.5%	33.2%	-24.6%
SHARE RELATED FIGURES
Earnings per share Basic DKK	-0.57	11.18	-9.54	26.68	26.19	41.54	-34.79
Earnings per share Diluted DKK	-0.58	11.18	-9.67	26.54	26.19	41.54	-
Share price at end of period DKK/Share OMX CPH/IS & Oslo Stock Exchange (from 3Q 2013)	129/145 & 128	184/184	129/145 & 128	184/184	157/153	217/217,50	162/160
OTHER KEY NUMBERS/FIGURES
Full time equivalent positions	3 0	1 9	2 7	1 6	1 1	8	9

Consolidated Income Statement

The result after tax for 2013 was a net loss of DKK 25.7MM (2012: profit of DKK 66.7MM) and loss of DKK 1.6MM for the last quarter of 2013 (4Q 2012: DKK 28.9MM). In 2013 net oil production to Atlantic Petroleum from the Ettrick, Chestnut and Blackbird fields was 720,000 boe (2012: 928,000 boe).

Operating profit (EBIT) was loss of DKK 1.6MM in 2013 (2012: Profit of DKK 246.8MM).

At the outset of 2013 the Company provided a guidance on expected earnings before interest, taxes, depreciation, amortisation and exploration expenses (EBITDAX) and production of oil equivalents (boe) in 2013. Guidance on production was in the range 700,000 – 800,000 boe. In May 2013 the guidance on production was revised to 725,000 - 800,000 boe. Full year production was 720,000 boe, slightly lower that the revised guidance due to an unanticipated temporary shutdown on Chestnut and a longer than expected shutdown on Ettrick/Blackbird related to annual maintenance and tie-in of the new Ettrick in-fill well. The range for EBITDAX was DKK 200.0MM - 250.0MM. In May the EBITDAX guidance was revised to DKK 225.0MM – 275.0MM. EBITDAX of DKK 223.7MM was slightly below the guidance provided.

Revenue generated from sale of hydrocarbons in 2013 was DKK 417.4MM (2012: DKK 596.7MM). Average realised oil price was 109.2 USD/bbl (2012: 112.3 USD/bbl).

Cost of sales amounted to DKK 221.8MM (2012: DKK 274.9MM). Cost of sales relates primarily to the operating cost of the Hummingbird and Aoka Mizu FPSO vessels, depreciation of producing fields and cost related to sale of hydrocarbons.

Gross profit was DKK 195.7MM in 2013 (2012: DKK 321.9MM).

Exploration cost amounted to DKK 119.6MM in 2013 (2012: DKK 27.2MM). The exploration expenditures written off in 2013 relate mainly to the relinquishment of Magnolia, Dunquin and PL559 Hendricks.

General and administration costs amounted to DKK 66.6MM in 2013 (2012: DKK 39.9MM) principally due to the full year effect of the Emergy acquisition completed November 2012.

Interest revenue and finance gains totalled DKK 1.5MM (2012: DKK 2.6MM).

Interest expenses and other finance costs amounted to 11.4MM (2012: DKK 21.7MM).

Loss before taxation totalled DKK 11.6 (2012: Profit of DKK 227.7 MM).

In 2013 taxation amounted to cost of DKK 14.1MM (2012: Cost of DKK 161.0MM).

The result after tax in 2013 was a net loss of DKK 25.7MM (2012: DKK Profit of 66.7MM).

Basic earnings per share were DKK -9.54 (2012: 26.68). Diluted earnings per share were DKK -9.67 (2012: 26.54).

Consolidated Statement of Financial Position

Total assets at the end of 2013 amounted to DKK 1,237.2MM (2012: DKK 1,121.8MM).

Consolidated Assets

Goodwill amounted to DKK 54.4MM (2012: DKK 57.7MM) pertaining to 2012 acquisition of Emergy Exploration AS and Volantis Exploration Limited in 2011.

Exploration and evaluation assets amounted to DKK 216.7MM at the end of 2013 (2012: DKK 215.8MM).

Development and production assets amounted to DKK 621.5MM at the end of 2013 (2012: DKK 440.8MM). The increase in booked value reflects that investments were higher than the depletion of the producing fields and mainly relates to Orlando. The depreciation amounted to DKK 97.6MM (2012: DKK 140.4MM).

Inventories at year end 2013 are at DKK 38.8MM (2012: DKK 14.0MM). This represents the value of underlifted production at the year end.

Trade and other receivables were DKK 48.5MM at the end of 2013 (2012: DKK 98.4MM). These mainly relate to ordinary contracts regarding sale of oil and gas in November and December 2013. All outstanding balances have been settled. Tax repayable in Norway amounted to DKK 43.5MM (2012: DKK 27.1MM).

Cash and cash equivalents were at DKK 184.6MM at the end of 2013 (2012: DKK 242.5MM).

Consolidated Liabilities

Total liabilities amounted to DKK 639.8MM at the end of 2013 (2012: DKK 584.7MM).

Total current liabilities totalled DKK 141.5MM at the end of 2013 (2012: DKK 149.5MM).

Short term debt amounted to DKK 44.6MM (2012: DKK 19.5MM). Trade and other payables amounted to DKK 94.8MM (2012: DKK 108.9MM). These relate primarily to the operator capex cost and also to the operating cost of producing fields.

Total non-current liabilities amounted to DKK 498.3MM at the end of 2013 (2012: DKK 435.2MM).

Deferred tax liability amounted to 267.0MM (2012: DKK 215.7MM). In 2013 Atlantic Petroleum provided for UK and Norwegian deferred tax to DKK 59.5MM (2012: 154.3MM).

Non-current liabilities also consist of a long term bank loan and of long term provision for abandonment costs for the Chestnut, Ettrick and Blackbird fields and two UK exploration wells and the three wells in Ireland. The amounts provided have been included in the cost of development and production assets and in the cost of exploration and evaluation assets. Some of the Irish costs incurred pre 3Q 2009 were subsequently impaired.

Consolidated Equity

The total shareholders' equity amounted to DKK 597.3MM at the end of 2013 (2012: DKK 537.1). In December 2013 the Company increased the share capital with 1,050,000 new shares with a nominal value of DKK 100 each. The cost of the capital raise was DKK 19.7MM. Atlantic Petroleum's nominal share capital at year end 2013 amounts to DKK 367.7MM consisting of 3.7MM shares each with a nominal value of DKK 100 or multiples thereof.

Cash Flow

Net cash provided from operating activities amounted to DKK 219.1MM (2012: DKK 367.6MM).

In order to secure a more stable revenue stream, the Company engaged in oil price hedging during 2013. Consequently the Company realised a loss on oil price hedging of DKK 0.5MM. In 2013 22% of expected oil production was hedged at an average oil price of USD 111.7/bbl.

Capital expenditures in the period were DKK 408.8MM (2012: DKK 213.6MM) principally relating to the acquisition of the development asset Orlando and near development asset Kells.

Net cash proceeds from financing activities amounted to DKK 135.4MM (2012: Spend of DKK 27.0MM).

Cash and cash equivalents totalled DKK 184.6MM at the end of 2013 (2012: DKK 242.5MM).

Investments

The additional capitalised investments in exploration and appraisal in 2013 amounted to DKK 150.0MM (2012: DKK 150.7MM). Total booked value at the end of 2013 amounted to DKK 216.7MM (2012: DKK 215.8MM).

During 2013 Atlantic Petroleum continued investments in the Ettrick and Blackbird developments and also invested in the Orlando and Kells (acquisition and project). The additional investments in development and production assets amounted to DKK 289.7MM in 2013 (2012: DKK 123.3MM). At the end of 2013, the booked value of development and production assets amounted to DKK 621.5MM (2012: DKK 440.8MM). The booked value is after deduction of depreciation.

Net Cash Position

At the start of 2013, the net cash position amounted to DKK 164.5MM. At year end 2013 this had decreased to a net cash position of DKK 81.6MM comprising DKK 184.6MM (2012: 242.5MM) of cash and cash equivalent balances, a short term bank loan of DKK 44.6MM (2012: 19.5MM) and a long term bank loan of DKK 58.5MM (2012: 58.5MM).

Significant Events after the Balance Sheet Date

The following significant events have occurred after the end of the financial year and prior to the approval of the financial statement for 2013:

• On 2nd January 2014 Atlantic Petroleum announced that the Group had entered into a farm-in option agreement with Rocksource ASA regarding the PL 528 licence in the Norwegian Sea. Through the farmin option agreement, Atlantic Petroleum agreed to purchase five percent (5%) with an option to purchase up to fifteen percent. The PL 528 licence contains the Ivory prospect sanctioned for drilling late 2014. The Ivory prospect is expected to be gas prone with Direct Hydrocarbon Indicator (DHI) support. It is adjacent to the Statoil-operated Aasta Hansteen field development which is due to come on stream in 2017. Rocksource currently carries a pre-drill resource range estimate of 55-306 MMboe. The agreement is subject to approval by the Norwegian Government.
• On 10th January 2014 Atlantic Petroleum announced exercise of the Over-Allotment Right. Reference was made to the stock exchange release published on 12th December 2013 and the prospectus dated 26th November 2013.The Board of Directors of Atlantic Petroleum P/F had resolved to issue 21,157 new shares each with a nominal value of DKK 100 at an issue price of DKK 123.8939 (calculated as the equivalent DKK value of the offering price of NOK 140 per share) to Carnegie AS and ABG Sundal Collier ASA (the "Joint Global Coordinators"), following exercise of the Over-Allotment Right as further described in the Prospectus and the stock exchange release of 12th December 2013. Following registration of the share capital increase in the Faroese Company Register, the Company would have 3,697,860 shares in issue each with a nominal value of DKK 100.
• On 10th January 2014 Atlantic Petroleum announced that the Stabilisation Period had ended. Carnegie AS gave notice that stabilisation was undertaken in relation to the shares in Atlantic Petroleum and that Carnegie AS had purchased 136,343 shares in the Company during the Stabilisation Period. As a result, Carnegie AS had exercised the Over-Allotment Right to subscribe for 21,157 new shares in Atlantic Petroleum.
• On 13th January 2014 Atlantic Petroleum announced that the capital increase of 21,157 new shares with a nominal value of DKK 100 each and a subscription price of NOK 140 pursuant to the exercise of the over-allotment right had been registered with the Faroese Company Registration authority. The issued share capital in Atlantic Petroleum following the share issue is DKK 369,786,000 consisting of 3,697,860 fully paid shares, each with a nominal value of DKK 100. The new shares are validly issued, fully paid up and non-assessable.
• On 14th January 2014 Atlantic Petroleum announced that drilling of the Langlitinden well (7222/11-2) in PL 659 had commenced. The licence is located c. 165 km NW of Hammerfest, and the water depth is c. 340 m. The 7222/11-2 Langlitinden well was being drilled by the semi-submersible Transocean Barents rig. The well would be drilled to a total depth of around 2900 m and operations were anticipated to take around 50 days. This would be extended in the case of discovery, in order to allow testing of the well. The prospect had an un-risked volume 154-374 mmboe in the main target interval (operator numbers) where both oil and gas may be present in the Kobbe Formation. The agreement is pending authority approval.

• On 21 st January 2014 Atlantic Petroleum announced that Atlantic Petroleum Norge AS (a wholly owned subsidiary of P/F Atlantic Petroleum) had been awarded the licences PL 763 and PL 270 B in the APA 2013 Licensing Round on the Norwegian Continental Shelf (NCS) announced by the Ministry of Oil and Energy on the 21st of January, 2014.

• On 4th February 2014 Atlantic Petroleum announced that NASDAQ OMX Iceland had accepted the Company's request from 13th November 2013 to remove the shares from trading on NASDAQ OMX Iceland. The delisting was effective as of close of trading on Friday 7th February 2014.

• On 10th February 2014 Atlantic Petroleum announced that the Company had, as partner in Norwegian licence PL 659, from core samples identified hydrocarbon shows in exploration well 7222/11-2 on the Langlitinden Prospect in the Barents Sea.
• On 11th February 2014 Atlantic Petroleum reissued the 2014 financial calendar.
• On 21st February 2014 Atlantic Petroleum announced that drilling operations on well 7222/11-2 on the Langlitinden prospect in License PL 659 were about to complete. The well (7222/11-2) encountered oilbearing sands of Triassic age. Movable oil was proved in the main target for the well, but mini-DST indicated poor reservoir properties at the well location. The well also encountered several hydrocarbon bearing sands in the lower Kobbe section.

Operational Review

North West European Licence Interests

		Year end Report date
	2013	March 2013 Block(s)		Operators	Partners
United		P218 & P588 P218 & P588	15/21a (part),b,c,f		Parkmead 52.03% Faroe Petroleum 34.62%, Atlantic Petroleum 13.35%
Kingdo m	P218	P218	15/21a (part) Gamma subarea	Premier 28%	Serica 21%, Cairn 21%, Parkmead 12.624%, Faroe Petroleum 8.4%, M aersk 5.736%, Atlantic Petroleum 3.24%
		P317 & P273 P317 & P273	20/2a,3a	Nexen 79.73%	Dana 12%, Atlantic Petroleum 8.27%
	P317	P317	20/2a Blackbird		Nexen 90.60227% Atlantic Petroleum 9.39773%
	P354	P354	22/2a	Centrica 69.875%	Dana 15.125%, Atlantic Petroleum 15%
	P1580	P1580	20/3f	Nexen 79.73%	Dana 12%, Atlantic Petroleum 8.27%
	P1556	P1556	29/1c	Trap Oil 60%	Ithaca 30%, Atlantic Petroleum 10%
	P1606	P1606	3/3b	Iona 75%	Atlantic Petroleum 25%
	P1607	P1607	3/8d	Iona 75%	Atlantic Petroleum 25%
	P1610	P1610	13/23a	Dana 45%	Summit 25%, Atlantic Petroleum 20%, Trap Oil 10%
	P1655	P1655	15/21g, 15/21a (part)	Premier 28%	Cairn 21%, Serica 21%, Parkmead 12.624%, Faroe Petroleum 8.4%, M aersk 5.736%, Atlantic Petroleum 3.24%
	P1673	P1673	44/28a	Centrica 95%	Atlantic Petroleum 5%
	P1724	P1724	43/13b	Centrica 55%	Viking 35%, Atlantic Petroleum 10%
	P1727	P1727	43/17b,18b	Centrica 55%	Viking 35%, Atlantic Petroleum 10%
	P1734	**	48/8c	Centrica 90%	Atlantic Petroleum 10%
	P1766	P1766	13/22d	Dana 50%	Summit 30%, Atlantic Petroleum 20%
	P1767	P1767	14/9,14a,15		Bridge Energy 70% Atlantic Petroleum 30%
	P1791	P1791	21/30e		Bridge Energy 40% Idemitsu 40%, Atlantic Petroleum 20%
	P1828	P1828	36/23a,24a,27,28,29	Centrica 45%	GdF Suez 45%, Atlantic Petroleum 10%
	P1899	P1899	44/4a,5,45/1	Centrica 45%	GdF Suez 45%, Atlantic Petroleum 10%
	P1906	P1906	47/2b,3g,7a,8d	Centrica 52.5%	Serica 37.5%, Atlantic Petroleum 10%
	P1933	P1933	205/23,24,25,28,29,30	Parkmead 43%	Atlantic Petroleum 43%, Dyas 14%
	P1993	P1993	15/16e	Parkmead 34%	Atlantic Petroleum 33%, Faroe Petroleum 33%
	P2069	P2069	205/12	Parkmead 30%	Atlantic Petroleum 30%, Summit 26%, Dyas 14%
	P2082	P2082	30/12c,13c,18c	Parkmead 30.5%	Atlantic Petroleum 30.5%, Bridge 25%, Dyas 14%
	P2108	P2108	42/21,22a	Centrica 80%	Atlantic Petroleum 20%
	P2112	P2112	43/29a,30b, 44/4b,5a	Centrica 40%	Holywell 40%, Atlantic Petroleum 20%
	P2126	P2126	42/2b,43/3b,42/7,8b,9b	Centrica 45%	GdF Suez 45%, Atlantic Petroleum 10%
o	P2128	P2128	43/12	Centrica 90%	Atlantic Petroleum 10%
rway	PL270	PL270	35/9	VNG Norge 85%	Atlantic Petroleum 15%
	***	PL270B	35/2,3(part)	VNG Norge 85%	Atlantic Petroleum 15%
	****	PL528	6707/8,9,10 (part),11	Centrica 40%	Statoil 35%, Rocksource 25%, Atlantic Petroleum 5-15%
	****	PL528B	6707/10 (part)	Centrica 40%	Statoil 35%, Rocksource 25%, Atlantic Petroleum 5-15%
	PL559	PL559	6608/10, 6008/11	Rocksource 50%	VNG 20%, Explora 10%, Skagen 44 10%, Atlantic Petroleum 10%
	PL704	PL704	6704/12, 6705/10 (part)	Eon 40%	Atlantic Petroleum 30%, Repsol 30%
	PL705	PL705	6705/7(part),8,9,10 (part)	Repsol 40%	Atlantic Petroleum 30%, Eon 30%
	****	PL659	7121/3,7122/1,2,7221/10,12,7222/11,12	Det norske 20%	Petoro 30%, Lundin 20%, Atlantic Petroleum 10%, Tullow 10%, Rocksource 5%, Ithaca 5%
	***	PL763	6606/2,3(part)	Repsol 40%	Atlantic Petroleum 30%, Rocksource 30%
epublic	SEL 2/07	SEL 2/07	part block 49/9		Providence 62.5% Atlantic Petroleum 18.333%, Lansdowne Oil & Gas 10%, Sosina 9.167%
f Ireland			part blocks 50/5,7		Providence 72.5% Atlantic Petroleum 18.333%, Sosina 9.167%
			part block 50/11		Providence 72.5% Atlantic Petroleum 18.333%, Sosina 9.167%
	FEL 3/04	FEL 3/04	44/18,23,24,29,30	ExxonM	obil 25.5% Eni 27.5%, Repsol 25%, Providence 16%, Atlantic Petroleum 4%, Sosina 2%
etherlands E1		E1		Centrica 54%	EBN 40%, Atlantic Petroleum 6%
	E2	E2		Centrica 54%	EBN 40%, Atlantic Petroleum 6%
	E4	E4		Centrica 54%	EBN 40%, Atlantic Petroleum 6%
	E5	E5		Centrica 54%	EBN 40%, Atlantic Petroleum 6%
aro e Islands	L006	L006	6104/16a,21, 6105/25	Statoil 35%	ExxonM obil 49%, OM V 15%, Atlantic Petroleum 1%
	L016	L016	6202/6a,7,8,9,10a,11,12,13,14,15,16,17, 18,21a, 22a,6203/14a,15a,16,17,18,19, 20,21,22, 23,24a,25a	Statoil 30%	DONG 30%, ExxonM obil 26%, OM V 10%, Atlantic Petroleum 4%

** Relinquished January 2014 *** APA award January 2014

**** Farm-in January 2014, subject to approval

Reserves

Atlantic Petroleum contracted Gaffney, Cline & Associates to prepare an independent assessment of the petroleum reserves and resources as of 31st December 2013. The assessment was based on technical data and information provided by Atlantic Petroleum up to that date. (Opening reserves were certified by Fugro Robertson).

The table below shows the proven, contingent and prospective resources, on a working interest basis, as of 31st December 2013, based on P50 estimates. Risks and uncertainties are incorporated into the evaluation of prospective resources.

P50 RESERVES & RESOURCES	Reserves	Contingent Resources	Prospective Resources
	MMBoe	MMBoe	(risked) MMBoe
Start of 2013	5.1	23.1	32.2
Production	-0.7
Net additions & revisions	2.0	-0.2	18.5
End of 2013	6.4*	22.9**	50.7

* Excluding Kells

** Including Kells

P50 remaining reserves have increased significantly from 5.1MMBoe to 6.4MMBoe even excluding Kells. The majority of the increase comes from significant reserve upgrades on Orlando and Chestnut and a minor upgrade on Ettrick. Chestnut reserves actually increased due to the better than expected reservoir performance and FPSO contract extension. Remaining Ettrick reserves increased slightly due to the reserve upgrade partially offsetting production. Blackbird reserves decreased naturally from the production in 2013.

P50 Contingent resources have decreased by a 0.2MMBoe primarily due to revisions by our new CPR provider Gaffney Cline & Associates and relinquishments.

P50 Risked Prospective resources have increased by 18.5MMBoe to 50.7MMBoe due to the inclusion of the prospectivity within the 27th UK Licence Round Blocks awards and new farm-ins.

Production

In 2013, Atlantic Petroleum produced a total of 720,000 boe from the Chestnut, Ettrick and Blackbird fields.

This equates to an average production of 1,973 boepd and is slightly below the latest guidance of 1,986 to 2,191 boepd.

The production in 2013 was heavily affected by shut downs in the Chestnut, Ettrick and Blackbird fields, which resulted in a 2013 production below budgeted production.

Chestnut (15%), Licence P354, Block 22/2a

Chestnut overall produced above expectations, but production was affected by shut downs during 4Q. Despite these shut downs, the field's reserves were upgraded and field life extended by at least a further year. The contract extension comes on the back of significantly better than expected reservoir performance, which indicates that the field will continue to produce at economic rates for at least another year beyond previous expectations. Furthermore, we are confident that Chestnut will continue to produce strongly in the future. Studies are underway to update the existing reservoir models to produce improved forecasts and reserve estimates. It is Atlantic Petroleum's view that the oil initially in place in the Chestnut field could be as much as 70MMBoe, and given a recovery factor based on fields of a similar geologic age, the reserves in the field are likely to increase significantly (14.1MMBoe has been produced to the end of 2013). Further contract extensions on the Hummingbird FPSO are being negotiated along with other long term options for the field.

Ettrick (8.27%) Licences P273 & P317, Blocks 20/2a,3a

A new production well on the Ettrick field was successfully drilled and completed and came on-stream in 4Q 2013, which was slightly behind schedule. The well increases the rate of production in the near term and adds further reserves to the field. Ettrick produced 296,000 boe or 811 boepd in 2013.

Blackbird (9.4%), Licences P273, P317 & P1580, Blocks 20/2a,3a,3f

Blackbird produced 73,000 boe net or 200 boepd in 2013. Field production was relatively stable throughout the year with the field production responding to water injection In December 2013 Atlantic Petroleum announced that DECC had approved the Blackbird Field Development Plan Addendum. The FDP Addendum will result in the drilling of a second production well. The well is planned to be drilled in 2Q 2014 and is expected to be in production by mid-2014. Similar to the Ettrick 20/2a-E9 production well, which came onstream in November 2013, the investment in the Blackbird production well is expected to qualify for the Brown Field Allowance under the UK taxation system.

Development

Orlando (25%), Licence P1606 Block 3/3b

In February 2013, Atlantic Petroleum announced the sanctioning of the Orlando development and completion of the Orlando and Kells acquisition. Atlantic Petroleum, through its fully owned subsidiary Volantis Exploration Limited committed to pro-rata funding of the Orlando & Kells developments commensurate with its 25% working interest. Discussions have been in progress with the operator of the NCP to secure commercial terms for the modifications to the platform for a considerable time. The negotiations are proving to be slower to conclude than expected. DECC is aware of the situation and is assisting in finding a resolution of the outstanding issues. The operator of the Orlando Field continues to push for 2015 first oil however our expectation is that first oil will slip into 2016.

Near Development

Kells (25%), Licence P1607 Block 3/8d

Atlantic Petroleum holds a 25% interest in this licence which contains the Kells discovery. Work is on-going to re-submit an FDP in 2014, with first oil planned in late 2016 or 2017. The plan is to redevelop the field (formerly known as Staffa) as a subsea tie-back to the Ninian Central platform in the Northern North Sea. The expected initial rate from Kells is 2,600 bopd net to Atlantic Petroleum. Field life could extend out to 2025, but the majority of the reserves will be produced in the first 4 years.

Perth (13.35%), Licence P218 & P588 Blocks 15/21a and c

In 2011 and 2012 the then operator, DEO, constructed a development plan using an FPSO to initially develop the Core Perth area. Later in 2012, DEO was acquired by the Parkmead Group who decided to defer the project. In early 2013, the Perth partners had been working towards potentially drilling a well in 2014 to evaluate a region of the field called Core Perth Extension. Later in the year, efforts focused on examining options for a joint field development with the nearby Lowlander discovery. As a result of this, plans for the well were suspended and joint studies are now ongoing to determine the feasibility of a joint Perth/Lowlander development.

Exploration and Appraisal

Faroe Islands

Atlantic Petroleum holds an interest in 2 Faroese licences.

Brugdan Deep (1%), Licence 006, Blocks 6104/16a,21, 6105/25

The 'Brugdan Deep' well was spudded in 2012 targeting a prospect with a resource estimate up to 1 billion barrels. Weather and operational problems resulted in the well being suspended, but the partners have agreed to return to the Brugdan II location in the first half of 2014.

Kúlubøkan (10%), Licence 016, Blocks 6201/1, 2, 6, 6202/4, 5, 6, 7, 8, 9, 10, 11, 12, 13a, 14, 15, 16, 17, 18, 21, 22, 6203/13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25

3D seismic survey was acquired in 2013. The partnership has up to six years from award to decide whether or not to drill an exploration well.

United Kingdom

Atlantic Petroleum by end 2013 holds interests in 29 licences in the UK (by report date 28 licences), which have exploration or appraisal potential. The key activities on the UK licences are described in the following section.

Pegasus (10%), Licence P1724, Block 43/13b

The Pegasus discovery is a fault-bounded anticline with an Intra-Namurian sandstone reservoir. It was successfully drilled in December 2010, and a rig has been contracted to drill an appraisal well on Pegasus West planned for 2Q 2014.

Harmonia & Browney (10%), Licence P1727, Blocks 43/17b & 43/18b

A well will be drilled in 2014 on the Pegasus West structure which extends into this licence. The authorities have agreed that this well, which will be drilled on the adjacent P1724 licence, will fulfil the licence commitment for P1727.

Magnolia (20%), Licence P1767, Blocks 14/9,14a,15

The Magnolia exploration well was completed in March 2013. The well penetrated the prognosed Lower Cretaceous targets, with no hydrocarbons encountered, and was drilled to a depth to fulfil the licence obligations. The well was plugged and abandoned, but work is on-going looking at other potential on the blocks.

Lead B (10%), Licence P1899, Blocks 44/4a, 44/5 & 45/1

This is a 26th Licensing Round licence award and lies next to the Dutch E Block acreage. The Group acquired new 3D data over the licence in 2013.

Greater York Area (10%), Licence P1906, Blocks 47/26, 47/3g, 47/7a & 47/8

These blocks lie adjacent to the Centrica operated York field which came on stream in March 2013. A 3D seimsic survey was acquired in 2013.

UK 27th Round Awards

On 29 th November 2013, the Company anounced that it had been offered the award of a further four licences in the 27th UKCS Licensing Round.

The licence details of the four new licences are as follows:

P2126, Blocks 42/2 (split), 42/3 (split), 42/7, 42/8b, 42/9b and 43/3b. Centrica Resources Limited (Operator) 45%, Atlantic Petroleum UK Limited 10%, and GDF Suez E&P Ltd 45%

• P2108, Blocks 42/21 and 42/22 (split). Centrica Resources Limited (Operator) 90% and Atlantic Petroleum UK Limited 10%
• P2128, Block 43/12. Centrica Resources Limited (Operator) 90% and Atlantic Petroleum UK Limited 10%
• P2112, Blocks 43/29 (part), 43/30b (part), 48/4b (part), 48/5 (part) Centrica Resources Limited (Operator) 40%, Atlantic Petroleum UK Limited 20% and Holywell Resources Limited 40%

These four licences together with the four licences awarded in 2012 in the first tranche bring the total 27th Round awards to eight. Atlantic Petroleum applied for nine licences in total.

Ireland

Atlantic Petroleum holds two licences in Ireland.

Licence SEL 2/07(18.33/13.75%), Part Blocks 50/6, 7, 11, 49/9, 13, 14, 18 & 19

The licence group is in the process of application with the PAD to convert the licence into a Licence Undertaking where development options will be studied. In November 2013 it was announced that the joint venture had agreed a phased farm-in by ABT Oil & Gas into the Helvick and Dunmore oil discoveries. Under the agreed terms of the farm-in ABT Oil & Gas will carry out a work programme which will include an assessment of commerciality and, as appropriate, submission of plans for field development to first oil, using ABT Oil & Gas' low cost development solutions. Upon completion of agreed work programme ABT Oil & Gas will earn a 50% interest in the discoveries.

Dunquin (4%), Licence FEL 3/04, Blocks 44/18, 44/23, 44/24, 44/29 and 44/30

Dunquin North well was spudded in April 2013. It was plugged and abandoned in July 2013. The well has indicated a working hydrocarbon system, which is positive for the surrounding area, including the Dunquin South prospect. Post well evaluation is ongoing.

Netherlands

Blocks E1, E2, E4 & E5 (6%)

The licences are operated by Centrica and lie adjacent to UK/Netherlands border in approximately 35 - 40m of water. The area is also adjacent to UKCS Licence P1899, awarded in December 2012 to Atlantic Petroleum, Centrica and GdF Suez in the UKCS 26th Round. The licence group is in the process of applying for licence extensions, to allow more time to evaluate them.

Norway

Atlantic Petroleum at year end date holds interests in 4 licences on the Norwegian Continental Shelf, which have exploration or appraisal potential. Further a 10% ownership in PL 659 is subject to government approval, as well as an option to farm in to PL 528 and PL 528B with at least 5 and maximum 15% ownership (also subject to government approval). In January 2014 Atlantic Petroleum was awarded two APA licences, PL 270B and PL 763. Subject to government approval of PL 528, PL 528B and PL 659 Atlantic Petroleum Norge AS will hold 9 licences.

Turitella/Agat (15%), Licence PL270, Block 35/3

PL 270 was acquired in December 2012. The licence is located in the North Sea 50 km North of the Gjøa field and c. 50 km offshore the western coast of Norway. The work program in the licence is fulfilled. Three gas discovery wells have been drilled within the current licence boundaries. New data are currently being evaluated.

Gjallar South (30%), Licence PL 704, Blocks 6704/12 & 6705/10 (part)

PL 704 was awarded in the 22nd Licensing Round on the Norwegian Continental Shelf (NCS). The licence contains multiple high potential prospects and given a discovery the reserves could be tied in to the Aasta Hansteen Field. Licence PL 704 is located immediately south of PL 705, and immediately west of the Asterix discovery, and covers an area of 646 km2. Prospectivity is mapped on 2D and 3D seismic data within several geological play models.

Gjallar North (30%), Licence PL 705, Blocks 6705/7 (part),8,9,10 (part)

PL 705 was awarded in the 22nd Licensing Round on the Norwegian Continental Shelf (NCS). The licence contains multiple high potential prospects and given a discovery the reserves could be tied in to the Aasta Hansteen Field. The licence is located on the northern part of the Gjallar Ridge in the Vøring Basin (Norwegian Sea), immediately north of PL 704 the Asterix discovery and south west of the Naglfar Discovery. The licence covers an area of 1039 km2, and several prospects have been mapped and derisked using 3D seismic data. The prospects have potential targets at multiple reservoir levels.

Langlitinden (10% subject to government approval), Licence PL 659, Blocks/part blocks 7121/3, 7122/1,2, 7221/10,12, 7222/11,12

PL 659 was awarded in February 2012 (APA 2011) with a firm well + 3D seismic commitment. The well commitment will be fulfilled with the drilling of 7222/11-2 Langlitinden with spud January 2014. The licence consists of 7 blocks/part blocks and covers 1,462 sqkm. PL 659 includes an oil and gas discovery made in 2008 and later relinquished (7222/11-1, Caurus).

Ivory (5-15% subject to realization of option and government approval), Licence PL 528, Blocks 6707/8, 6707/9, 6707/11, 6707/10 (part)

In 2013 the Company entered into a farm-in option agreement with Rocksource ASA regarding the PL 528 licence in the Norwegian Sea. Through the farm-in option agreement, Atlantic Petroleum shall purchase five percent and has an option to purchase up to fifteen percent of the participating interest in PL 528. Atlantic Petroleum shall within 28th April 2014 decide, in its sole discretion, the size of the participating interest to be acquired within the aforementioned 5 to 15 percent range. The PL 528 licence contains the Ivory prospect sanctioned for drilling in late 2014.

Risk Management

As a participant in the upstream oil and gas industry, Atlantic Petroleum is exposed to a wide range of risks in the conduct of its operations. The risks can be internal as well as external in nature. Management of the risks facing the Group is anchored in a risk management system. The most significant risks and mitigation plans are consolidated into a key risk overview. The key risks facing the Group are discussed with the Group's Executive Board on a regular basis.

Atlantic Petroleum is exposed to a number of different market and operational risks arising from core business activities. The Group is also exposed to external risk.

Market risks include changes in oil and natural gas prices, currency exchange rates and interest rates. The changes can affect the value of the assets, liabilities and future cash flows.

Commodity prices

Short term volatility in oil prices is a risk facing the Group and can have a significant impact on the Group´s cash flow. In order to mitigate short term oil price volatility the Group engaged in oil price hedging. In 2013 with a total of 23% of annual production hedged. The Company did not engage in other commodity hedging.

Oil price hedging continues in 2014 and the Group will lock-in oil price for a proportion of expected future production in order to provide a sensible downside protection ensuring the operational and capital expenditure program are adequately funded.

Currently in 2014 32% of expected oil production is hedged at an average oil price of USD 104.9/bbl.

Foreign currency

The Group reports in DKK, which means exchange rate exposure related to USD, GBP, NOK and EUR. Operational currency risks relate to oil sales, gas sales and operating costs. On the investment side, the Group is also exposed to fluctuations in USD, GBP, NOK and EUR exchange rates as the Group's most material investments in oil and gas assets are made in these currencies.

The Group has not yet engaged in currency hedging on cash flows but has this under review.

Credit risk

Atlantic Petroleum has a significant balance deposited in short-term bank accounts in USD, GBP, NOK and DKK. There is a currency and a credit risk attached to these cash balances (bank deposits).

Operational risk

Through its core business Atlantic Petroleum is exposed to operational risk including the possibility that the Group may experience, among other things, a loss in oil and gas production or an offshore catastrophe. The Company works with and monitors operators and partners to ensure that HSE and asset integrity are given the highest priority. The Group also has an insurance programme in place to cover the potential impact of any catastrophic events.

Atlantic Petroleum operates in the Faroe Islands, United Kingdom, the Republic of Ireland, the Netherlands and Norway and the political climate in these countries is perceived as being stable.

Insurance

The Group has in place a significant insurance package covering equipment, subsurface facilities and operation. In addition the Group has insurance cover on offshore pollution and third party liability. The insurance package also includes business interruption coverage, covering a proportion of the cash flow arising from the producing fields. Atlantic Petroleum has in addition an insurance covering office and staff.

The Group is confident that its insurance policies cover the overall insurance requirement and provides insurance cover for the Group's general and standard risk exposure in relation to property damage, personal injury and liability.

Going concern

Over the last years Atlantic Petroleum has strengthened its financial position and the Group is committed to monitor its cash and capital position regularly throughout the year to ensure that it has sufficient funds to meet cash requirements. Sensitivities are run to reflect latest development of income and expenditures in order to avoid risk of shortfall of funds or covenant breaches to ensure the Group´s ability to continue as a going concern.

Corporate Social Responsibility

Corporate Social Responsibility (CSR) Policy

Atlantic Petroleum's culture and operating activities are conducted with a high priority for ethical standards. Being a responsible company in all of our operations is an integral part of Atlantic Petroleum and we continue to implement high ethical and practical standards in all our activities.

Atlantic Petroleum is committed to the review and continuous improvement of corporate social responsibility and environment, health and safety performance. To meet these commitments, we will operate in accordance with the following principles:

• Conduct our business activity in compliance with the law.
• Act openly and honestly in business dealings.
• Comply with best practice in our corporate governance.
• Behave responsibly and with sensitivity to local communities in all areas where we operate.
• Provide sustainable benefits and avoid the creation of a dependency culture.
• Integrate CSR and EHS responsibility throughout our activities.
• Recognise that all parties working on Atlantic Petroleum's behalf can impact our operation and reputation and that we all share a common responsibility.
• Ensure, wherever possible, that our partners' approach to CSR is compliant with our own standards.
• Monitor and review our CSR and EHS policies and procedures as appropriate to ensure suitability and effectiveness.
• Use continuous assessment to ensure our CSR activities meet identified performance objectives.

Environment, Health and Safety (EHS) Policy

Atlantic Petroleum's activities are undertaken with integrity, responsibility and respect for the environment and the community in which these activities take place. This entails conducting operations in an ethically and practically sound manner that minimises risks and places high priority on the safety of those involved in Atlantic Petroleum's oil and gas operations.

Atlantic Petroleum is committed to:

• Comply with all applicable Environment, Health and Safety (EHS) laws, regulations and standards and to apply responsible standards where legislation is inadequate or does not exist.
• A systematic framework of hazard identification and risk assessment through which safe operations can be managed.
• Develop effective EHS management systems to identify and manage risks associated with its activities by focusing on risk avoidance and prevention.

• Establish accountability and responsibility for EHS within organisational line management.

• Provide training, equipment and facilities necessary to maintain a safe and healthy worksite.

• Practice pollution prevention and seek viable ways to minimize the environmental impact of operations, reduce waste, conserve resources and respect biodiversity.
• Protect and minimise any harm to the environment in our oil and gas activities, and continuously focus on improving our environmental procedures.
• Monitor and review our CSR and EHS policies and procedures as appropriate to ensure suitability and effectiveness.
• Ensure that partners and contractors' policies and activities are compliant with our own standards, and recognise that all working on our behalf can impact our operation and reputation and that we all share a common responsibility for our safety.

Shareholder Information

Information to shareholders has high priority at Atlantic Petroleum. Therefore, Atlantic Petroleum aims to maintain a regular dialogue with the shareholders through the formal channel of stock exchange announcements, interim reports, annual reports, Annual General Meetings and presentations to investors and analysts.

Board of Directors

Birgir Durhuus, Chairman Jan E Evensen, Deputy Chairman Barbara Y Holm Diana Leo David A MacFarlane

Management

Ben Arabo, CEO, Mourits Joensen, CFO Nigel Thorpe, Business Development Director Wayne J Kirk, Technical Director Jonny Hesthammer, Managing Director Atlantic Petroleum Norge AS

At year end 2013 Atlantic Petroleum was listed on NASDAQ OMX Copenhagen, NASDAQ OMX Iceland and on Oslo Stock Exchange. In February 2014 Atlantic Petroleum was officially delisted from NASDAQ OMX Iceland. Following the delisting the primary listing is on NASDAQ OMX Copenhagen. Trading in Atlantic Petroleum shares can be done by contacting:

• Members of NASDAQ OMX Copenhagen
• Members of Oslo Stock Exchange
• A stockbroker or a financial institution

NASDAQ OMX ticker:	FO-ATLA CSE
OSLO:	ATLA
Bloomberg ticker:	ATLA IR
Reuters ticker:	FOATLA.IC

Financial calendar

14th March 2014:	2013 Annual Financial Statement
th April 9 2014:	Annual General Meeting
21st May 2014:	st Quarter 2014 Interim Financial Statement 1
27th August 2014:	nd Quarter 2014 Interim Financial Statement 2
12th November 2014:	rd Quarter 2014 Interim Financial Statement 3

Share price 2013

Following the delisting from NASDAQ OMX Iceland in February 2014 P/F Atlantic Petroleum is main listed on NASDAQ OMX Copenhagen and from mid December 2013 second-listed on Oslo Stock Exchange. The performance of Atlantic Petroleum's shares on NASDAQ OMX Copenhagen in 2013 is shown in the figure below:

The year 2013 started with a share price of DKK 184. Highest share price was in early January when the shares were sold for DKK 194.50. The share price has trended downwards throughout the year. Following the equity raise in December the price dropped to DKK 124 tracking the equity offering price which was NOK 140. The closing price at year end was DKK 129, a decrease of 30% compared to the beginning of the year.

The volumes of shares traded on NASDAQ OMX Copenhagen in 2013 were higher than the previous year, specifically in the December the volume of shares traded soared due to the equity raise.

Compliance Officer

The Compliance Officer for Atlantic Petroleum continuously ensures that relevant persons observe the Group's rules on trading Atlantic Petroleum's shares. The Parent Company's Board of Directors appoints the Compliance Officer, including his or her deputy. The Compliance Officer's responsibility is to monitor adherence to the Group's internal rules.

The Compliance Officer also ensures that the duty of information in relation to the rules of the NASDAQ OMX Copenhagen, NASDAQ OMX Iceland (delisted in February 2014) and Oslo Stock Exchange on the handling of insider information and insider transactions are followed through. The current Compliance Officer is Mary-Ann Thomsen. Deputy Compliance Officer is Mourits Joensen.

Contact

Further information about the Group is available on Atlantic Petroleum's website www.petroleum.fo.

Please address enquiries related to the stock market and investor relations to:

Atlantic Petroleum Tel.: + 298 350100 Fax: + 298 350101 E-mail: petroleum@petroleum.fo

Auditors

The consolidated accounts for 2013 have been audited by JANUAR State Authorised Public Accountants P/F. The financial statements of the subsidiary companies for the year ended 31st December 2013, Atlantic Petroleum UK and Volantis Exploration are audited by Ernst & Young in Aberdeen and Atlantic Petroleum (Ireland), for the year ended 31st December 2013, is audited by KPMG in Dublin. Volantis Netherlands B.V. for year end 31st December 2013 will be audited by Ernst & Young in Netherlands. Atlantic Petroleum Norge AS is audited by Ernst & Young Norway.

Results and Dividends

The Group's result after taxation for the year amounted to a loss of DKK 25.7MM (2012: Profit of DKK 66.7MM). Payment of a dividend is not proposed.

The Company´s investments will be allocated towards existing licences, as well as on farm-ins to new licences and acquisitions by utilising free cash flow. The Company is seeking to deliver future share price growth for shareholders through exploration success.

Shareholders Capital and Vote

In December 2013 Atlantic Petroleum completed a public share emission and increased the holding with 1,050,000 new shares. By year end 2013 Atlantic Petroleum's nominal share capital amounted to DKK 367,670,300 consisting of 3,676,703 shares each with a nominal value of DKK 100.

In January 2014 Carnegie AS exercised the Over-Allotment Right to subscribe for 21,157 new shares in Atlantic Petroleum. The issued share capital in Atlantic Petroleum following the share issue is DKK 369,786,000 consisting of 3,697,860 fully paid shares, each with a nominal value of DKK 100.

Each share holds one vote and all shares have the same rights. For more details, please refer to the articles of associations of the Parent Company which can be found on the Company's website www.petroleum.fo.

Dematerialisation of paper shares

In October 2005, Atlantic Petroleum commenced dematerialisation of paper shares. All shares issued before 2004 (paper shares) have been called in for electronic registration. As at 31st December 2013, there were paper shares in issue with the nominal value of DKK 669,500. The process to convert the shares into electronic registration will continue in 2014.

Distribution of Share capital

By year end 2013 Atlantic Petroleum had around 9,000 shareholders representing more than 30 countries. The majority of the share capital was represented by Danish, Faroese and Norwegian investors.

The geographical distribution of share capital, and the distribution between private and institutional sharecapital as at 31st December 2013 are shown in the figures below.

Substantial Shareholders

At 31st December 2013, the following shareholders are listed according to §28 b in the Companies Act:

TF Holding Group:

P/F Eik Banki & P/F TF Íløgur

The listed shareholder above holds interests in excess of 5% of the issued ordinary share capital of the Parent Company.

Director Profiles

Birgir Durhuus Chairman of the Board of P/F Atlantic Petroleum

Date and year of birth: 10th September 1963

Primary occupation: Head of External Solutions & Risk Management at Danske Capital

Principal work experience: 24 years of managerial experience from the financial sector in Denmark

First elected to the Board: 3 rd July 2009

Expiry of current term: AGM 2014

Current key offices: Atlantic Petroleum: Remuneration Committee

Jan E Evensen Deputy Chairman of the Board of P/F Atlantic Petroleum

Date and year of birth: 5 th May 1951

Primary occupation: Chief Technical Officer at Rock Energy AS

Principal work experience: 37 years international career within the oil and gas industry

First elected to the Board: 3 rd July 2009

Expiry of current term: AGM 2014

Current key offices: Partner, MD and Board member of MoVa AS, COB of Kviknehytta AS, and CTO/COB of Rock Energy AS. Owner and COB of Evenco AS. Non Executive director of Atlantic Petroleum UK Ltd, Atlantic Petroleum (Ireland) Ltd, Volantis Exploration Ltd, Atlantic Petroleum Norge AS.

Diana Leo Boardmember of P/F Atlantic Petroleum

Date and year of birth: 3 rd June 1966

Primary occupation: Head of Operations & Facilities (Director) at DONG Energy E&P

Principal work experience: 19 years of experience as a production engineer within the oil and gas industry

First elected to the Board: 3 rd July 2009

Expiry of current term: AGM 2014

Current key offices: None

David A MacFarlane Boardmember of P/F Atlantic Petroleum

Date and year of birth: 3 rd February 1957

Primary occupation: Chartered Accountant / Company Director

Principal work experience: More than 30 years experience in financial control & management in the upstream oil and gas business

First elected to the Board: 19th March 2011

Expiry of current term: AGM 2014

Current key offices:

Atlantic Petroleum: Chairman, Audit & Remuneration Committee; Trinity Exploration & Production plc (London AIM): Chairman, Audit Committee and member of Remuneration Committee; Energy Assets Group plc (London): Chairman Audit Committee and member of Remuneration Committee, Senior Independent Director; Kentz Corporation Limited (London): Member of Audit Committee.

Barbara Y Holm Boardmember of P/F Atlantic Petroleum

Date and year of birth: 15th April 1966

Primary occupation: Oil & gas professional / Company Director

Principal work experience: Over 15 years of commercial and financial experience in the global E&P industry

First elected to the Board: 12th April 2013

Expiry of current term: AGM 2014

Current key offices: None.

As a matter of Corporate Governance the independence of the directors is evaluated yearly.

All of the Board members are independent of the Company.

The Directors whose current term expires at the Annual General Meeting 2014 are Mr Birgir Durhuus, Jan E Evensen, Barbara Y Holm, Diana Leo, and David MacFarlane.

Board Meetings

In 2013, the Board of P/F Atlantic Petroleum held 11 board meetings, including tele meetings.

Management Profiles

CEO Ben Arabo CEO of the Atlantic Petroleum Group

Date and year of birth: 1 st September 1973

Primary occupation: CEO of the Atlantic Petroleum Group

Principal work experience:

Exploration Business Manager for Hess in South East Asia. Management committee member for Hess in exploration ventures in Asia, North Africa and North West Europe. Branch manager of Hess' activities on the Faroe Islands

Joined Atlantic Petroleum: August 2010

Current key offices:

Executive Director of Atlantic Petroleum UK Ltd, Atlantic Petroleum (Ireland) Ltd, Volantis Exploration Ltd and Chairman of Atlantic Petroleum Norge AS. Non Executive Director of P/F Eik Banki

CFO Mourits Joensen CFO of the Atlantic Petroleum Group

Date and year of birth: 17th April 1974

Primary occupation: CFO of the Atlantic Petroleum Group

Principal work experience:

Has held the position as Finance and Administration Manager of the Faroese Employment Service Fund, and prior to that he worked with Eik Bank and Hagstova Føroya (Statistics Faroe Islands)

Joined Atlantic Petroleum: March 2010

Current key offices: None

TECHNICAL DIRECTOR Wayne J Kirk Technical Director of the Atlantic Petroleum Group

Date and year of birth: 4 th May 1965

Primary occupation:

Technical Director of P/F Atlantic Petroleum, Atlantic Petroleum UK Ltd, Atlantic Petroleum (Ireland) Ltd and Volantis Exploration Ltd

Principal work experience:

Over 20 years exploration, development and production experience in the North Sea, West of Shetlands, Brazil and New Zealand

Joined Atlantic Petroleum: December 2011

Current key offices:

Executive Director of Atlantic Petroleum UK Ltd, Atlantic Petroleum (Ireland) Ltd , Volantis Exploration Ltd and Volantis Netherlands BV.

BUSINESS DEVELOPMENT DIRECTOR Nigel Thorpe

Business Development Director of the Atlantic Petroleum Group

Date and year of birth: 18th August 1956

Primary occupation:

Business Development Director of P/F Atlantic Petroleum, Atlantic Petroleum UK Ltd, Atlantic Petroleum (Ireland) Ltd and Volantis Exploration Ltd

Principal work experience:

Mr Thorpe has more than 30 years international E&P experience. He previously held positions as CEO of Volantis Exploration Ltd, COO of a private Malaysian E&P Company and MD of Eni Lasmo Indonesia

Joined Atlantic Petroleum:

June 2011

Current key offices:

Executive Director of Atlantic Petroleum UK Ltd, Atlantic Petroleum (Ireland) Ltd, Volantis Exploration Ltd, Volantis Netherlands BV and Atlantic Petroleum Norge AS

MANAGING DIRECTOR Jonny Hesthammer

Managing Director of Atlantic Petroleum Norge AS

Date and year of birth:

7 th March 1965

Primary occupation:

Managing Director Atlantic Petroleum Norge AS

Principal work experience:

More than 20 years petroleum industry experience in Norway and internationally. Previously held positions as CEO of Emergy Exploration AS, geoscientist and manager in Statoil (Norway), geologist in Husky Oil (Canada), CTO in Rocksource Geotech (Norway) and professor at the University of Bergen (Norway).

Joined Atlantic Petroleum: December 2012

Current key offices:

MD Atlantic Exploration Norge AS. Prof. II at the University of Bergen, Norway. Chairman of the Board of GeoContrast AS and Jonny Hesthammer AS.

Directors' Interests and Remuneration

Beneficial interests of the Board of Directors holding office at the year-end, related parties and indirect holdings of the Group are set out below:

Board of Directors	Position	Number of Shares	Related Parties	Holdings	Indirect Remuneration Remuneration 2013	2012
Birgir Durhuus	Chairman of the Board	4.768	0	0	480.000	441.000
Jan E Evensen	Deputy Chairman	0	0	2.554	360.000	330.750
Diana Leo	Board Member	1.250	0	0	240.000	220.500
David A MacFarlane	Board Member	357	0	0	360.000	305.262
Poul Mohr *	Board Member	1.346	233	0	68.000	220.500
Barbara Y Holm**	Board Member	0	0	0	172.000	0
Total		7.721	233	2.554	1.680.000	1.518.012
** Barbara Y Holm w	* Poul R Mohr resigned from the Board at the AGM on 12th April 2013 as elected to the Board at the AGM on 12th April 2013

The Board of Directors do not receive any share related compensation from the Group.

CEO's Interests and Remuneration

Beneficial interests of the CEO holding office at the year-end, related parties and indirect holdings of the Group are set out below:

					Salary incl.		Share based				Value of Value of
Management	Position		Number Related	Indirect	pension	Bonus		payment Remuneration Remuneration		LTIP	LTIP
The Group		of Shares		parties Holdings	2013	2013	in bonus 2013	2013	2012	2013	2012
Ben Arabo	CEO	1,521	10	1,404	1,941,662	352,000	0	2,293,662	2,628,375	734,497	418,395

In addition to the remuneration to the CEO total benefits add up to DKK 5.300.

Stock Exchange Announcements 2013 – (most recent first)

No Date Subject

59/13	19th December	Atlantic Petroleum announces farm-in to Norwegian Licence PL659
58/13	12th December	Change of Primary Listing Exchange
57/13	12th December	Reissued 2014 Financial Calendar
56/13	12th December	Stabilisation and over-allotment notice
55/13	11th December	Registration of capital increase completed
54/13	10th December	Director's dealings
53/13	10th December	Successful completion of the Initial Public Offering on Oslo Børs
52/13	th December 6	Blackbird Field Development Plan Addendum approved
51/13	th December 4	The Board of Oslo Børs approves P/F Atlantic Petroleum for listing on Oslo Børs ASA
50/13	nd December 2	Operations update November 2013
49/13	29th November	Further four licences offered for award in the UK 27th Round
48/13	26th November	P/F Atlantic Petroleum Prospectus 26th November 2013
47/13	26th November	Atlantic Petroleum publishes Prospectus and launches Initial Public Offering
46/13	22nd November	Chestnut production temporarily suspended. Resumptio expected in early December
45/13	13th November	Atlantic Petroleum prepares listing on the Oslo Stock Exchange
44/13	13th November	Gross profit of DKK 78.3MM in 3Q 2013
43/13	13th November	Expected de-listing on NASDAQ OMX Iceland
42/13	13th November	ABT Oil & Gas Farms into Helvick & Dunmore Oil Discoveries
41/13	11th November	Webcast 13th November 2013
40/13	th November 4	Operations update October 2013
39/13	th November 4	Revised 2013 and issue of 2014 Financial Calendar of Atlantic Petroleum
38/13	nd October 2	Operations update September 2013
37/13	th September 9	Chestunut reserves upgrade and field life extended for another year
36/13	nd September 2	Operations update August 2013
35/13	28th August	Gross profit of DKK 90.8MM 1H 2013
34/13	20th August	Live webcast/Conference call 28th August 2013
33/13	st August 1	Operations update July 2013
32/13	22nd July	Drilling activities now completed on the 44/23-1 Dunquin North
31/13	st July 1	Operations update June 2013
30/13	26th June	Director's dealings
29/13	12th June	Successful 22nd Round award for Atlantic Petroleum
28/13	th June 4	Brugdan 2 update
27/13	rd June 3	Exxon Mobile Farms in to Atlantic Petroleum's Interest in Faroes Block
26/13	rd June 3	Operations update May 2013
25/13	29th May	Gross profit of DKK 54.2MM 1Q 2013
24/13	28th May	Live webcast/Conference call 29th May 2013
23/13	21st May	Acquisition of High Impact Exploration Opportunity
22/13	th May 6	Ettrick Field Development Plan Addendum approved
21/13	st May 1	Operation update April 2013
20/13	29th April	Grant of Options
19/13	17th April	Orlando Field Development Plan approved
18/13	12th April	Result of Annual General Meeting 12th April 2013
17/13	11th April	Director's and related party dealings
1613	th April 9	Director's dealings
15/13	th April 9	Transaction of own shares
14/13	th April 8	Director's related party dealings
13/13	nd April 2	Operations update March 2013
12/13	26th March	Director's dealings
11/13	20th March	Summons for the Annual General Meeting of P/F Atlantic Petroleum
10/13	20th March	Drilling now completed on the 13/23a-7 Magnoliga exploration well on UK Licence P1610
09/13	15th March	Director's dealings
08/13	15th March	A record breaking year for Atlantic Petroleum in 2012
07/13	14th March	Live webcast/Conference call 15th March 2013
06/13	th March 7	NOK 300MM Credit Facility for Norwegian Exploration and Appraisal
05/13	th March 4	Operations update February 2013
04/13	25th February	Driling commences on the 13/23a-7 Magnolia exploration well on UK
03/13	20th February st February	Atlantic Petroleum Sanctions the Orlando Development and completes the Orland & Kells acquisition
02/13	1 rd January	Operations update January 2013
01/13	3	Operations update December 2012

Please refer to www.petroleum.fo where the announcements to the stock exchanges can be read in full.

CORPORATE GOVERNANCE REPORT

As a Faroese registered company listed on NASDAQ OMX Copenhagen, NASDAQ OMX Iceland (delisted in February 2014) and on Oslo Stock Exchange, Atlantic Petroleum is obliged to comply with Faroese, Danish, Icelandic and Norwegian securities law and stock exchange rules. The stock exchange rules require listed companies to take a position on corporate governance recommendations on a "comply or explain" basis. As a dual listed company, Atlantic Petroleum has chosen to base the corporate governance policy on the highest standard and thus follows both the recommendations on NASDAQ OMX Copenhagen, NASDAQ OMX Iceland and Oslo Stock Exchange, with the exemptions summarised below: Atlantic Petroleum has reviewed and implemented recent changes and recommendations on Corporate Governance.

A summary of Atlantic Petroleum's non-compliance procedure and recommendations are stated below. Further information is available on the Company's website, www.petroleum.fo

Openness and Transparency

Information and publication of information:

Because of the Group's international operations, all information is published in English and, where required, Faroese.

Retirement Age

The Supervisory Board has not found it necessary to lay down a retirement age for the Supervisory Board members. The annual report contains information about the age of the Supervisory Board members.

Election Period

The members of the Supervisory Board are elected for 1 year at a time. Re-election is allowed. For the time being there is no limit of how often Board members can be re-elected.

REMUNERATION OF THE MEMBERS OF THE SUPERVISORY BOARD AND THE EXECUTIVE BOARD:

Remuneration Policy

Remuneration to the members of the Supervisory Board and the Executive Board is on the same level as comparable companies in order to attract, retain and motivate the members of the Supervisory Board.

Remuneration Policy for Senior Executives of Atlantic Petroleum

Overall Aim

The aim of Atlantic Petroleum's (the "Company") Remuneration Policy for senior executives is to provide a reward framework which ensures that key executives are appropriately attracted, retained and motivated and which is fit for purpose in the markets in which the Company operates and where it and its peer groups are listed.

Remuneration Strategy

The Company's remuneration strategy is to provide a competitive remuneration package which rewards Directors and employees fairly and responsibly for their contributions and aims to deliver superior remuneration for superior performance.

The total reward package will consist of elements such as Salary, Annual Performance Bonuses, Long Term Incentives and Pension Contributions and Other Benefits.

The guiding principles behind the setting and implementation of this policy are that:

Balanced

There should be an appropriate balance between fixed and performance-related elements and the provision of equity over the longer-term and which focuses executives on delivering the business strategy;

Competitive

Remuneration packages should be sufficiently competitive taking into account the level of remuneration paid in respect of comparable positions in similar companies within the industry;

Equitable

There should be an appropriate level of gearing in the package to ensure that executives receive an appropriate proportion of the value created for shareholders while taking into account pay and conditions throughout the remainder of the group and where the Company operates and is listed;

Risk-weighted

Remuneration should not raise environmental, social or governance risks by inadvertently motivating irresponsible behaviour. More generally, the overall remuneration policy should not encourage inappropriate operational risk; and

Aligned

Executives will be encouraged to build a meaningful holding in the Company to further align their interests with those of shareholders.

The Remuneration Committee will review on an annual basis whether its remuneration policy remains appropriate for the relevant financial year. Factors taken into account by the Remuneration Committee will include:

• overall corporate performance;
• market conditions affecting the Company;
• the recruitment market in the Company's sector;
• changing market practice; and
• changing views of institutional shareholders and their representative bodies.

Base Salary

The Remuneration Committee's policy is to provide a lower quartile salary relative to an appropriate benchmark on appointment to the Board which based on appropriate levels of individual and corporate performance will be increased to the median position with experience gained over time. Any subsequent salary increases when an individual has attained the median benchmark will take into account factors such as:

• the levels of base salary for similar positions with comparable status, responsibility and skills, in organisations of broadly similar size and complexity in the E&P sector;
• the performance of the individual; and
• pay and conditions throughout the Company.

Annual Performance Bonus

Senior executives will participate in an annual bonus arrangement which focuses on the delivery of the shortterm business/strategic objectives across the following key areas:

• exploration/production targets;
• operational milestones;
• financial management and performance; and
• personal objectives

In addition to ensure affordability of any bonus, a pre-determined level of EBITDAX must be achieved before any funding is made available. These targets will be set by the Remuneration Committee each year.

The maximum bonus opportunity for key executives will be set at a rate competitive to the market – however, maximum bonus pay-out will only be earned by executives for achieving exceptional levels of performance. Mr. Ben Arabo's maximum cash bonus target is 100% of his base salary.

The structure of any bonuses paid to the CEO and other key executives will be as follows:

• any bonus of up to 25% of salary will be payable immediately in cash;
• 50% of the balance of any bonus earned above 25% of salary must be deferred in shares which will vest at the end of a two year holding period. An individual may also elect to further defer up to an additional 25% of salary, from the remaining cash element of the bonus into Company shares; and
• deferred shares which vest will be matched on a one for one basis provided that the Company's share price has not fallen over the two year holding period and there is continuity of employment.

For all other employees any bonus earned will be paid in cash or shares at the discretion of the Remuneration Committee.

Long Term Incentive Plans

The Remuneration Committee believes that a key component of the remuneration package is the provision of equity awards to senior executives through the Long-Term Incentive Plan ("LTIP") to ensure that:

• key executives become meaningful shareholders of the Company and share in its success;
• it aligns the interests of shareholders and those of executives;
• it develops a culture which encourages strong corporate performance both on an absolute and relative basis; and
• total remuneration levels are highly attractive and competitive against the market

Share Based Payments

Nil-cost options over ordinary shares in the Company were granted to members of management and senior staff under the Atlantic Petroleum Long Term Incentive Plan (LTIP).

The options are capable of vesting after a three year period subject to continued employment and meeting stretching corporate performance conditions.

The LTIP awards form part of the Company's remuneration strategy to provide a competitive remuneration package that rewards Directors and employees fairly and responsibly for their contributions and aims to deliver superior remuneration for superior performance, whilst maintaining alignment with shareholder's interests.

We set out the two corporate performance conditions below:

Comparative Total Shareholder Return ("TSR"):

The Company's comparative TSR is compared to a comparator group of 24 quoted oil and gas exploration and production companies and;

25% of the option will vest for median performance against the comparator group;

100% of the option will vest for upper quartile performance against the comparator group; and

The option will vest on a straight-line basis for TSR performance between these levels.

Share price multiplier:

The vesting level achieved under the comparative TSR element can be multiplied upwards if the Company achieves absolute share price growth of more than 15% p.a. over the three year performance period. A maximum multiplier of three times can be achieved for 45% p.a. absolute share price growth and awards vest on a straight-line basis between these share price performance levels.

The options awarded in 2012 and 2013 to the participants are as follows:

Issued to		Number of plan shares
Year:	2012	2013
Ben Arabo, CEO	8,849	5,871
Members of Management & Senior Employees	13,503	15,935

The options are capable of vesting after a three year period subject to continued employment and meeting stretching corporate performance conditions.

For the CEO, Ben Arabo, the options granted in 2013 were equal to 67% of the annual base salary and the options granted in 2012 were equal to 100% of the annual base salary.

The option was calculated by reference to a price of DKK 171.2 per share, being the three month average closing share price of the Company's shares to 25th April 2013 on NASDAQ OMX Copenhagen. The option in 2012 was calculated by references to a price of DKK 169.5 per share, being the closing share price of the Company's shares the 23rd March 2012 on the NASDAQ OMX Copenhagen. The number of shares shown above represents the figure that may be acquired by the participants, if the Group's TSR is in the upper quartile TSR of its comparator group.

Where the Company's absolute share price growth is 45% p.a. or more over the performance period, the participants would be entitled to exercise their option in respect of three times as many shares as stated above.

Additional Benefits

In addition to salary, annual bonus and the long-term incentives, the Company, where appropriate will also provide a pension contribution and other competitive benefits.

A competitive level of pension contributions (or cash equivalent) and other ancillary benefits will be provided for all senior executives in line with market rates.

Shareholding Guidelines

The Remuneration Committee has established formal shareholding guidelines that will encourage the CEO and other participants of long-term incentive plan to retain no less than 50% of the net of tax value of awards vesting under the company's annual bonus and long-term incentive arrangements, until such time as they have achieved a holding worth 100 per cent of salary in the case of the CEO and 50 per cent of salary for other participants. Adherence to these guidelines is a condition of continued participation in the long-term incentive arrangements. This policy ensures that the interests of executives and those of shareholders are closely aligned.

Non-Executive Directors Fees

The Non-Executive Director ("NED") fees will be structured as follows:

• A base fee will be paid for carrying out day to day duties as an NED; and
• Additional fees will be provided for extra responsibilities, for example chairing the Audit, Nominations or Remuneration committees.

Fees should be sufficiently competitive taking into account the level of remuneration paid to Non-Executives in similar companies within the industry.

These policies were implemented in 2012.

The Management and Board of Directors have today considered and approved the Annual and Consolidated Report and Accounts of P/F Atlantic Petroleum for the financial year 1st January 2013 to 31st December 2013.

The Annual Report has been prepared in accordance with International Financial Reporting Standards as adopted by the EU, the financial reporting requirements of NASDAQ OMX in Copenhagen, the financial reporting requirements of the Oslo Stock Exchange and additional Faroese disclosure requirements for annual reports of listed companies.

In our opinion, the accounting policies used are appropriate and the Annual and Consolidated Report and Accounts give a true and fair view of the Group and Parent's financial positions at 31st December 2013 as well as the results of the Group's and the Parent's activities and cash flows for the financial year 1st January 2013 to 31st December 2013.

Tórshavn 14th March 2014

Management:

Ben Arabo CEO

Board of Directors:

Birgir Durhuus Jan E Evensen Chairman Deputy Chairman

Diana Leo David A. MacFarlane

Barbara Y. Holm

To the Shareholders of P/F Atlantic Petroleum

Report on Consolidated Financial Statements

We have audited the consolidated financial statements of P/F Atlantic Petroleum for the financial year 1st January to 31st December 2013, which comprise income statement, comprehensive income statement, balance sheet, statement of changes in equity, cash flow statement and notes, including summary of significant accounting policies, for the Group. The consolidated financial statements are prepared in accordance with International Financial Reporting Standards as adopted by the EU and Faroese disclosure requirements for listed companies.

Management's Responsibility for the Consolidated Financial Statements and the Parent Company Financial Statements

The Management is responsible for the preparation of consolidated financial statements that give a true and fair view in accordance with International Financial Reporting Standards as adopted by the EU and Faroese disclosure requirements for listed companies and for such internal control as the Management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility

Our responsibility is to express an opinion on the consolidated financial statements based on our audit. We conducted our audit in accordance with International Standards on Auditing and additional requirements under Faroese Audit regulation. This requires that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatements of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation of consolidated financial statements that give a true and fair view in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by the Management, as well as the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

The audit has not resulted in any qualification.

Opinion

In our opinion, the consolidated financial statements give a true and fair view of the Group's financial position at 31st December 2013 and of the results of the Group's operations and cash flows for the financial year 1st January to 31st December 2013 in accordance with International Financial Reporting Standards as adopted by the EU and Faroese disclosure requirements for listed companies.

Statement on the Management's review

Pursuant to the Faroese Financial Statements Act, we have read the Management's review. We have not performed any further procedures in addition to the audit of the consolidated financial statements.

On this basis, it is our opinion that the information provided in the Management's review is consistent with the consolidated financial statements.

Tórshavn 14th March 2014

JANUAR

State Authorised Public Accountants P/F

Jógvan Amonsson Fróði Sivertsen

State Authorised Public Accountant State Authorised Public Accountant

For the year ended 31st December 2013

DKK 1,000	Note	2013	2012
Revenue	3	417,421	596,745
Cost of sales	4	-221,767	-274,888
Gross profit		195,655	321,857
Exploration expenses	5	-119,647	-27,209
Pre-licence exploration cost		-11,064	-7,962
General and administration cost	6,7,8,10, 25	-66,572	-39,930
Other operating income	9	0	14
Operating loss/profit		-1,629	246,771
Interest revenue and finance gains	11	1,454	2,587
Interest expenses and other finance cost	11	-11,448	-21,700
Loss/profit before taxation		-11,623	227,658
Taxation	12	-14,051	-160,998
Loss/profit after taxation		-25,674	66,660
Earnings per share (DKK):
Basic	14	-9.54	26.68
Diluted	14	-9.67	26.54

For the year ended 31st December 2013

DKK 1,000	2013	2012
Profit for the year	-25,674	66,661
Exchange rate differences	-19,530	10,267
Value of Future Contracts	-6,776	5,914
Total comprehensive loss/income for the year	-51,980	82,841

As at 31st December 2013

DKK 1,000	Note	2013	2012
Non-current assets
Goodwill	15,32	54,354	57,693
Intangible assets	16	26,482	16,589
Intangible exploration and evaluation assets	17	216,682	215,777
Tangible development and production assets	18	621,504	440,842
Property plant and equipment	19	2,782	2,555
Deferred tax asset	28	0	526
		921,804	733,982
Current assets
Inventories	21	38,759	14,004
Trade and other receivables	22	48,493	98,356
Tax repayable		43,509	27,091
Financial asset		0	5,863
Cash and cash equivalents	24,27	184,613	242,521
		315,375	387,834
Total assets		1,237,179	1,121,816
Current liabilities
Short-term debt	24,27	44,558	19,500
Short term liabilities		116	116
Trade and other payables	23	94,836	108,888
Current tax payable		1,117	20,975
Financial liabilities	27	914	0
		141,541	149,479
Non-current liabilities
Deferred tax liability	28	267,003	215,710
Long-term debt	24,27	58,500	58,500
Long-term provisions	26	172,790	160,986
		498,293	435,196
Total liabilities		639,834	584,676
Net assets		597,345	537,140
Equity
Share capital	29	367,670	262,670
Share based payment schemes		3,123	1,314
Value of futures contracts		-914	5,863
Share premium account		232,903	227,527
Translation reserves		12,435	31,966
Retained earnings		-17,873	7,801
Total equity shareholders' funds		597,345	537,140

For the year ended 31st December 2013

DKK 1,000	Share capital	Own shares	Share premium	Share based Payments account LTIP and bonus	Value of futures contracts	Translation reserves	Retained earnings	Total
At 1s t January 2012
	262,670	-27,306	231,154	0	-51	21,699	-58,860	429,306
Own Shares bought (52.500)	0	-9,450	0	0	0	0	0	-9,450
Own Shares sold (183,014 shares)	0	36,756	0	0	0	0	0	36,756
Capital loss of shares sold	0	0	-3,627	0	0	0	0	-3,627
Value of futures contracts	0	0	0	0	5,914	0	0	5,914
Share based payments - LTIP and bonus	0	0	0	1,314	0	0	0	1,314
Translation reserves	0	0	0	0	0	10,267	0	10,267
Profit for the year	0	0	0	0	0	0	66,661	66,661
At 31s t Decemeber 2012	262,670	0	227,527	1,314	5,863	31,966	7,801	537,140
Shares issued	105,000	0	0	0	0	0	0	105,000
Change in share premium account/cost of capital raise	0	0	5,376	0	0	0	0	5,376
Value of futures contracts	0	0	0	0	-6,776	0	0	-6,776
Share based payments - LTIP and bonus	0	0	0	1,809	0	0	0	1,809
Translation reserves	0	0	0	0	0	-19,530	0	-19,530
Profit for the year	0	0	0	0	0	0	-25,674	-25,674
At 31s t December 2013	367,670	0	232,903	3,123	-914	12,435	-17,873	597,345

For the year ended 31st December 2013

DKK 1,000	Note	2013	2012
Operating activities
Operating profit		-1,629	246,771
Allocated consolidated capitalised interest		2,541	-3,735
Relinquishment and disposal of licence		48,814	1,973
Impairment on exploration and evaluation assets		70,833	24,261
Depreciation, depletion and amortisation		103,189	138,472
Change in inventories		-24,695	-12,004
Change in trade and other receivables		25,955	-13,124
Change in trade and other payables		-41,321	24,776
Interest revenue and finance gains		1,454	2,681
Interest expenses and other finance costs		-11,448	-21,427
Income taxes		45,454	-21,083
Net cash provided by operating activities		219,146	367,561
Investing activities
Capital expenditure		-408,763	-213,574
Net cash used in investing activities		-408,763	-213,574
Financing activities
Change in share capital		105,000	0
Change in share premium account/cost of capital raise		5,376	0
Change in short-term debt		25,058	-20,468
Change in long-term debt		0	-6,500
Net cash used in financing activities		135,434	-26,968
Increase/Decrease in cash and cash equivalents		-54,183	127,018
Cash and cash equivalents at the beginning of the period		242,521	114,313
Currency translation differences		-3,725	1,190
Cash and cash equivalents at the end of the period	24	184,613	242,521

1 Corporate information

The consolidated financial statements of the Group, which comprise P/F Atlantic Petroleum, as the parent, and all its subsidiaries, for the year ended 31st December was authorised for issue in accordance with a resolution of the Directors on 14th March 2014.

P/F Atlantic Petroleum is a public limited company incorporated and domiciled in the Faroe Islands and listed on the exchanges on NASDAQ OMX Copenhagen and Oslo Stock Exchange. The principal activities of the Company and its subsidiaries (the Group) are Oil & Gas exploration, appraisal, development and production in the Faroe Islands, United Kingdom, Norway, Netherlands and Ireland. Financial statements for the Group's ultimate parent are presented on the group's website: www.petroleum.fo.

2.1 Basis of preparation

The Consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as endorsed by the Council of the European Union (EU) and the additional Faroese disclosure requirements according to the Faroese Company Accounts Act, the financial reporting requirements of NASDAQ OMX Copenhagen and Oslo Stock Exchange for listed companies.

The accounting policies set out below have been applied consistently to all periods presented in these consolidated financial statements

The financial information has been prepared on a historical cost basis and fair value conventions on the basis of the accounting policies set out below. The consolidated financial statements are presented in DKK and all values rounded to the nearest thousand, except where othewise indicated.

The consolidated financial statements incorporate the financial statements of P/F Atlantic Petroleum and entities controlled by P/F Atlantic Petroleum (its subsidiaries) made up at the end of each accounting period. Control is achieved where P/F Atlantic Petroleum has the power to govern the financial and operating policies of an investee entity so as to obtain benefits from its activities.

The results of subsidiaries acquired or disposed of during the year are included in the consolidated income statement from the effective date of acquisition or up to the effective date of disposal, as appropriate.

Where necessary, adjustments are made to the financial statements of subsidiaries to bring the accounting policies used into line with those used by other members of the Group.

Intra-group balances and any unrealised gains and losses or income and expenses arising from intra-group transactions are eliminated in preparing the consolidated financial statements.

The interests in the subsidiaries are eliminated with the Parent Company's proportionate ratio of the fair value of the subsidiaries assets, liabilities and provisions measured at the date of acquisition or establishment of the subsidiary.

2.2 Significant accounting judgements, estimates and assumptions

Determining the carrying amount of some assets and liabilities requires estimation of the effects of future events on those assets and liabilities at the balance sheet date.

In the opinion of Atlantic Petroleum's management, the following estimates and associated judgements are material for the financial reporting:

• Determination of underground oil and gas reserves. The assessment of reserves is a complex process involving various parameters such as analysis of geological data, commercial aspects, etc., each of which is subject to uncertainty. The assessment is material to the determination of the recoverable amount and depreciation profile for oil and gas assets,

• determination of the recoverable amount and depreciation profile for production assets. Determination of the recoverable amount is based on assumptions concerning future earnings, oil prices, interest rate levels, etc., each of which is subject to uncertainty. The depreciation profile has been determined on the basis of the expected use of the production assets, and is consequently subject to the same risks relating to reserves, future earnings, etc., as apply to the determination of the value of the production assets,

• determination of abandonment obligations. Provisions for abandonment obligations are subject to particular uncertainty as far as concerns the determination of the costs associated with removal of the production assets, and the timing of the removal,

• and assessment of contingent liabilities and assets.
• Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred and the amount recognised for non-controlling interest over the net identifiable assets acquired and liabilities assumed.

If the fair value of the net assets acquired is in excess of the aggregate consideration transferred, the gain is recognised in profit or loss.

After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group's cash-generating units that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units.

Where goodwill has been allocated to a cash-generating unit and part of the operation within that unit is disposed of, the goodwill associated with the disposed operation is included in the carrying amount of the operation when determining the gain or loss on disposal. Goodwill disposed in these circumstance is measured based on the relative values of the disposed operation and the portion of the cash-generating unit retained.

The estimates applied are based on assumptions which are sound, in management's opinion, but which, by their nature, are uncertain and unpredictable. The assumptions may be incomplete or inaccurate and unforeseen events or circumstances may occur. Moreover, the Atlantic Petroleum Group is subject to risks and uncertainties that may cause actual results to differ from these estimates. Special risks for the Atlantic Petroleum Group are described in the section Director's Report under Risk Management.

Assumptions for forward-looking statements and other estimation uncertainties at the balance sheet date that involve a considerable risk of changes that may lead to a material adjustment in the carrying amount of assets or liabilities within the coming financial year are disclosed in the notes.

The Group's intangible exploration and evaluation assets, amounts to DKK 216.7MM (2012: DKK 215.8MM) and the Group's development and production assets amounts to DKK 621.5MM at 31st December 2013 (2012: DKK 440.8MM). The Group's abandonment obligations as of 31st December 2013 amounts to DKK 172.8MM (2012: DKK 161.0MM).

2.3 Summary of significant accounting policies

Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of the consideration transferred measured at acquisition date fair value and the amount of any non-controlling interest in the acquiree. For each business combination, the Group elects whether to measure the non-controlling interest in the acquiree at fair value or at the proportionate share of the acquiree's identifiable net assets. Acquisition-related costs are expensed as incurred and included in administrative expenses.

When the Group acquires a business, it assesses the financial assets and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the separation of embedded derivatives in host contracts by the acquiree. If the business combination is achieved in stages, the previously held equity interest is remeasured at its acquisition date fair value and any resulting gain or loss is recognised in profit or loss.

Any contingent consideration to be transferred by the acquirer will be recognised at fair value at the acquisition date. Contingent consideration classified as an asset or liability that is a financial instrument and within the scope of IAS 39 Financial Instruments: Recognition and Measurement, is measured at fair value with changes in fair value recognised either in profit or loss or as a change to other comprehensive income. If the contingent consideration is not within the scope of IAS 39, it is measured in accordance with the appropriate IFRS. Contingent consideration that is classified as equity is not remeasured and subsequent settlement is accounted for within equity.

Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred and the amount recognised for non-controlling interest over the net identifiable assets acquired and liabilities assumed.

If the fair value of the net assets acquired is in excess of the aggregate consideration transferred, the gain is recognised in profit or loss.

After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group's cash-generating units that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units.

Where goodwill has been allocated to a cash-generating unit and part of the operation within that unit is disposed of, the goodwill associated with the disposed operation is included in the carrying amount of the operation when determining the gain or loss on disposal. Goodwill disposed in these circumstance is measured based on the relative values of the disposed operation and the portion of the cash-generating unit retained.

A joint venture is a contractual arrangement whereby the Group and other parties undertake an economic activity that is subject to joint control.

Acquisitions of oil and gas properties are accounted for under the purchase method where the transaction meets the definition of a business combination. Transactions involving the purchases of an individual field interest, or a group of field interests, that do not qualify as a business combination are treated as asset purchases, irrespective of whether the specific transactions involved the transfer of the field interests directly or the transfer of an incorporated entity. Accordingly no goodwill and no deferred tax gross up arises, and the consideration is allocated to the assets and liabilities purchased on an appropriate basis.

Proceeds on disposal are applied to the carrying amount of the specific exploration and evaluation asset or development and production asset disposed of and any surplus is recorded as a gain on disposal in the income statement.

Investments in joint ventures are recognised by proportionate consolidation at the share of the jointly controlled assets and liabilities, classified by nature, and the share of revenue from the sale of the joint product, along with the share of the expenses incurred by the jointly controlled operation. Liabilities and expenses incurred in respect of the jointly controlled operation are also recognised.

For each individual entity, which is recognised in the consolidated accounts, a functional currency is determined in which the entity measures its results and financial position. The functional currency is the currency of the primary economic environment in which the entity operates. Transactions in other currencies than the functional currency are transactions in a foreign currency.

A foreign currency transaction is, on initial recognition, recorded in the functional currency, at the spot exchange rate between the functional currency and the foreign currency on the date of the transaction.

At each balance sheet date receivables, payables and other monetary items in foreign currency are translated to the functional currency using the closing rate.

Exchange differences arising on the settlement of monetary items or on translating monetary items, at rates different from those at which they were translated on initial recognition during the period or in previous financial statements, shall be recognised in the income statement under financial revenues and expenses.

On consolidation the results and financial position of the Group's individual entities with different functional currencies than the Group's presentation currency (DKK) are translated into the Group's presentation currency using the following procedure:

• Assets and liabilities are translated at the closing rate at the date of the balance sheet.
• Income and expenses are translated at exchange rates at the dates of the transactions.

All resulting exchange differences are recognised directly in equity as a separate component of equity.

For practical reasons an average rate for the period that approximates the exchange rates at the dates of the transactions is used.

Revenue is recognised to the extent it is probable that the economic benefits will flow to the Group and the revenue can be reliably measured. Revenue is measured at the fair value of the consideration received or receivable, excluding discounts, sales taxes, excise duties and similar levies. The Group assesses its revenue arrangements against specific criteria in order to determine if it is acting as principal or agent. The Group has concluded that it is acting as a principal in all of its revenue arrangements.

Sale of hydrocarbons is recognised when transfer of risk to the buyer has taken place. Sale of hydrocarbons is measured at fair value and represents amounts receivable for goods and services provided in the normal course of business, net of discounts, VAT and other sales related taxes.

Cost of sales comprises cost directly related to the operation of oilfields, cost of goods sold, depreciations, lease payments and other costs related to the operation of producing oil fields. Rentals payable for assets under operating leases are charged to the income statement on a straight-line basis over the lease term. Impairment of development and production assets is also recognised here.

Pre-licence exploration expenses comprise cost incurred prior to having obtained the legal rights to explore an area and other general exploration costs which are not specifically directed to a licence and economic use is of less than a year.

Exploration expenses comprise the cost of the impairment of exploration and evaluation assets and relinquishment cost.

Administrative expenses comprise employment costs to the management and administration, staff, depreciations and other costs related to the general administration of the Group.

Financial income and expenses comprise interests, currency differences, dividend income from investments and amortisation of financial assets and liabilities.

Income tax expense represents the sum of the tax currently payable and deferred tax. The tax currently payable is based on taxable profit for the year. Taxable profit differs from net profit as reported in the income statement because it excludes items of income or expense that are taxable or deductible in other years and it further excludes items that are never taxable or deductible. The Group's liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the balance sheet date.

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

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

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

Deferred tax is calculated at the tax rates that are expected to apply in the period when the liability is settled or the asset realised.

Deferred tax assets and liabilities are offset when there is a legally enforceable right to set off corporation tax assets against corporation tax liabilities and when they relate to income taxes levied by the same taxation authority and the Group intends to settle its current tax assets and liabilities on a net basis.

Tax is charged or credited in the income statement, except when it relates to items charged or credited directly to equity, in which case the deferred tax is also dealt with in equity.

By the acquisition of Atlantic Petroleum Norge AS, the Group is subject to the Norwegian oil taxation regime for the operations on the Norwegian Continental shelf. Under this regime oil companies which are not in a tax paying position may claim a 78% refund of their exploration costs, limited to the taxable loss for the current year. The tax refund is unconditional in terms of contingent operation of the companies concerned. The refund is paid out in December in the following year. The portion of the tax receivable which is due to be received within one year from the balance sheet date is classified as a current asset.

Goodwill is initially recognised and measured as the difference between on the one hand, the cost price of the acquired company, the value of minority interests in the acquired company and the acquisition-date fair value of previously held equity interests, and, on the other hand, the fair value of the acquired assets, liabilities and contingent liabilities.

When recognising goodwill, the goodwill amount is allocated to those of the Group's activities that generate independent cash flows (cash flow generating units). The definition of cash generating units is in accordance with the internal managerial accounting and reporting in the Group. Goodwill is not amortised but is tested for impairment at least once a year.

Items of intangible assets are stated at cost less accumulated depreciation and impairment losses.

Depreciation is charged to the income statement under General and Administration costs item on a straightline basis over the estimated useful lives. The estimated useful lives are as follows:

Office equipment 3 – 10 years

The residual value is reassessed annually.

The Group applies the successful efforts method of accounting for Exploration and Evaluation (E&E) costs, having regard to the requirements of IFRS 6 Exploration for and Evaluation of Mineral Resources.

Under the successful efforts method of accounting all licence acquisition, exploration and appraisal costs are initially capitalised at cost in well, field or specific exploration cost centres as appropriate, pending determination. Expenditure, incurred during the various exploration and appraisal phases, is then written off unless commercial reserves have been established or the determination process has not been completed.

The amounts capitalised include payments to acquire the legal right to explore, licence fees, cost of technical services and studies, seismic acquisition, exploratory drilling and testing and other directly attributable cost.

Finance cost that are directly attributable to E&E assets are capitalised in accordance with IAS 23. In the Parent Company these cost are expensed to the profit and loss account.

Cost incurred prior to having obtained the legal rights to explore an area (pre-licence cost) are expensed directly to the income statement under Pre-licence exploration cost as they have incurred.

E&E assets are not amortised prior to the conclusion of appraisal activities.

Intangible E&E assets related to each exploration licence/prospect are carried forward, until the existence (or otherwise) of commercial reserves has been determined subject to certain limitations including review for indications of impairment. Every year or if there otherwise are indications of impairment the assets will be tested for impairment. Where, in the opinion of the directors, there is impairment, E&E assets are written down accordingly, through the profit and loss account under Exploration Expenses.

If commercial reserves have been discovered and a field development plan has been approved by the authorities, the carrying value of the relevant E&E asset is reclassified as a tangible asset, development and production asset. Before the reclassification the asset will be tested for indications of impairment. If however, the commercial reserves have not been found, the capitalised cost are charged to the profit and loss account under Exploration Expenses after conclusion of appraisal activities.

Development and production assets are accumulated generally on a field by field basis and represent the cost of developing the commercial reserves discovered and bringing them into production, together with the E&E expenditures incurred in finding commercial reserves transferred from intangible E&E assets as outlined in the accounting policy for E&E assets above.

The cost of development and production assets also includes the cost of acquisitions and purchases of such assets, directly attributable overheads, finance costs capitalised, and the cost of recognising provisions for future restoration and decommissioning. In the Parent Company finance costs are expensed to the profit and loss account.

The net book values of producing assets are depreciated generally on a field-by-field basis using the unit-ofproduction (UOP) method by reference to the ratio of production in the period and the related commercial reserves of the field.

An impairment test is performed once a year or whenever events and circumstances arising during the development or production phase indicate that the carrying value of a development or production asset may exceed its recoverable amount.

The carrying value is compared against the expected recoverable amount of the asset, generally by reference to the present value of the future net cash flows, expected derived from production of commercial reserves. An impairment loss is recognised whenever the carrying amount of an asset or its cash-generating unit exceeds its recoverable amount. Impairment losses are recognised in the income statement under the relevant item. The cash-generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped as a single cash-generating unit where the cash flows of each field are interdependent. An impairment loss is reversed only to the extent that the assets carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or amortisation, if no impairment loss had been recognised.

The depreciation and impairment are charged to the profit and loss account under Cost of sales.

Provision for decommissioning is recognised in full when the liability occurs. The amount recognised is the present value of the estimated future expenditure. A corresponding tangible fixed asset is also created at an amount equal to the provision. This is subsequently depreciated as part of the capital costs of the production facilities. Any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the fixed asset.

Items of property, plant and equipment are stated at cost less accumulated depreciation and impairment losses.

Depreciation is charged to the income statement under General and Administration costs item on a straightline basis over the estimated useful lives. The estimated useful lives are as follows:

Operating assets and office equipment 3 – 10 years

The residual value is reassessed annually.

Financial assets and financial liabilities are recognised in the Group's balance sheet when the Group becomes a party to the contractual provisions of the instrument.

The difference between cumulative production and lifted (sold) volumes is crude inventory and will be valued at the market rate at the period end with the inventory adjustments being posted through Cost of Sales.

Trade and other receivables are recognised at amortised costs and are reduced by appropriate allowances for estimated irrecoverable amounts.

Cash and cash equivalent includes cash in hand and deposits held at call with banks with maturity dates of less than three months.

The translation reserve comprises foreign exchange rate adjustments arising on translation of the financial statements of foreign entities with a functional currency that is different from the presentation currency (DKK) of Atlantic Petroleum.

Borrowings are recognised initially at fair value, net of transaction costs incurred. Borrowings are subsequently stated at amortised cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognised in the income statement over the period of the borrowings. Borrowings are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least 12 months after the balance sheet date.

Other payables are stated at their nominal value.

Provisions are recognised when the Group has a present obligation as a result of a past event and it is probable that the Group will be required to settle that obligation. Provisions are measured at the management's best estimate of the expenditure required to settle the obligation at the balance sheet date, and are discounted to present value where the effect is material. Included in the item Provisions is provision for decommissioning costs.

Equity-settled share-based payments are initially measured at fair value at the date of grant. The fair value determined at the grant date of the equity-settled share-based payments is expensed on a straight-line basis over the vesting period, based on the Company's estimate of shares that will eventually vest and adjusted for the effect of nonmarket-based vesting conditions.

The fair value is determined by using generally accepted valuation techniques, such as the Monte Carlo model.

Cancellations or settlements of equity settled share-based payments are treated as an acceleration of vesting and as a result any amounts that otherwise would have been recognised for services received over the remainder of the vesting period are recognised immediately in the income statement. When options are exercised the payments from employees are recognised as an increase in the Group's share capital and share premium reserve.

In the opinion of the directors the operations of the Group comprise one class of business, the production and sale of hydrocarbons. Its primary segment reporting will be by geographical region.

The cash flow statement is prepared according to the indirect method and presents cash flow from operations, investments and financing activities.

Cash flows from operating activities are presented using the indirect method, whereby the net profit or loss for the period is adjusted for the effects of non-cash transactions, accruals, tax-payments and items of income or expense associated with investing or financing cash flows.

Cash flows from investment activities comprises cash flows in conjunction with buying and selling entities and activities, buying and selling intangible, tangible and other non-current assets and buying and selling securities which are not recognised as cash and cash equivalents.

Cash flows from financing activities comprise the raising of new share capital and loans, amortisation on loans and payment of dividends.

2.4 Changes in accounting policies and disclosures

The Consolidated Financial Statements are presented in accordance with the accounting policies adopted previous financial years and which are consistent with those applied in the previous financial year.

There were a number of new standards and interpretations, effective from 1st January 2013, that the Group applied for the first time in the current year. These included IFRS 10 Consolidated Financial Statements, IFRS 11 Joint Arrangements, IFRS 12 Disclosure of Interests in Other Entities, IAS 27 Separate Financial Statements, IAS 28 Investment in Associates and Joint Ventures and IFRS 13 Fair Value Measurement. None of these standards required a restatement of previous financial statements or did result in disclosures being changed.

Several other amendments apply for the first time in 2013. However, they do not impact the annual consolidated financial statements of the Group or the interim condensed consolidated financial statements of the Group.

The nature and the impact of each new relevant standard and/or amendment is described below. Other than the changes described below, the accounting policies adopted are consistent with those of the previous financial year.

IFRS 10 replaces the portion of IAS 27 Consolidated and Separate Financial Statements that addresses the accounting for consolidated financial statements. It also addresses the issues covered in SIC-12 Consolidation - Special Purpose Entities.

IFRS 10 establishes a single control model that applies to all entities including structured entities (previously referred to as special purpose entities). The changes introduced by IFRS 10 require management to exercise significant judgement to determine which entities are controlled and therefore are required to be consolidated by a parent, compared with the requirements that were in IAS 27.

The application of IFRS 10 and IAS 27 did not impact the Group's accounting for its interests in subsidiaries.

The application of IFRS 11 and IAS 28 did not impact the Group's accounting for its interests in joint arrangements because the Group determined that Its joint arrangements that were previously classified as jointly controlled assets, were classified as joint operations under IFRS 11.

IFRS 12 sets out the requirements for disclosures relating to an entity's interests in subsidiaries, joint arrangements, associates and structured entities. The requirements in IFRS 12 are more comprehensive than the previously existing disclosure requirements for such investments, but will have no impact on the Group's financial position or performance.

IFRS 13 establishes a single source of guidance under IFRS for all fair value measurements. IFRS 13 does not change when an entity is required to use fair value, but rather provides guidance on how to measure fair value under IFRS when fair value is required or permitted. IFRS 13 defines fair value as an exit price. Application of IFRS 13 has not materially impacted the fair value measurements of the Group.

The revised standard includes a number of amendments that range from fundamental changes to simple clarifications and re-wording. The more significant changes include the following:

• For defined benefit plans, the ability to defer recognition of actuarial gains and losses (i.e., the corridor approach) has been removed. As revised, amounts recorded in profit or loss are limited to current and past service costs, gains or losses on settlements, and net interest income (expense). All other changes in the net

• defined benefit asset (liability), including actuarial gains and losses, are recognised in OCI with no subsequent recycling to profit or loss.
• Expected returns on plan assets are no longer recognised in profit or loss. Expected returns are replaced by recording interest income in profit or loss, which is calculated using the discount rate used to measure the pension obligation.
• Objectives for disclosures of defined benefit plans are explicitly stated in the revised standard, along with new and revised disclosure requirements. These new disclosures include quantitative information about the sensitivity of the defined benefit obligation to a reasonably possible change in each significant actuarial assumption.

• Termination benefits are recognised at the earlier of when the offer of termination cannot be withdrawn, or when the related restructuring costs are recognised under IAS 37 Provisions, Contingent Liabilities and Contingent Assets.

• The distinction between short-term and other long-term employee benefits is based on the expected timing of settlement rather than the employee's entitlement to the benefits.

The revised standard is applied retrospectively in accordance with the requirements of IAS 8 for changes in accounting policy. There are limited exceptions for restating assets outside the scope of IAS 19 and for presenting sensitivity disclosures for comparative periods in the period the amendments are first effective. Early application is permitted and must be disclosed.

• o IFRS 1 Repeat application of IFRS 1
• o IFRS 1 Borrowing Costs
• o IAS 1 Clarification of the requirement for comparative information
• o IAS 16 Classification of servicing equipment
• o IAS 32 Tax effects of distributions to holders of equity instruments
• o IAS 34 Interim financial reporting and segment information for total assets and liabilities

The IASB's annual improvements process deals with non-urgent but necessary clarifications and amendments to IFRS. In the 2009-2011 annual improvements cycle, the IASB issued six amendments to five standards, summaries of which are provided below. The amendments are applicable to annual periods beginning on or after 1st January 2013. Earlier application is permitted and must be disclosed. The amendments are applied retrospectively, in accordance with the requirements of IAS 8 for changes in accounting policy.

The Group will quantify the effect in conjunction with the other phases, when the final standard including all phases is issued. Management believes that implementation of these standards and interpretations do not have a material affect on the Consolidated Financial Statements of the Group.

2.5 Standards issued but not yet effective

There are no standards and interpretations that are issued but not yet effective up to the date of issuance of the Group's financial statements that the Group reasonably expects will have an impact on disclosures, financial position or performance when applied at a future date. he Group intends to adopt these standards and interpretations, if applicable, when they become effective.

I

IFRS 9, as issued, reflects the first phase of the IASB's work on the replacement of IAS 39 and applies to classification and measurement of financial assets and financial liabilities, as defined in IAS 39. The standard was initially effective for annual periods beginning on or after 1st January 2013, but Amendments to IFRS 9 Mandatory Effective Date of IFRS 9 and Transition Disclosures, issued in December 2011, moved the mandatory effective date to 1st January 2015. In subsequent phases, the IASB is addressing hedge accounting and impairment of financial assets. The adoption of the first phase of IFRS 9 may have an effect on the classification and measurement of the Group's financial assets but will not have an impact on classification and measurements of the Group's financial liabilities. The Group will quantify the effect in conjunction with the other phases, when the final standard including all phases is issued.

IFRIC 21 clarifies that an entity recognises a liability for a levy when the activity that triggers payment, as identified by the relevant legislation, occurs. For a levy that is triggered upon reaching a minimum threshold, the interpretation clarifies that no liability should be anticipated before the specified minimum threshold is reached. IFRIC 21 is effective for annual periods beginning on or after 1st January 2014. The adoption of IFRIC 21 may have an impact on the Group's accounting for production and similar taxes, which do not meet the definition of an income tax in IAS 12. However, the Group is still assessing and quantifying the effect.

3 Geographical segmental analysis

Group

Segmental reporting follows the Group's internal reporting structure, and accordingly its primary segment reporting is geographical. In the opinion of the directors the

operations of the Group comprise one class of business; the production and sale of hydrocarbon.

	Faroe Islands		United Kingdom		Norway		Other		Total
DKK 1,000	2013	2012	2013	2012	2013	2012	2013	2012	2013	2012
Revenue
Oil sales	0	0	409,869	583,622	0	0	0	0	409,869	583,622
Gas sales	0	0	7,329	12,318	0	0	0	0	7,329	12,318
Income Manpower and recharges	0	0	224	856	0	0	0	-51	224	805
Total revenue	0	0	417,421	596,796	0	0	0	-51	417,421	596,745
Results
Operating profit	-5,459	-12,633	93,765	264,010	-48,963	-2,840	-40,973	-1,766	47,334	249,611
Interest revenue and finance gains	41	1,363	6,796	1,077	453	236	566	4	7,403	2,444
Interest expenses and other finance costs	-4,907	-6,742	-2,255	-14,755	-9,219	0	-1,469	-295	-8,631	-21,793
Profit /loss before tax	-10,325	-18,012	98,306	250,332	-57,728	-2,604	-41,876	-2,108	46,105	230,263
Taxation	0	0	-48,330	-162,609	34,280	1,611	0	0	-48,330	-162,609
Net profit/loss	-10,325	-18,012	49,975	87,723	-23,448	-993	-41,876	-2,108	-2,225	67,653
Assets and liabilities
Segment assets	123,219	37,659	912,179	951,142	177,474	70,241	24,307	62,774	1,059,705	1,051,575
Total segment assets	123,219	37,659	912,179	951,142	177,474	70,241	24,307	62,774	1,059,705	1,051,575
Total segment liabilities	97,786	86,651	463,412	457,431	72,395	33,959	6,241	-31,801	567,439	512,281
Other segment information
Capitalised additions to intangible and
tangible assets	2,697	19,495	366,615	200,820	36,189	0	53,851	2,126	423,164	222,441
Depreciations and amortisation	-488	-274	-98,336	-141,093	-6,905	0	0	-137	-98,824	-141,505
Disposal and exploration expenditures
written off	-270	-9,242	-71,369	-17,867	-11,057	0	-39,744	0	-111,383	-27,109

The Group manages its operations on a geographical basis. During 2013 the Group's operations were based in three main geographical areas being Faroe Islands, UK,

Norway and Other, comprising the Netherlands and the Reublic of Ireland .

4 Cost of sales

DKK 1,000	2013	2012
Operating costs	124,199	133,754
Amortisation and depreciation, plant and equipment:
Oil and gas properties	97,567	141,134
	221,767	274,888

5 Exploration expenses

DKK 1,000	2013	2012
Relinquishment of licences	48,742	2,460
Exploration expenditures written off	70,906	24,748
	119,647	27,209

L014 expired in January 2013 and was written off in 2012. Also additional cost in 2013 has been written off. In the UK Magnolia has been written off. In Ieland part of the Dunquin well has been written off. The Company has relinquished P1734 Endymion and written off P1716 Foxtrot, Ketex block 49/3, P1827 Lead K and P1748 Dory. In Norway PL559 Hendricks has been relinquished.

The directors have reviewed the carrying amounts for the intangible exploration and evaluation assets and have decided that no other impairment provision shall be made in 2013.

6 Auditors' remuneration

DKK 1,000	2013	2012
Audit services:
Statutory and Group audit, parent company auditor	432	408
Review of Interim Financial Statements	250	240
Audit subsidiaries	282	560
	963	1,207
Tax services:
Consulting and advisory services	48	49
	48	49
Other services:
Consultancy other services	12	77
	12	77

7 Employee cost

DKK 1,000	2013	2012
Staff costs, including executive directors:
Wages and salaries
Board of Directors*	1,680	1,518
Managing Director - CEO***	1,942	1,728
Administration, technical staff and other employees	30,267	13,780
	33,888	17,027
Bonus:
Managing Director - CEO****	352	900
Administration, technical staff and other employees	1,535	2,343
	1,887	3,243
Share based payement - LTIP accounting charge:
Managing Director - CEO	734	418
Administration, technical staff and other employees	1,298	636
	2,033	1,054
Pension costs:
- defined benefit	0	0
- defined contribution:
Administration, technical staff and other employees	2,691	1,506
	2,691	1,506
Social security costs	5,795	1,701
	5,795	1,701
Total employee costs	46,294	24,532
	2013	2012
Average number of employees during the year**:
Technical and operations	17	10
Management and administration	10	6
	27	16

* The Board of Directors' remuneration by person is disclosed in the section regarding shareholders information.

** Staff numbers include managers. ***In addition to salaries to CEO total benefits add upp to DKK 5,300.

**** The 2012 Bonus is split up in cash DKK 637,500 and 1,521 shares at a share price of DKK 172.55

The notice of termination for the CEO is one year.

8 Share based payments

The companies have share option schemes under which options have been granted to the CEO and members of employees and management, for shares in the parent company. The options are capable of vesting after a three year period subject to continued employment and meeting stretching corporate performance conditions.

Movements during the period	2013			2012
		Weighted		Weighted
	Number	average	Number	average
	of options	exercise price	of options	exercise price
Outstanding at 1s t January	22,352	169.50
Granted during the period	21,804	157.50	22,352	169.50
Forfeited during the period	0	0.00	0	0.00
Exercised during the period	0	0.00	0	0.00
Expired during the period	0	0.00	0	0.00
Outstanding at end of period	21,804	163.57	22,352	169.50
Exercisable at end of period	0		0
Authorised but not issued at end of period	0		0

The range of exercise prices for options outstanding at the end of the year was DKK 157.50 to DKK 169.50.

The weighted average contractual life for the share options outstanding as at end of the year 2013 is 2.27 years (2012: 2.23 years)

The weighted average fair value of the options granted during the year is DKK 146.00 and for the options granted in 2012 it is DKK 184.24. The weighted average fair value of the options granted during the year is DKK 146.00 and for the options granted in 2012 it is DKK 184.24.

The fair value of one of these LTIP awards awarded in 2012 is DKK 184.24 and in 2013 it is DKK 146.00. Please note that the fair value is more than 100% for the 2012 awards accordingly 93% for the 2013 awards of the share at grant as a result of the LTIP Schemes share price multiplier potentially permitting up to three times the number of initial awards to vest. This results in a total charge of DKK 7,241,101, which will be accounted for as follows:

	LTIP Awarded	LTIP Awarded
	2013	2012	Total
Charges to the income statement	DKK	DKK	DKK
2012 Charges	-	1,060,587	1,060,587
2013 Charges	709,483	1,372,745	2,082,228
2014 Charges	1,040,005	1,372,745	2,412,750
2015 Charges	1,040,005	312,159	1,352,164
2016 Charges	333,372	-	333,372
	3,122,865	4,118,236	7,241,101

	LTIP Awarded	LTIP Awarded
	2013	2012
Inputs to the models	DKK	DKK
Dividend yield in %	0.00	0.00
Expected volatility in %	34.50	39.63
Risk-free interest rate in %	0.24	0.43
Date of Grant	26t h April 2013	24t h March 2012
Expected life of share options in years	3	3
Share price at grant in DKK	157.50	169.50
Model used	Monte Carlo	Monte Carlo
Number of options awarded	21,804	22,352

9 Other operating income

DKK 1,000	2013	2012
Other operating income is related to a demurrage claim	0	14
	0	14

10 Depreciation

DKK 1,000	2013	2012
Depreciations included in general and administrations costs	8,583	1,073
	8,583	1,073

11 Interest revenue and expenses & finance gains and cost

DKK 1,000	2013	2012
Interest revenue and finance gains:
Short-term deposits	586	2,587
Exchange differences	867	0
	1,454	2,587
DKK 1,000	2013	2012
Finance expenses and other finance costs:
Bank loan and overdrafts	8,992	6,666
Creditors	7	9
Unwinding of discount on decommissioning provision	2,036	7,307
Unwinding of discount on liabilities	259	366
Others	153	148
Exchange differences	0	7,204
	11,448	21,699

12 Tax

DKK 1,000	2013	2012
Current tax:
Tax payable in UK	-1,565	-23,973
Tax repayable Norway	47,019	2,890
Total current tax	45,454	-21,083
Deferred tax:
Deferred tax cost in UK	-97,452	-143,605
Deferred tax income in UK	50,687	4,969
Deferred tax cost in Norway	-12,739	-1,279
Total deferred tax	-59,504	-139,915
Tax on profit on ordinary activities	-14,051	-160,998

As at 31st December 2013, the Group has a net deferred tax asset of DKK 20.2MM (2012: DKK 15.3MM) which has not been recognised in the Group's accounts.

Effect of capital allowances in excess of depreciation: DKK 5.5MM (2012: DKK 8.5MM) Effect of tax losses available: DKK 25.7MM (2012: DKK 23.9MM) The losses can be carried forward indefinitely.

This is made up of the following amounts:

The charge for the year can be reconciled to the result per the income statement as follows:

	2013	2012
Group result on ordinary activities before tax	-11,623	227,659
	-11,623	227,659
Corporation tax on profits	12,673	75,172
Hydrocarbon taxes	703	79,659
	13,376	154,831
Tax effect off:
Expenses not deductible for tax purposes	5,703	7,271
Net onshore income	5,409	0
Income taxed at lower rate	-1,833	-399
Adjustments to opening balance due to change in tas rates or laws	729	248
Restriction on relief on deconmissioning costs	-6	359
Prior year adjustments	424	-1,312
Change in brown field allowances	-3,654	0
Interests in Norway	-90	0
Ringe fence expenditure supplement charge	-5,004	0
Deferred tax on financial posts	-1,004	0
Tax expense for the year	14,051	160,998

13 Dividend

No interim dividend is proposed. (2012: DKK Nil)

14 Earnings per share

The calculation of basic earnings per share is based on the profit after tax and on the weighted average number of Ordinary Shares in issue during the year.

Basic and diluted earnings per share are calculated as follows:

			Weighted average
DKK 1,000	Profit after tax		number of shares			Earnings per share
					2013	2012
	2013	2012	2013	2012	DKK	DKK
Basic	-25,674	66,661	2,689,991	2,498,680	-9.54	26.68
Diluted	-26,015	66,660	2,689,991	2,498,680	-9.67	26.54

15 Goodwill

DKK 1,000	2013	2012
At 1st January	57,693	37,851
Additions during the year	0	18,856
Exchange movements	-3,339	987
At 31s t December	54,354	57,693

The goodwill in 2012 arises from the acquisition of Emergy Exploration AS (Now Atlantic Petroleum Norge AS).

16 Intangible assets

DKK 1,000	Faroe Islands	United Kingdom	Norway	Other	Total
Costs
At 1s t January 2012	378	551	0	0	929
Additions during the year	120	14	16,164	0	16,298
At 31s t December 2012	498	565	16,164	0	17,227
Additions during the year	899	2,406	15,402	0	18,707
Exchange movements	0	-13	-2,087	0	-2,101
At 31s t December 2013	1,397	2,958	29,479	0	33,834
Amortisation and depreciation
At 1st January 2012	-53	-191	0	0	-244
Exchange movements	0	-5	0	0	-5
Charge for the year	-130	-158	-100	0	-389
At 31s t December 2012	-183	-355	-100	0	-638
Charge for the year	-336	-253	-6,636	0	-7,225
Exchange movements	0	4	508	0	513
At 31s t December 2013	-519	-604	-6,228	0	-7,351
Net book value
At 31st December 2012	315	210	16,064	0	16,589
At 31s t December 2013	878	2,354	23,251	0	26,482

17 Oil and gas – Intangible exploration and evaluation assets

			Oil and gas properties
DKK 1,000	Faroe Islands	United Kingdom	Norway	Other	Total
Costs
At 1s t January 2012	16,641	68,069	0	5,722	90,432
Exchange movements	0	1,733	0	20	1,753
Additions during the year	20,310	76,923	0	2,126	99,359
Additions during the year from business combinations	0	0	51,341	0	51,341
Disposal of licences	-57	-1,905	0	0	-1,963
Exploration expenditures written off	-9,023	-14,713	0	0	-23,736
Consolidated interest written off/moved to development and production assets -162		-1,249	0	0	-1,410
At 31s t December 2012	27,710	128,857	51,341	7,869	215,777
Exchange movements	0	-4,041	-5,805	0	-9,846
Additions during the year	1,631	74,361	19,835	53,851	149,679
Traded during theh year	-9,654	0	0	0	-9,654
Disposal of licences	0	-37,684	-11,057	0	-48,742
Explorations expenditures written off	-124	-37,883	0	-39,744	-77,752
Consolidated interest written off	-73	-2,708	0	0	-2,780
At 31s t December 2013	19,490	120,902	54,314	21,976	216,682

The amounts for intangible E&E assets represent the active exploration projects. These amounts will be written off to the income statement as exploration expense unless commercial reserves are established or the determination process is not completed and there are no indications of impairment. The outcome of ongoing exploration, and therefore whether the carrying value of E&E assets will ultimately be recovered, is inherently uncertain.

18 Oil and gas – Tangible development and production assets

	Oil and gas properties
DKK 1,000	Faroe Islands	United Kingdom	Norway	Other	Total
Costs
At 1s t January 2012	0	799,633	0	0	799,633
Exchange movements	0	20,040	0	0	20,040
Additions during the year	0	123,344	0	0	123,344
At 31s t December 2012	0	943,017	0	0	943,017
Exchange movements	0	-21,226	0	0	-21,226
Additions during the year	0	289,697	0	0	289,697
At 31s t December 2013	0	1,211,488	0	0	1,211,488
Amortisation and depreciation
At 1s t January 2012	0	-353,012	0	0	-353,012
Exchange movements	0	-8,803	0	0	-8,803
Charge for the year	0	-140,360	0	0	-140,360
At 31s t December 2012	0	-502,175	0	0	-502,175
Exchange movements	0	9,759	0	0	9,759
Charge for the year	0	-97,567	0	0	-97,567
At 31s t December 2013	0	-589,984	0	0	-589,984
Net book value
At 31st December 2012	0	440,842	0	0	440,842
At 31s t December 2013	0	621,504	0	0	621,504

Depreciation and amortisation for oil and gas properties is calculated on a unit-of-production basis, using the ratio of oil and gas production in the period to the estimated quantities of proved and probable reserves at the end of the period plus production in the period, on a field-by-field basis. Proved and probable reserve estimates are based on a number of underlying assumptions including oil and gas prices, future costs, oil and gas in place and reservoir performance, which are inherently uncertain. Management uses established industry techniques to generate its estimates and regularly references its estimates against those of joint venture partners or external consultants. However, the amount of reserves that will ultimately be recovered from any field cannot be known with certainty until the end of the field's life.

19 Property, plant and equipment assets

Faroe Islands	United Kingdom
		Norway	Other	Total
				3,039
0	54	0	0	54
595	554	752	0	1,900
1,376	2,865	752	0	4,993
0	-251	-97	0	-348
167	151	952	0	1,270
1,543	2,765	1,606	0	5,914
-645	-1,016	0	0	-1,660
0	-21	0	0	-21
-144	-575	-37	0	-755
-788	-1,612	-37	0	-2,437
0	217	25	0	241
0	0	0	0	0
-152	-516	-269	0	-937
-940	-1,911	-282	0	-3,133
587	1,253	714	0	2,555
603	854	1,325	0	2,782
	781	2,258	0	0

20 Investments and associates

Principal subsidiary undertakings of the Parent Company, all of which are 100 per cent owned, are as follow:

	Business and	Country of incorporation
Name of Company	area of operation	or registration
Atlantic Petroleum Norge AS	Exploration, development and production, Norway	Norway
Atlantic Petroleum UK Limited	Exploration, development and production, UK	England and Wales
Atlantic Petroleum (Ireland) Limited*	Exploration, development and production, Ireland	Republic of Ireland
Volantis Exploration Limited*	Exploration, development and production, UK	England and Wales
Volantis Netherlands B.V.*	Exploration, development and production, Netherlands	Netherlands
* Held through subsidiary undertaking.

21 Inventories

DKK 1,000	2013	2012
Chestnut Ettrick Blackbird	14,170 22,393 2,196	3,949 9,397 658
Net assets	38,759	14,004

Produced but not sold oil at year end, valued at fair value.

22 Trade and other receivables

DKK 1,000	2013	2012
Trade receivables	30,688	63,369
Prepayments and accrued income	10,276	25,337
Other taxes and VAT receivable	2,375	3,056
Other receivables	5,154	6,594

In the 2012 accounts Norwegina tax repayable was grouped with Other taxes and VAT receivable. The amount included was DKK 27.1MM and the total of the line was 30.1MM.

All trade and other receivables are due within one year. The carrying values of the trade and other receivables are equal to their fair value as at the balance sheet date. 48,493 98,356

23 Trade and other payables

DKK 1,000	2013	2012
Trade payables	52,855	71,455
Accrued expenses	5,162	3,915
Other taxes and vat payable	3,365	1,913
Other payables	33,454	31,605
	94,836	108,888

All trade and other payables are due within one year.

The carrying values of the trade and other payables are equal to their fair value as at the balance sheet date.

24 Cash, short and long term debt

DKK 1,000	2013	2012
Cash:
Cash at bank and in hand	184,613	242,521
Total cash	184,613	242,521
Short term bank loans	44,558	19,500
Other short term loans	0	0
Total short term borrowings	44,558	19,500
Long term bank loans	58,500	58,500
Other long term loans	0	0
Total long term borrowings	58,500	58,500
The borrowings are repayable as follows:
DKK 1,000	2013	2012
Bank loans analysed by maturity:
In one to five years	58,500	58,500
Over five years	0	0

Total borrowings 58,500 58,500

The Group had one long-term facility of DKK 58.5MM at year end 2013 and a borrowing facility of NOK 300MM. (2012: DKK 58.5MM). At year end 2013 the total short- and long-term loans amounted to DKK 103.1MM (2012: DKK 78.0MM).

25 Obligations under leases

DKK 1,000	2013	2012
Minimum lease payments under operating leases recognised in the income statement for the year	50,332	44,503
	50,332	44,503
Outstanding commitments for future minimum lease payments under non-cancellable operating leases,
which fall due as follow:
Within one year	51,464	44,403
In one to five years	6,070	14,626
Over five years	0	0
	57,534	59,029

In accordance with the Company's participation in joint arrangements with other companies, an agreement has been signed whereby the Company is party to a charter contract for the use of a floating production, storage and offloading platform. Payments under the contract began approximately 1st October 2008 were made every 6 months. The latest renewal from 1st January 2014 secures the vessel for 1 full year, with an additional 5x three months optional extension periods, taking the potential hire of the vessel out to end March 2016. The Company's annual commitment is estimated at USD 5.2MM. production, storage and offloading platform. An agreement has now been reached where the initial term of the contract has been extended to March 4t h 2015.

Also, in accordance with the Company's participation in joint arrangements with other companies, an agreement was signed whereby the Company was party to a five year charter contract for the use of a floating

The Joint Venture has the option to extend the contract by a further two years. Payments under the contact result in an annual commitment estimated at USD 3.4MM.

26 Provisions for long-term liabilities and charges

DKK 1,000	2013	2012
Deferred provision:
At 1st January	13,809	13,104
Exchange movements	-321	342
Additions during the year	-13,488	363
At 31s t December	0	13,809
Decommissioning costs:
At 1st January	147,177	101,729
Exchange movements	-3,273	2,495
Addition of future decommissioning costs during the year	26,861	35,756
Unwinding of discount on decomissioning provision	2,024	7,197
Decommissioning	0	0
At 31s t December	172,790	147,177
Total provision	172,790	160,986

The deferred provision represents a deferred payment for the acquisition of certain licences. The licences have had development plans approved and consequently a provision has been made for the potential deferred consideration that is expected to be paid in respect of these licences. These amounts have been included in tangible assets. A deferred provision for one certain licence has been transferred to short term deferred provisions.

The decommissioning provision represents the present value of decommissioning costs relating to the oil and gas interests, which are expected to be incurred between 2013 and 2031. These provisions have been created based on operators' estimates. Based on the current economic environment, assumptions have been made which the management believe are a reasonable basis upon which to estimate the future liability. These estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual decommissioning costs will ultimately depend upon future market prices for the necessary decommissioning works required, which will reflect market conditions at the relevant time.

Furthermore, the timing of decommissioning is likely to depend on when the fields cease to produce at economically viable rates. This in turn will depend upon future oil and gas prices, which are inherently uncertain.

27 Financial instruments

The Group's activities expose it to financial risks of changes, primarily in oil and gas prices, but also foreign currency exchange and interest rates. The Group does use derivative financial instruments to hedge certain of these risk exposures

Interest rate risk profile of financial liabilities

The interest rate profile of the financial liabilities of the Group as at 31st December was:

DKK 1,000	Fixed rate	Floating rate	Total
2013
DKK	0	103,058	103,058
Total	0	103,058	103,058
2012
DKK	0	78,000	78,000
GBP	0	0	0
USD	0	0	0
Total	0	78,000	78,000

The floating rate comprises bank borrowings bearing interest at rates set by reference to DKK CIBOR exposing the Group to a cash flow interest rate risk. The interest rate profile of the financial assets of the group as at 31s t December was:

Interest rate risk profile of financial assets

DKK 1,000	Fixed rate	Floating rate	Total
2013
Cash and short-term deposits:
Held in DKK	0	100,463	100,463
Held in GBP	0	4,089	4,089
Held in USD	0	48,488	48,488
Held in EUR	0	131	131
Held in NOK	0	31,443	31,443
Total	0	184,613	184,613
2012
Held in DKK	0	111,252	111,252
Held in GBP	0	19,261	19,261
Held in USD	0	111,211	111,211
Held in EUR	0	168	168
Held in NOK	0	629	629
Total	0	242,521	242,521

The floating rate cash and short-term deposits consists of cash held in interest-bearing current accounts by reference to DKK CIBOR.

Borrowing facilities

The Group had borrowing facilities of which the undrawn amount available at the year end was:

DKK 1,000	2013	2012
Expiring within one year	0	0
In one to five years	0	0
Over five years	0	0
	0	0

The Group has one two loans DKK 103.1MM (2012: DKK 105MM).

The fair values of the financial assets and financial liabilities are:

DKK 1,000	Carrying amount 2013	Estimated fair value 2013	Carrying amount 2012	Estimated fair value 2012
Primary financial instruments held or issued to finance the Group's operations:
Cash and short-term deposits	184,613	184,613	242,521	242,521
Bank loans and overdraft facility	-44,558	-44,558	-19,500	-19,500
Long term bank loan	-58,500	-58,500	-58,500	-58,500
Derivative financial instruments held or issued
to hedge the Group's exposure on expected future sales:
Forward commodity contracts – net	-914	-914	0	0

Fair value is the amount at which a financial instrument could be exchanged in an arm's length transaction, other than in a forced or liquidated sale. Where available, market values have been used to determine fair values. The estimated fair values have been determined using market information and appropriate valuation methodologies. Values recorded are indicative and will not necessarily be realised. Non-interest bearing financial instruments, accounts receivable from customers, and accounts payable are recorded materially at fair value reflecting their short-term maturity and are not shown in the above table.

Currency risk

No currency exposures were hedged during the year and thus there is a currency risk. Please see risk management section for currency risk exposures.

28 Deferred tax

DKK 1,000	2013	2012
Deferred tax liabilities	-267,003	-215,710
Deferred tax assets*	0	526
	-267,003	-215,185

	Faroese	Faroese	Overseas
DKK 1,000	hydrocarbon tax	Corporation tax	tax	Total
At 1s t January 2012	0	0	-60,886	-60,886
Charge to income	0	0	-140,443	-140,443
Exchange movements	0	0	-806	-806
Addition from Business combination	0	0	-10,712	-10,712
Tax losses utilised between subsidiaries	0	0	-2,863	-2,863
At 31s t December 2012	0	0	-215,710	-215,710
Charge to income	0	0	-57,714	-57,714
Exchange movements	0	0	6,422	6,422
At 31s t December 2013	0	0	-267,003	-267,003

*See note 12 for net defered tax assets not provided for.

29 Share capital

DKK 1,000	2013	2012
Balance at 1st January	262,670	262,670
Shares issued	105,000	0
Balance at 31st December	367,670	262,670

Ordinary Shares:

	2013	2013	2012	2012
DKK 1,000	100 DKK shares		100 DKK shares
Ordinary Shares:
Authorised	8,626,703	862,670	3,240,951	324,095
Called up, issued and fully paid	3,676,703	367,670	2,626,703	262,670

30 Own shares

DKK 1,000	2013	2012
At 1s t January	0	27,306
Acquired in the period	0	9,450
Sold in the period	0	-36,756
At 31s t December	0	0

Atlantic Petroleum acquired 52,500 and sold 183,014 of its own shares during 2012.

31 Analysis of changes in net debt/cash

DKK 1,000	Note	2013	2012
a) Reconciliation of net cash flow to movement in net debt/cash:
Movement in cash and cash equivalents		-57,907	0
Proceeds from short-term loans		-25,058	0
Proceeds from long-term loans	24	0	0
Increase/decrease in net cash in the period		-82,966	0
Opening net cash		164,521	9,345
Closing net cash/debt		81,555	9,345
b) Analysis of net cash/debt:
Cash and cash equivalents	24	184,613	242,521
Short-term debt	24,27	-44,558	-19,500
Long-term debt	24	-58,500	-58,500
Total net cash/debt		81,555	164,521

32 Capital comittments and guarantees

P/F Atlantic Petroleum has provided a parent guarantee to fulfil all obligations the wholly owned subsidiary Atlantic Petroleum (Ireland) Limited, has in connection with the sale and purchase agreement with ExxonMobil Exploration and Production Ireland (Offshore) Limited and the related Joint Operating Agreement regarding Irish Continental Shelf Petroleum Exploration Licence No. 3/04 (Frontier) relating to Blocks 44/18, 44/23, 44/24, 44/29 and 44/30.

P/F Atlantic Petroleum has provided a parent guarantee to fulfil all obligations its wholly owned subsidiary Atlantic Petroleum UK Limited has in connection with the share purchase agreement with the vendors of the entire issued share capital of Volantis Exploration Limited.

P/F Atlantic Petroleum has provided a parent guarantee to fulfil all obligations the wholly owned subsidiary of Atlantic Petroleum UK Limited, Volantis Exploration Limited, has in connection with the sale and purchase agreement with Iona Energy Company (UK) Ltd regarding UK licence P1606, block 3/3b and P1607, block 3/8d.

P/F Atlantic Petroleum has provided guarantees on behalf of Atlantic Petroleum Norge AS to the Norwegian government for liabilities relating to its exploration and appraisal activities.

P/F Atlantic Petroleum has provided guarantees on behalf of Atlantic Petroleum Norge AS to DnB the lender of the bank credit facility established in March 2013 to finance the Company's growth plans in Norway. P/F Atlantic Petroleum has provided a parent guarantee to fulfil all obligations Atlantic Petroleum UK Limited has in connection with the farm-in agreement with Summit Petroleum Ltd regarding UK Licence P1556, block 29/1c.

P/F Atlantic Petroleum has provided a parent guarantee to fulfil all obligations Atlantic Petroleum UK Limited has in connection with the purchase of assets from Premier Oil.

P/F Atlantic Petroleum has provided a parent guarantee to the UK Department for Energy and Climate Change in connection with Atlantic Petroleum UK Limited assets in the UKCS:

• (i) the parent will always provide necessary finance to enable Atlantic Petroleum UK Limited to fulfil its obligations in the UK area
• (ii) the parent will not alter Atlantic Petroleum UK Limited legal rights, so that the Company cannot fulfil its obligations
• (iii) the parent will undertake Atlantic Petroleum UK Limited financial obligations if the Company fails to do so

P/F Atlantic Petroleum has a senior secured loan agreement with P/F Eik Banki. The Company has offered the following security to lender in connection with the loan agreement:

• (i) shares in Atlantic Petroleum UK Limited
• (ii) receivables from Atlantic Petroleum UK Limited
• (iii) charge over proceeds from insurance coverage

The Company has provided lender with a negative pledge and investment in new ventures shall be endorsed by the lender.

The Group had capital expenditure committed to, but not provided for in these accounts at 31st December 2013 of approximately DKK 119.2MM. The capital expenditure is in respect of the Group's interests in its exploration and development production licences.

33 Contingent considerations

In addition to the payments to Iona Energy Ltd for 25% equity in Orlando and Kells, pursuant to the agreement, Volantis Exploration Limited has committed to pay:

• (i) USD 1.25MM upon Kells FDP approval
• (ii) Staged payments commencing six months after first production from Orlando of USD 1.8MM, USD 1.8MM, USD 0.925MM and USD 0.925MM made every six months thereafter respectively and
• (iii) A proportionate share of royalties payable to the previous owner of the Kells field, Fairfield Energy.

34 Related party disclosures

Intra-group related party transactions, which are eliminated on consolidation, are not required to be disclosed in accordance with IAS 24.

As part of the 2012 bonus of DKK 900,000 to the CEO he received in 2013 1,521 shares at a price of DKK 172.55.

Appraisal well	A well drilled as part of an appraisal drilling programme which is carried out to determine the physical extent, reserves and likely production rate of a field.
BOEPD	Barrels of Oil Equivalent per Day
BOE	Barrels of Oil Equivalent
BOPD	Barrels of Oil per Day
DECC	UK Department of Energy & Climate Change
DKK Danish kroner.	The currency used in the Kingdom of Denmark
EBIT	Earnings before Interest and Taxes (Operating Profit)
EBITDAX	Earnings before Interest, Taxes, Depreciation, Amortizations and Exploration Expenses
EBIT Margin	% (Operating Margin) (EBIT/Sales)
EBITDAX Margin	% (EBITDAX/Sales)
Exploration gas.	A general term referring to all efforts made in the search for new deposits of oil and
Exploration well	A well drilled in the initial phase in petroleum exploration
Farm out	A contractual agreement with an owner who holds a working interest in an area to assign all or part of that interest to another party in exchange for payment or fulfilling contractually specified conditions.
FDP	Field Development Plan
FPSO	A Floating Production, Storage and Offloading unit used by the offshore oil and gas industry for the processing of hydrocarbons and for storage of oil.
Gross Margin	% (Gross profit or loss/Sales)
Lead	Areas thought to contain hydrocarbons.
Ltd	A limited liability company
MM	Million
Monte Carlo	The Monte Carlo method approximate solutions to quantitative problems by employing statistical sampling that calculates a representative range of resulting values. Monte Carlo simulation results are pre-determined by the possible values of the underlying input variables, which can encompass multiply source of uncertainties.
NCS	Norwegian Continental Shelf
Net Cash	Cash and cash equivalents less Short & Long Term Debt

Oil field	An accumulation of hydrocarbons in the subsurface.
Prospect	An area of exploration in which hydrocarbons have been predicted to exist in economic quantity.
Return on Equity	(ROE) (%) (Profit for the period excl. Minorities/Average Equity excl. Minorities)
ROE	Return on Equity
Spud	To start drilling a well
TSR	Total Shareholder Return
Water injector well	A well into which water is pumped in order to increase the yield of adjacent wells
Wildcat	An exploration well drilled in an unproven area to find out whether petroleum exists in a prospect.

P.O.Box 1228 Yviri við Strond 4 FO-110 Tórshavn Faroe Islands Telephone +298 350 100 Fax +298 350 101 E-mail: petroleum@petroleum.fo www.petroleum.fo VAT/Tax No. Faroes 475.653 Reg. No. Faroes 2695

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