Atlantic Petroleum P/F — AGM Information 2014

Apr 9, 2014

Tórshavn – 9 th April 2014

ANNUAL GENERAL MEETING

• This presentation includes statements regarding future results, which are subject to risks and uncertainties. Consequently, actual results may differ significantly from the results indicated or implied in these statements
• No representation or warranty (expressed or implied) is made as to, and no reliance should be placed on, the fairness, accuracy or completeness of the information contained herein. Accordingly, none of the Company, or any of its principal shareholders or subsidiary undertakings or any of such person's officers or employees or advisors accept any liability whatsoever arising directly or indirectly from the use of this document

CHAIRMAN'S STATEMENT 2013

AGENDA

2013 – Progress and Challenges

• Production was roughly in line with expectations unplanned production downtime towards the end of the year
• Oil prices were stable at decent levels throughout the year
• Reserves increased significantly
• However, the financial result was not satisfactory, mainly because of costly unsuccessful exploration in 2013
• The Norwegian stock market entry so far only partially successful

The Strategy of Atlantic Petroleum

• Strategy unchanged: Atlantic Petroleum follows a sustainable model where oil production finances exploration and growth
• Going forward the focus will be on getting Orlando & Kells first oil as soon as possible and to get high impact exploration opportunities with limited downside exposure through creative commercial solutions and carry arrangements

The Challenges of Atlantic Petroleum

• Production from existing assets is gradually declining in 2014 and 2015
• Some uncertainty on the timing of new production 2015/16
• Atlantic Petroleum is well positioned
• Strong balance sheet
• Lots of oil in the ground
• Several high impact projects in the pipeline

OIL PRICES IN 2013

THE MARKET PRICE OF ATLANTIC PETROLEUM

AP VS. SMALL CAP DENMARK

AP VS. PEER GROUP

E&A WRITE-DOWNS PER ASSET

• The purpose of the Oslo listing and de-listing from Iceland
• To finance exploration in Norway
• To strengthen the balance sheet in preparation for Kells which improves borrowing terms for funding development assets
• Increase liquidity in the stock
• To increase more institutional investors
• To increase analyst coverage
• The listing has short term only been a partial success
• The balance sheet was strengthened with DKK 115m
• The company attracted a number of new institutional investors
• The number of analysts has increased from 1 to 3
• However the IPO was costly for existing shareholders, as
• The new investors craved a substantial discount to participate

• The Oslo listing will be positive for Atlantic Petroleum in the long term, as Oslo Stock Exchange has a strong E&P focus. We believe that when we deliver the market will deliver.

• Atlantic Petroleum is now covered by 3 analysts

• Nordea
• Carnegie
• ABG Sundal

Huge dispersion in valuations

• Nordea: 25/3-2014 (Sell DKK 92)
• Carnegie: 17/3-2014 (Buy NOK 200)

• ABG Sundal : 17/3-2014 (Buy NOK 190)

• Atlantic Petroleum is still well placed with:

• strong cash position
• lots of oil in the ground Largest reserves base ever
• several high impact projects in the pipeline set to double production over the next years

The way forward in 2014 – 2015

• Atlantic Petroleum will manage within its means
• A cautious approach until clear visibility on first oil of Orlando
• Atlantic Petroleum is currently not planning to revisit the market for equity capital
• Atlantic Petroleum plans to finance Orlando & Kells with Reserved Based Lending facilities from international banks, cash at hand and cashflow from operations
• Successful exploration or appraisal drilling may have an impact on the above
• Atlantic Petroleum needs to demonstrate exploration success
• The portfolio built up through the last 3 years has the potential to deliver
• The next few wells to be drilled are highly important

OPERATIONAL REVIEW 2013 & FORWARD PLANS

THIS IS ATLANTIC PETROLEUM

NW Europe exploration and production company

• 42 licenses on UK, Norwegian, Faroese, Irish and Dutch continental shelves
• Three producing fields
• One field under development; one approaching development sanction
• Average net production of 1,975 boepd in 2013
• Total reserves of 8.7 MMBoe¹

Small technical company– 30 employees

• Headquartered in the Faroe Islands
• UK subsidiary and technical office in London
• Norwegian subsidiary and technical office in Bergen

Listed on NASDAQ OMX Copenhagen & Oslo Stock Exchange

Market cap. DKK ~360MM

Licence overview

1) Source: GCA Competent Person's Report (CPR) End 2013

Low gearing, solid production base with significant exploration upside

SIGNIFICANT ACHIEVEMENTS IN 2013

Acquired High Value Barrels through the completion of the acquisition of 25% working interest in UK licenses P1606 and P1607 containing the development assets Orlando and Kells. Orlando development was approved by DECC in 2013.

Maximized the value of our existing assets

• One in-fill well drilled on the Ettrick field and one committed on the Blackbird field for Q2 2014
• Contract extension on Chestnut Field for a further Year (March 2016) and considering further extensions
• Successfully farmed into two high impact Norwegian licenses: PL 659 containing the Langlitinden and PL 528 containing the Ivory prospect

• Strengthened the balance sheet through an equity raise with net proceeds of DKK 115MM

• Listed on the Oslo Stock Exchange to attract a broader investor base and wider analyst coverage

• Exploration debt facility put in place with DNB in Norway for NOK 300MM
• Built exploration portfolio through licensing rounds:
• UK awarded a further 12 blocks in 4 licenses in the 27th Round bringing the total awards for the round to 23 blocks in 8 licenses
• Norway awarded 10 blocks in 4 licenses in the 22nd Licensing Round & Norwegian APA round

Key assets and reserves acquired, production life extended, high impact exploration added

RESERVES (CPR NUMBERS)

1) Source: Competent Person's Reports by Fugro Robertson (year 2009-2012) & GCA (year end 2013)

ORLANDO FIELD DEVELOPMENT

Orlando Field – UK Block 3/3b

Iona Energy 75% (Operator), Atlantic Petroleum 25%

Acquired in 2013 for \$30million plus future production payments of \$7.25million

CPR estimates

• Orlando net 2P reserves of 3.8 Mmboe
• NPV10 post tax stand alone \$63.1mm

High value barrels – Life of field capex and opex in the order of \$30 to 35/boe

Orlando initial rates expected at 10,000+ bopd.

First oil expected 2015/2016

Orlando FDP received government sanction on 17th April 2013. The execution of the Construction and Tie in Agreement with CNR is the next critical step

Orlando provides production growth in 2016 of high value barrels

ORLANDO FIELD DEVELOPMENT

Orlando Field

• Small field approximately 10km NE of Ninian Central Platform
• 1988 discovery by Chevron, appraised by two wells in 2011/2012
• High quality Brent reservoir with 18% porosity and 50mD permeability
• 32 degree API oil
• Large active underlying aquifer

Straight Forward Development plan

• Re-entry of the suspended appraisal well to be recompleted near horizontal with dual Electric Submersible Pumps
• The subsea facilities will be tied back to Ninian Central Platform
• Utilises existing topside equipment where-ever possible
• One contingent well subject to reservoir performance

Remaining net capital expenditure of approximately USD 60 million net of which USD46 million are spent prior to first well

KELLS FIELD DEVELOPMENT

Kells Field - UK Block 3/8b

Iona Energy 75%, Atlantic Petroleum 25%

Development plan

• Subsea tieback of one or two wells to Ninian Central Platform.
• Second well 18 months after first production
• Utilises existing topside equipment and shares Orlando modifications
• Flow assurance issues addressed by pipeline insulation (pipe in pipe)
• Total net remaining capital expenditure approximately \$50 million

CPR estimates

• Kells net 2P reserves of 2.25 Mmboe
• NPV10 post tax stand alone \$23.9mm

High value barrels – Life of field capex and opex in the order of \$30 to 35/boe

Kells initial rates expected at 7,000+ bopd. First production expected 2016/17

Kells provides production growth following Orlando

INDICATIVE PRODUCTION PROFILE

Production Profile 2014-2020 Assumptions

• Production profile beyond 2014 based on Gaffney Cline & Associates ("GCA") 2P reserves as of 31st December 2013
• Assumes Orlando first oil in 2015 and Kells first oil in 2016
• The operator of the Orlando field continues to push for 2015 first oil. However, our expectation is that first oil will slip into 2016
• 2015 and beyond are provided for illustration only. Budgets and forecasts beyond 2014 have not been finalised and are subject to a variety of factors

Atlantic Petroleum is set to more than double production

PERTH

Comments

Perth – P588 15/21b & 15/21c

Located in the UK sector of the Central North Sea

JV partners and interests:

• Parkmead Group (Operator) 52.13%
• Faroe Petroleum Limited 34.62%
• Atlantic Petroleum 13.35%

CPR Estimates

5.1MMBbl 2C contingent resources

Development Plans

• Several sour oil fields lie within the proximity of Perth however there are no facilities capable of producing these discoveries
• Parkmead are co-operating with Faroe Petroleum, the operator of the nearby Lowlander Field to develop both fields using the same facilities to minimise costs
• Considerable upside comes from adding further fields to the development
• A FDP was submitted in 2011 and agreed in principle by the authorities
• Parkmead and Faroes Petroleum are working towards submitting a joint FDP in 2015

Development of a sour oil hub has the potential to add significant value

Source: Faroe Petroleum

Unlocking the assets has potential to generate exceptional return

CHESTNUT

Chestnut – P354, Block 22/2a

Located in the UK sector of the Central North Sea

JV partners and interests:

• Centrica Energy Upstream (Operator) 69.875%
• Dana Petroleum (E&P) Limited 15.125%
• Atlantic Petroleum 15.000%

Wells

• 2 production wells
• 22/2a -11X started production in September 2008
• 22/22a-16Y tied to Chestnut facilities and started production in 2009 (water injection well in 2011)

Production and facilities

• Average production of 6,434 boepd in 2013
• FPSO "Hummingbird" leased from Teekay
• The contract for the Teekay Hummingbird FPSO has been extended to allow the field to produce to end 1Q 2016 and further extensions are expected in the near future

CPR Reserves Estimate

1.1 MMBoe (Net 2P reserves to AP)

Total production of 6,434 boepd in 2013

CHESTNUT: CONTINUED PERFORMANCE ABOVE EXPECTATIONS

• Production has increased over the last three years through increasing the choke size whilst monitoring for sand production
• Water Cut has stabilised just below 50%
• Ultimate Recoverable Reserves (URR) have consistently increased over field life (from annual CPR reports) and have the potential for further increase
• Net Remaining Reserves (NRR) are at same level as in 2007 (from annual CPR reports) and have the potential for further increase

Centrica / JV Actions

• Reservoir model being re-examined
• Hummingbird FPSO contract extensions
• Examining next phase of development

ETTRICK

Ettrick – P317 and P273, Blocks 20/2a and 20/3a

Located in the Moray Firth region of the UK North Sea

JV partners and interests:

• Nexen UK Limited (Operator) 79.73%
• Dana Petroleum (E&P) Limited 12.00%
• Atlantic Petroleum 8.27%

Wells

• 7 production wells and 2 water injections
• Production commenced in 2009 from the wells 20/2a-E1, 20/2a-E2z & 20/2a-E5
• E9 drilled in summer 2013

Production and facilities

• Average production of 9,792 in 2013
• FPSO vessel 'Aoka Mizu' leased from Bluewater
• FPSO contract extensions will be sought when field production performance and expectation allows the commitment to be made
• The field is expected to produce until late 2016 / early 2017 in the base case scenario

CPR Reserves Estimate

1.1 MMBoe (Net 2P reserves to AP)

Total production of 9,792 boepd in 2013

BLACKBIRD

Blackbird – P317, P273 and P1580, Blocks 20/2a, 20/3a and 20/3f

Located in the Moray Firth region of the UK North Sea

JV partners and interests:

• Nexen UK Limited (Operator) 90.60227%
• Atlantic Petroleum 9.39773%

Wells

• 1 production well and 1 water injector
• Subsea tie back to Ettrick; first oil in 2011
• 2nd production well planned for 2014 expect initial production rate between 6-8,000bopd

Production and facilities

• Average production of 2,121 boepd in 2013
• Tied back to Ettrick facilities
• The field is expected to produce until late 2016 / early 2017
• Ultimate end of production will depend on the combined Blackbird and Ettrick field performance

Reserves

0.4 MMBoe (Net to AP)

Total production of 2,121 boepd in 2013

Continued Investment has extended the life of Ettrick and Blackbird

FAROES EXPLORATION

• Through its regional knowledge, AP is pursuing the East Faroe ridge, the next ridge across from the Corona/Westray ridge system in the UK
• Significant discoveries in the UK play include Rosebank/ Lochnagar, Cambo, Tobermory
• The Brugdan II well will be a key data point in determining the future potential of the fairway

Is the Faroes the next extension of the West of Shetlands Plays?

FAROES L006 - BRUGDAN

JV partners & equities:

• Statoil (operator) 35%
• ExxonMobil 49%
• OMV 15%
• Atlantic Petroleum 1%

Area:

• Faroe Shetland Basin
• Extremely large four way dip closure with prognosed Palaeocene Vaila Formation reservoir

History:

• Brugdan I drilled in 2006:
• Failed to reach Vaila target
• Brugdan II drilled in 2012:
• Suspended due to onset of winter

Resources:

• Operator P50: 4.6 TCF
• CoSg 14%

Net Dry Hole Cost Exposure to AP

DKK 5MM

Large volume potential at low cost exposure

SNS CARBONIFEROUS PLAY FAIRWAY

• Atlantic Petroleum accessed considerable expertise and exposure to SNS, especially the emerging Carboniferous play fairway through its purchase of Volantis
• Several TCF of gas have been discovered in the Carboniferous play in recent years including the Pegasus (AP10%), Breagh, Crosgan and Cygnus discoveries
• AP has built a significant position in recent years to access the best opportunities to exploit this play

The Carboniferous play is relatively underexplored and offers volume potential

UK P1724 - PEGASUS

JV partners & equities:

• Centrica (operator) 55%
• Viking UK Gas (Third Energy) 35%
• Atlantic Petroleum (Volantis) 10%

Area:

• Southern North Sea, close to Cavendish Field and export routes
• Intra-Carboniferous structures, reservoirs & seals

Appraisal of 2011 Discovery:

• Pegasus North well drilled 2011 & discovered gas in Carboniferous Namurian sandstones
• Pegasus West well due to spud May 2014
• Drilled as a keeper well

Resources:

• Operator P50 for Pegasus complex: 198 BCF
• CoSg 30%

Net Dry Hole Cost Exposure to AP

DKK15MM (50% of our costs are carried by Centrica)

The Pegasus area offers the potential for near term gas production

NORWAY ENTRY

• Atlantic Petroleum's entry into Norway is for the long term
• Atlantic Petroleum fulfils the stringent requirements set by the Norwegian authorities to become a licensee in Norway
• A remote approach where a company does not build the proper organization and allocates the appropriate resources is not an option in Norway
• The time horizon is not to drill one well and decide or to see for one year and decide – Atlantic Petroleum is committed to exploring in Norway
• Norway is the most active exploration area in NW Europe and will remain so in the near future as other European areas become more mature
• The expanding portfolio will bring projects over the years to come that take Atlantic Petroleum into the next decade
• Exploration success in Norway makes companies

PL659 LANGLITINDEN

Blocks 7221/12, 7222/10,11,12, and parts of 7121/3, 7122/1,2 Det Norske 20% (Op), Petoro 30%, Lundin 20%, Tullow 15%, Rocksource 5%, Atlantic 10%

• Well 7222/11-2 was spudded January 14th and completed on 27th February 2014. The well was drilled with Transocean Barents within budget.
• The well encountered oil filled Triassic Kobbe Fm sands as prognosed. Core data, wireline logs and MDT fluid sampling proved the channel to be oil bearing, but the flow properties are lower than the expectations. The reservoir properties were also considered the main risk before drilling.
• APN's preliminary assessment suggest oil in-place above 200 MMbbls for the main target in Langlitinden. The license also contains the Caurus gas discovery in the Snadd Formation.
• Commerciality and remaining prospectivity of the licence, is being evaluated using the acquired well data and a new 3D seismic acquisition program is scheduled for this summer.

BUILDING A POSITION AROUND NEW INFRASTRUCTURE

PL5228 Ivory (Blocks 6707/8,9,11 and 6707/10 (part)) – Farm in 2013

See next slide

PL 763 Karius (Blocks 6606/2,3) – APA 2013 award

Repsol 40% (Op), Rocksource 30%, Atlantic 30%

• Several prospects and leads, and the main target is a robust structure associated with EM DHI.
• Short distance (15km) to the Aasta Hansteen SPAR

PL705 Napoleon (Blocks 6705/10 & 6704/12) – 22nd Round award

Repsol 40% (Op), Repsol 30%, Atlantic 30%

• Multiple structural closures with prospectivity at multiple levels
• Neighbouring license to the Asterix gas discovery and c. 70 km from Aasta Hansteen.

PL 704 Kjerag (Blocks 6705/10 & 6704/12) – 22nd Round award

Eon 40% (Op), Repsol 30%, Atlantic 30%

• Multiple structural closures with prospectivity at multiple levels.
• Neighbouring license to the Asterix gas discovery, and c. 70 km from Aasta Hansteen.

Gas export through the Polarled pipeline planned to be in operation from Aasta Hansteen to Nyhamna late 2016

Significant prospect inventory with multi TCF potential in vicinity of new infra-structure

PL528/528B NORWEGIAN SEA – IVORY

Blocks 6707/8,9,11 and 6707/10 (part)

Centrica 40% (Op.), Statoil 35%, Rocksource *20% (10-25%) Atlantic *5% (5-15%)

• Gross recoverable resources up to 306 MMboe
• Gas prone area with possibility for oil
• Adjacent to Aasta Hansteen field (2017 first gas)
• Seismic and EM DHI support
• Several other large prospects within the license with DHI support
• Earliest spud: Q3 2014 (West Navigator)
• Net cost exposure to AP DKK 7MM**

*) Atlantic Petroleum has an option to increase equity up to 15% **) Assuming AP stays at 5%

High impact exploration well with significant follow on potential

EXPLORATION PORTFOLIO – HIGH POTENTIAL PROJECTS

Significant portfolio inventory targeting material volumes

• It takes time to build up an exploration portfolio
• It takes resources capital and human resources to get into the right assets with the right partner companies – Largest operator of Atlantic Petroleum assets is Centrica
• Atlantic Petroleum has now got several opportunities in the portfolio where there is a possibility to farm out against a well carry – i.e. get high impact exploration opportunities with a low downside exposure
• With the approach where the company limits its exploration drilling programme to a low level of exposure within its means, Atlantic petroleum will ensure adding resources through the drillbit
• Stopping exploration is not an option It's a matter of having the right balance and exposure.

Portfolio has been built up and matured over the last years

MARKET PRICE

Atlantic Petroleum has a solid base of production set to grow in the years to come

KEEPING THE BALANCE FROM SHORT TERM TO LONG TERM

Atlantic Petroleum follows a sustainable and balanced approach

MARKET CONTEXT - OIL PRICE

Source: Pareto, March 2014

2014 ACTIVITY OUTLOOK & SUMMARY

LICENCE			2014
			1Q	2Q	3Q	4Q
n o orati pl x E	UK	P1724 Pegasus West (Committed)	Exploration well
	Norway	PL528 Ivory (Committed)	Exploration well
		PL659 Langlitinden (Committed)	Exploration well
	Faroe Islands	L006 Brugdan II (Committed)	Exploration well
n o cti u d o Pr	P317, P273, & P1580 Blackbird UK (Committed)
		Production well

• Orlando is sanctioned by the UK authorities and is a firm element in AP's forward programme. Kells planned for sanction in 2014

• The plan is to finance programme with a mix of debt, cash at hand and cashflow from operations
• AP will decrease administration cost in 2014 compared to 2013 with a further decrease in 2015
• AP will pursue high impact exploration opportunities with limited exposure through carried exploration
• Significant value triggers in the near term 1 additional production well & 3 exploration wells

FINANCIALS

• Revenues of DKK 417.4MM in 2013 (2012: DKK 596.7MM) - Average realised oil price in 2013 was USD 109.2 per barrel (2012: USD 112.3)
• Operating profit (EBIT) of DKK -1.6MM in 2013 (2012: DKK 246.8MM)
• Profit before taxation of DKK -11.6MM in 2013 (2012: DKK 227.7MM)
• Net cash flow from operating activities in 2013 of DKK 219.1MM (2012: DKK 367.6MM)
• Total assets of DKK 1,237.2MM (2012: DKK 1,121.8MM)
• Total equity of DKK 597.3MM (2012: DKK 537.1MM)
• Net production to Atlantic Petroleum was 720,000 boe in 2013 (2012: 928,000 boe)

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

DKK 1,000		2013	2012
Revenue		417,421	596,745
Cost of sales		-221,767	-274,888
Gross profit		195,655	321,857
Exploration expenses	Admin of Norwegian	-119,647	-27,209
Pre-licence exploration costs	assets subject to 78%	-11,064	-7,962
General and administration costs	tax refund. UK admin	-66,572	-39,930
Other operating income	goes against UK tax	0	14
Operating profit	position – 62%	-1,629	246,771
Interest revenue and finance gains		1,454	2,587
Interest expenses and other finance costs	-11,448	-21,700
Profit before taxation		-11,623	227,658
Taxation		-14,051	-160,998
Profit after taxation	-25,674	66,660
Earnings per share (DKK):
Basic		-9.54	26.68
Diluted		-9.67	26.54

DKK 1,000,000	End 2013	End 2012
Balance sheet
Total assets	1,237.2	1,121.8
- Cash and cash equivalents	184.6	242.5
Equity	597.3	537.1
Bank debt	103.1	78.0
- Long term	58.5	58.5
- Short term	44.6	19.5
	2013	2012
Cash flow
Net cash from operating activities	219.1	367.6
Net cash from investing activities	-408.8	-213.6
Net cash from financing activities	-135.4	-27.0

Net cash position at year-end 2013 amounted to DKK 81.6MM (2012: DKK 164.5MM)

DKK 1,000	2013	2012
Revenue	0	0
Cost of sales	0	0
Gross profit	0	0
Exploration expenses	-124	-9,080
Pre-licence exploration costs	-90	-703
General and administration costs	-20,593	-17,294
Other operating income	15,422	15,854
Operating profit	-5,386	-11,223
Interest revenue and finance gains	41	1,363
Interest expenses and other finance costs	-4,907	-6,742
Profit before taxation	-10,252	-16,602
Taxation	0	0
Profit after taxation	-10,252	-16,602

DKK 1,000,000	End 2013	End 2012
Balance sheet
Total assets	557.4	426.9
- Cash and cash equivalents	100.4	8.5
Equity	384.1	283.4
Bank debt	78.0	78.0
- Long term	58.5	58.5
- Short term	19.5	19.5
	2013	2012
Cash flow
Net cash from operating activities	1.6	-0.8
Net cash from investing activities	5.6	-94.2
Net cash from financing activities	84.8	34.8

Net cash position at year-end 2013 amounted to DKK 22.4MM (2012: DKK -69.5MM)

CONTACT

Headquarters, Faroe Islands

P/F Atlantic Petroleum Yviri við Strond 4 P.O.Box 1228 Faroe Islands Tel +298 350100

Norway office, Bergen

Atlantic Petroleum Norge AS Edvard Griegsvei 3c 5059 Bergen Norway Tel +47 99205989

UK office, London

Atlantic Petroleum (UK) Limited 26/28 Hammersmith Grove London W6 7BA United Kingdom Tel +44 20 8834 1045

Ben Arabo, CEO Tel +298 350 100 E-mail: ben.arabo@petroleum.fo