AGM 2013

PA Resources AGM 2013

Bo Askvik,

President & CEO

Stockholm, 14 May 2013

Today’s outline

2

Q1

>> FINANCIAL HIGHLIGHTS

Full-year 2012 and Q1 2013

>> RECAPITALISATION

Two step transaction

>> PA RESOURCES BUSINESS PLAN

Strategy and investment focus

>> OPERATIONAL UPDATE

Key assets and progress

Financials highlights

Q1

4

Production and sales in 2012 and Q1 2013

bopd Full-year

2012

Q1

2013

April

2013

West Africa 5,600 4,800 4,200

North Africa 2,300 2,000 1,900

Group Total 7,900 6,800 6,100

• ASENG: Production now off plateau level, affected

by limitations in gas handling capacity, overall field

oil rates on expected levels.

• AZURITE: Production continue to be affected by

by intermittent well instability.

• TUNISIA: Onshore production impacted by well

intervention, successfully completed in March

• PRICE: PA Resources realised price of USD 113

per barrel equal to Brent average

Average production per country (bopd)

Average sales price (USD/bbl)

97

109 106 104

120

109 109 106 113

106

117 113 109 119

108 109 110 113

20

40

60

80

100

120

140

Q12011

Q22011

Q32011

Q42011

Q12012

Q22012

Q32012

Q42012

Q12013

PA Resources Brent

0

2 000

4 000

6 000

8 000

10 000

Q12011

Q22011

Q32011

Q42011

Q12012

Q22012

Q32012

Q42012

Q12013

Congo: Azurite EG: Aseng Tunisia: Didon & Onshore

Earnings and key ratios

5

Q1 2013 Q4 2012 FY 2012 FY 2011

Production (bopd) 6,800 7,100 7,900 8,600

Oil price (USD/barrel) 113 106 111 103

Revenue (SEK million) 446 467 2,184 2,154

EBITDA (SEK million) 242 266 1,255 1,295

Profit before tax

(SEK million)* 131 -16 85 158

Profit for the period

(SEK million) 34 -340 -1,966 -2,084

Earnings per share (SEK)** 0.003 -0.04 -1.93 -2,67

* Figures for Q1 2013 exclude non-cash, one-off costs of SEK 21 million. Figures for Q4 and

full-year 2012, exclude non-cash, one-off costs of SEK 169 million respectively SEK 1,748 million.

** The righs Issue in February 2013 gave rise to retrospective adjustments

Capital expenditures and 2013 forecast

Actual Forecasted

Capex development and forecast (SEK million)

KEY COMMENTS

• Capex in Q1 amounted to SEK 58 million,

at the lower end of the forecast range

• Main part of Q1 investments relates to West

Africa/Azurite sidetrack

• 2013 forecast of SEK 250 – 380 million

unchanged assuming no farm-outs reducing

investments

6

1,613

255

58

250-380

0

200

400

600

800

1 000

1 200

1 400

1 600

1 800

2011 2012 2013

MS

EK

58

Cash flow

7

SEK million

Q1

2013

Q4 2012 FY 2012 FY 2011

Operating cash flow -70 175 838 812

of which income

taxes paid

-54 0 -5 -45

CAPEX -58 -186 -255 -1,613

Financing activities 359 65 -568 -408

Net cash flow 231 54 15 -1,209

KEY COMMENTS

• Operating cash flow of SEK -70 million

mainly relating to reduction of accounts

payable and other liabilities in connection

to Azurite sidetrack

• Income taxes of SEK 54 million relating

mainly to one-off payments in Tunisia and

Equatorial Guinea

• Capex of SEK 58 million, at the lower end

of the forecast range

• Righs issue of SEK 604 million, net after

transaction costs

• Amortisations of SEK 245 million in Q1

• Cash and cash equivalents at the end of

the period amounted to SEK 288 million

Recapitalisation

Q1

» Convertible bondholders offered to set-off their claim against newly issued shares at

SEK 0.15

» Approx. 90% of nominal amount converted into newly issued shares

» Equity increased with SEK 968 million and nominal debt decreased with SEK 890

million (net debt reduced by SEK 819 million)

Recapitalisation – two step transaction

Completed two-step transaction strengthened equity with approx. SEK 1.570 billion

Set-off issue

9

1

» Fully underwritten rights issue at SEK 0.10 (~50% to old shareholders and ~50% to

convertible bondholders)

» 51% of shares (3,570 million) were subscribed with preferential right

» Increases equity with SEK 604 million after transaction related costs and reduced net

debt with SEK 602 million

» Outcome of transactions resulted in changes in shareholder structure

Fully underwritten rights issue increased equity with SEK 604 million

2

Current equity and debt situation

10

KEY COMMENTS

• Recapitalisation restored Equity and

Book equity/Capital employed above

requirement in covenants

• Amortisations of SEK 245 million in Q1

• Net debt reduced to SEK 2,111 million

Equity and net debt before and after recapitalisation (SEK million)

Q1 2013 Q4 2012 Q3 2012 Covenant

Book Equity (SEK

million) 2, 201 1,590 956 >2,000

Book Equity to

Capital Employed 48% 37% 22% >40%

Net debt (SEK

million) 2,111 2,630 3,410 N/A

Covenants and Net Debt development

956

3,410

2,201 2,111

0

500

1 000

1 500

2 000

2 500

3 000

3 500

4 000

Equity Net Debt

30 Sept. 2012 31 March 2013

Reverse share split

11

SUMMARY

• The EGM on 9 April 2013 resolved in favour of a reversed share

split and a minor new share issue of 28 shares

• 500 present shares are consolidated into one share, with record

date 2 May 2013

• Shareholdings is rounded off downward, any excess shares will

come under the Company’s ownership and is thereafter sold

• Proceeds to be automatically distributed among the owners

• Following the reverse split the total number of shares in

PA Resources amounts to 28,291,998

Largest shareholders

12

The 10 largest shareholders

per 28 March 2013

Capital/

votes

GUNVOR GROUP LTD 9.9%

AVANZA PENSION 6.8%

CREDIT AGRICOLE (SUISSE) SA 3.8%

AB TRACTION 3.0%

NORDNET PENSIONSFÖRSÄKRING AB 2.8%

ÅGERUP FASTIGHETER AB 2.7%

LUX-NON-RESIDENT/DOMESTIC RATES 1.9%

JP MORGAN BANK 1.7%

SEB S.A. 1.7%

ORIGINAT AB 1.4%

10 largest shareholders 35.7%

Other shareholders 64.3%

Total 100.0%

NOMINATION COMMITTEE

• Sven A. Olsson (Gunvor Group Ltd),

Chairman of the Nomination Committee

• Bengt Stillström (AB Traction)

• Göran Ågerup (Ågerup Fastigheter)

• Hans Kristian Rød, Chairman of the Board

BOARD PROPOSAL

• Sven A. Olsson (Chairman - new)

• Philippe R Probst (Board member - new)

• Philippe R Ziegler (Board member - new)

• Paul Waern (Board member since 2009)

Operations update

Q1

Changes in Reserves and Resources 2012

14

Working

Interest

Net

Entitlement

End 2011:

Proven and probable reserves*

Production

Revision

1P/P90 2P/P50 1P/P90 2P/P50

39.1 60.2

-2.9

+1.9

-2.9

-1.6

-2.1

+1.3

-2.1

-1.4

25.9 40.4

End 2012: 38.1 55.7 25.1 36.9

* Reserves are classified accordingly to the SPE-PRMS 2007 guideline

KEY COMMENTS:

» Improved 1P to 2P ratio from 65 to 68%

» 1P reserves impacted by;

• Increase of 1P volume for the Aseng field

(1.03 mmboe) and the Tunisian fields (1.0

mmboe) based on production performance

• Reduction for Azurite of 0.15 mmboe

» 2P reserves impacted primarily by;

• Downwards revision of Azurite reserves by

2.9 mmboe on a working interest based

• Upwards revision of the producing Tunisian

fields (1 mmboe)

» Resources approximately unchanged

• Contingent resources of 142 mmboe (145)

• Risked prospective resources of 406 mmboe

(409) at a mid-case level

15

Licence changes and transactions 2012-2013

SUMMARY

• Tunisia: Small producing fields Ezzaouia and

El Bibane sold to Candax Energy

• Denmark: 9/95 Maja relinquished, 12/06 and 9/96

Gita extended with two years

• Congo: Marine XIV relinquished, PA Resources

working interest in MPS increased from 35% to 85%

• UK: Awarded new licence Block 22/19A in the 27th UK

licensing round (100%), Block 17/4b relinquished

• Germany: 10% of licence B20008-73 farmed out to

Danoil Exploration A/S

Capex forecast and drilling programme

DK: 12/06 Lille John 2013/2014 Appraisal/

Exploration/1-2

EG: Block I Carla South Ongoing Exploration/1

EG: Block I Diega 2013 Appraisal/1

EG: Block H 2013 Exploration/1

NL: Q7/10a Q7-FA 2013/2014 Appraisal/

Development/1

Tunisia: Zarat Elyssa 2013/2014 Appraisal/1

Tunisia: Makthar 2014 Exploration/1

Drilling programme/planned wells 2013-2014 Capex forecast 2013 includes:

• Drilling campaign ín Block I in EG, Carla

South exploration ongoing

• Drilling campaign on 12/06 high priority

• Drilling on 12/06, Block H and Q7/10a

dependent on rig availability

• Operational expenditures in producing

fields

• Elyssa well assumes successful farm-out

of Zarat licence

• The drilling programme is revised

continuously based on the capex budget

and prioritised commitments

16

EG Block I Aseng – Foundation asset for growth PA Resources 5.7%

• First oil from Aseng in November 2011, plateau level of

around 60,000 bopd sustained from March 2012 until

March 2013

• Total field production since start in November 2011 of

~31 mmbo + 1.8 million barrels to PA Resources

• Profitable barrels – foundation for future growth

» Investments of SEK 500 million recovered in 2012

» Opex per barrel will reduce after Alen commencement in

Q3 2013

» 6-9 liftings per quarter generate frequent cash flow

• 1P reserves upgrade substantially replaces 2012 production

• Field has come off plateau levels and production affected by

vessel’s gas handling capacity which operator is assessing

• Overall field oil rates on expected levels – reservoir

performance monitored

17

Licence Group: Operator Noble Energy (38%),

Atlas Petroleum Int. (27.55%), Glencore (23.75%),

PA Resources (5.7%), GEPetrol (5%)

EG Block I – Carla South oil discovery PA Resources 5.7%

• 2013 drilling programme with Atwood Hunter rig

in progress

• Progressing two exciting fields towards develop-

ment

1. Carla North and South

» 2011 discovery in adjacent Block O (Carla

North) appraised 2013 in Block O, where

operator has announced additional oil

reservoir found

» Carla South om Block I exploration well

spudded before Easter, oil discovery in good

quality sandstones at target level in late April,

well now being sidetracked to adjacent target

2. Diega

» Expect appraisal well and 3 to 4 week

production test in Block I Q3 2013

18

Licence Group: Operator Noble Energy (38%), Atlas Petroleum

(27.55%), Glencore (23.75%), PA Resources (5.7%),

GEPetrol (5%)

Block I Drilling program

Carla South

1 2

Congo – Potential in extended MPS-licence PA Resources 85%

• PA Resources granted additional 50% working

interest and operatorship, licence extended by

authorities until November 2013

• Prospect and lead inventory at various

stratigraphic levels

» Miocene (proven play)

» Albian (proven play on the shelf,

developing play in deep water)

» Possibly pre-salt (frontier play)

• Miocene inventory to be re-interpreted on the

2011 reprocessed 3D data which is better

suited to evaluation at this level

• Intention during extension period to seek

farmees/farmee operator to progress

exploration

19

Licence Group: Operator PA Resources (85%), SNPC (15%)

Mer Profonde Sud – exploration licence area

• Located in the Gulf of Gabes near large producing fields

(Ashtart, Miskar, Hasdrubal & Al Jurf)

• Extensively appraised discoveries with 7 wells drilled

• Zarat field the third largest liquids field found in Tunisia

and the largest remaining field to be developed

• Total gross recoverables of c. 170 mmboe (123 mmboe

net) and c. 40% liquids

Zarat AshtartJenein NordHasdrubalAdam Fields

Za

rat

fie

ld

Zarat and Elyssa Fields

• Onstream since 1998, 31 mmbbl oil produced to date

• Infill production wells and ESP’s evaluated as technically

feasible, to extend field production life cycle

BRING

MAP

20

Producing Didon Field

Top 10 remaining liquids fields in Tunisia

Tunisia – Overview Zarat permit PA Resources Operator 100%

» Tunisian gas deficit growing – more gas projects required

» Submit Unit Plan of Development for approval in Q2 2013

» Agree unitisation with Joint Oil Block

» Actively participate in Government infrastructure initiative

Zarat Field – Largest undeveloped field in Tunisia

1992 Discovery

2010-2011 ZRT-N1 Appraisal

1995 Appraisal Well

2011-2012 POD Update, Unitisation

2017/2018 First production

2013-2017 Development

2013 UPOD, UUOA

Gross

Recoverable

Volumes

• c. 80 mmbbl liquids

• c. 600 Bscf gas incl. inerts

• Largest undeveloped discovery in Tunisia

Subsurface

Aspects

Outlook - Forward Plan

• El Gueria fm reservoir

• 30m oil rim with > 70m rich gas cap

• 40° API oil, 53° API condensate

• Significant inert component in gas

Facilities and

Development

Aspects

Development Concept

• 40,000 bopd initial oil/cond. rate

• 200 mmscf/d initial raw gas rate

• 9 producer wells, 4 gas injectors

• Objective to maximise liquid recovery

• Plan assumes a 7yr gas recycling phase

• Followed by gas cap blowdown

• 25yr + production life

2005 PA Acquisition

1990 Permit Award

21

Tunisia: Significant onshore exploration acreage

Tunis

Sfax

4

3

1

2

Algeria Libya

Tunisia

1 Makthar Permit

Tunis

Sfax

4

3

1

2

Algeria Libya

Tunisia

Producing Asset

1

1 Jelma Permit

2

1 Douleb, Semmama

& Tamesmida

3

1 Jenein Centre Permit 4

Exploration Acreage

PA Resources onshore assets:

• Jelma-Makthar permits surround

producing Douleb, Semmama and

Tamesmida (DST) fields onshore Tunisia

• Both permits cover areas of 7,216 km²

and 3,828 km², contains several onshore

exploration prospects

• Successful exploration and production

history in the region, Serdj play proved

as working petroleum system for Douleb,

Semmama & Tamesmida fields

• Shell preparing drilling in adjacent

licence

22

Denmark 12/06 - Progressing discoveries PA Resources Operator with 64%

• High quality Middle Jurassic reservoir proved by wells

• Mid to high case assessment of c. 25-50 mmboe gross

of contingent resources including liquids

• Technical and commercial studies continuing towards a

year end decision point on either appraisal drilling or to

move into development Front End Engineering Design

(FEED)

• Ongoing discussions with owners of infrastructure for tie

back as one of range of possible development concepts

• Wells established 35 API oil in Miocene sandstone

at c. 900m – exceptionally light oil for shallow depth

• Remaining deeper potential likely – Chalk and Middle

Jurassic

• Efforts to locate available rig for appraisal drilling continue

in tight rig market

• Development options dependent on appraisal results –

successful appraisal could lead to tieback to nearby

infrastructure or standalone development

23

Licence Group: Operator PA Resources (64%),

Nordsøfonden (20%), Spyker Energy (8%), Danoil (8%)

B20008-73

12/06 Broder Tuck-2

Lille John-1

Broder Tuck

Lille John

Business plan 2013 - 2018

Q1

Attractive Asset Portfolio

25

22 oil and gas licences

6 producing fields

9 potentially commercial

discoveries

Operator of 11 licences

PA Resources’ strategy and focus

26

2013 - 2018

Development of

prioritised projects

with reduced risk

>> LONG TERM GROWTH

Development of ~ 32 mmboe for

long-term production growth

>> BALANCED INVESTMENTS

Farm-out of assets reducing invest-

ments and risk, financing from produc-

tion and debt financing at lower level

Business plan 2013 - 2018

27

Operating cash flow and

strengthened liquidity enables

maintenance, financing and

amortisations

» Cash flow from producing assets to finance operational expenditures at

the Aseng and Didon fields

» Strengthened balance sheet, in combination with new debt financing,

enables planned amortizations of bond loans and credit facilities

Lower interest reduces

the level of investment and risk

» Farm-out processes ongoing to reduce interest in prioritised assets

• Zarat license in Tunisia (Elyssa, Zarat and Didon)

• 12/06 in Denmark (Broder Tuck and Lille John)

» Reduced risk exposure to individual projects and share of investment

» Strengthened balance sheet enhances position for future transactions

Development of

prioritised assets for

long-term production growth

» Cash flow from producing fields combined with new debt financing

enables development of ~32 mmboe to production from 2016-2018

» Advance Broder Tuck in Denmark and Zarat in Tunisia towards into

development. Progress the appraisal of Lille John in Denmark , Elyssa in

Tunisia and Diega in EG towards development

» Maintain debt level near post-transaction level during investment phase

Selective exploration to further

expand the resource base

» Active and selective exploration activities to further expand the

discovered resource base - few scheduled commitment wells in the

coming two years

Developed reserves and resources after farm-out

28

MMboe 2P

Reserves

Contingent

Resources

Risked Prospective

Resources

Assets included

Didon, Azurite, Aseng

liquids, Alen, Zarat field

liquids, DST-fields

Block I, MPS, 12/06,

Zarat permit, Netherlands

Block I, Block H, MPS,

Zarat permit, Jelma,

Makthar, Jenein Centre,

Gita, 12/06, Block 8,

Netherlands, UK

Total per 2012.12.31 55.7 142 406

Whereof:

Tunisia: Zarat 43.9 29.3

Tunisia: Elyssa 42.2

Denmark: Lille John 9.1 9.1

Denmark: Broder Tuck 21.4

Total before farm-out 43.9 102.2 9.1

Developed 32 mmboe net

after farm-out 8.8 21.5 2.2

>> Business plan farm-out assumptions: Zarat licence from 100%

to 20%, Didon field from 100%% to 50% and 12/06 from 64% to 15%%

0

5

10

15

20

25

30

35

40

2013 2014 2015 2016 2017 2018

Producing Fields Fields to be developed

0

2 500

5 000

7 500

10 000

12 500

15 000

17 500

2013 2014 2015 2016 2017 2018

Producing Fields Fields to be developed

Expected outcome of Business Plan

29

Estimated development of reserves (mmboe) Estimated future average production (boepd)

32 MMBOE

32 mmboe

>> The foundation of the business plan is to

gradually increase production and reserves

Planned investments 2013 – 2018

30

KEY ASSUMPTIONS:

Development is not progressed until farm-out

successful

• Continued operational expenditures on

producing fields

• Development of existing reserves and

resources of 155 mmboe will after farm-out add

32 mmboe

• Farm-out of prioritised assets to reach

preferred working interest level and reduce risk

on individual assets

» Zarat licence from 100% to 20%

» Didon field from 100%% to 50%

» 12/06 from 64% to 15%

• Present operatorship in farm-out assets

secures development planning

• Oil price of 110 USD/bbl and USD/SEK of 6.53

Capex forecast 2013-2018 before and

after farm out transactions (SEK million)

1,613

255 170 270

540 590

230

520

680

970

300

0 0

200

400

600

800

1 000

1 200

1 400

1 600

1 800

2011 2012 2013E 2014E 2015E 2016E 2017E 2018E

PA Resources' share of investments Partners' share of investments

Expected outcome of planned development

31

KEY ASSUMPTIONS:

• Development of existing

reserves adding after farm-out

32 mmboe for long-term

production growth

• Debt maintained around

current level

• Expected net cash position in

2018

Estimated development of net debt

and average production

0

2 000

4 000

6 000

8 000

10 000

12 000

14 000

16 000

-1,0

0,0

1,0

2,0

3,0

4,0

5,0

2010 2011 2012 2013E 2014E 2015E 2016E 2017E 2018E

ba

rrels

pe

r da

y

SE

K b

illio

n

Net debt actual Production Net debt estimate

Thank you! Q1

Q2 Report on 14 August 2013