2. Disclaimer
Forward-Looking Statements
Certain information contained herein respecting the Company, the Company's properties or anticipated financial
results or performance of the Company or its properties constitutes forward-looking information. Such forward-
looking information, including but not limited to, statements with respect to anticipated rates of production, the
estimated costs and timing of the Company's planned work program and reserves determination involve many
known and unknown risks, uncertainties and other factors which may cause the actual costs and results of the
Company and its operations to be materially different from estimated costs or results expressed or implied by such
forward-looking statements. Such factors include, but are not limited to, risks related to international operations
including political risks, general risks associated with petroleum operations (such as commodity prices, production
delays, production costs, exchange rate fluctuations and environmental costs and risks) and risks associated with
equipment procurement and equipment failure. Although the Company has attempted to take into account
important factors that could cause actual costs or results to differ materially, there may be other factors that cause
costs of the Company's program or results not to be as anticipated, estimated or intended. There can be no
assurance that such statements will prove to be accurate as actual results and future events could differ materially
from those anticipated in such statements. The forward-looking statements contained herein are made as of the
date hereof and the Company undertakes no obligations to update or revise any forward-looking statements or
information, whether as a result of new information, future events or otherwise. Accordingly, readers should not
place undue reliance on forward-looking information.
2
3. 21 oil and gas licences
7 producing fields
9 potentially commercial
discoveries
Operator of 9 licences
Attractive Asset Portfolio
KEY FACTS:
• Diversified portfolio with exploration,
development and production assets in West
Africa, North Africa and the North Sea
• Oil production in West and North Africa,
average production of 4,800 bopd in Q2 2013
• 16 mmboe in 1P reserves, 23.5 mmboe in
2P reserves and 78 mmboe in contingent
2C resources
• Offices in London, Tunis and Stockholm
• Listed on NASDAQ OMX in Stockholm
Production
Exploration & Development
3
4. 4
Developments during first half 2013
• New Board of Directors and Management
• Initiated review of strategy, assets,
organisation and financing
• Short-term funding to be secured through
rights issue and planned new bond in
September/October
• Gunvor Group becoming major shareholder
with extensive industry expertise
• Farm-out in Tunisia signed, ongoing process
in Denmark and Congo
• Oil discovery and new field on stream in
Equatorial Guinea
6. Tunisia: Producing Didon and DST-fields
• Onstream since 1998, 31 mmbbl oil produced to date
• Farmed out 70% and operatorship to EnQuest. Hand-over
expected in Q4 2013.
• Current gross production of some 1,400 bopd (approx.
400 bopd to PA Resources after farm-out)
• Infill well(s) and ESPs to increase production and extend
field life
• Didon FSO-vessel currently undergoing recertification
programme, field shut down until late September
Licence Group: Operator EnQuest 70%, PA Resources 30%
6
Producing Didon field
• Douleb, Semmama and Tamesmida (DST) in production
since late sixties
• Current production around 400 bopd
• Facilities located at Douleb, export via 6” pipeline to Skhira
• Licences extended to 2035. Fields being reviewed.
Licence Groups:
Douleb: PA Resources 70%, Serept 30%,
Semmama: PA Resources 70%, Serept 30%,
Tamesmida: PA Resources 95%, Serept 5%
(Operatorship outsourced to Serept)
Producing DST-fields
Douleb &
Semmama
Tamesmida
Didon
7. 7
Congo – Azurite – The end of a sad story
PA Resources 35%
• Full field development reached in 2011 with the world’s
first FDPSO
• Disappointing production performance due
to severe reservoir problems
• Remedial sidetrack failed in early 2013
• Total field recovery now estimated at <17 mmbbl,
compared with the initial plan of 40-98 mmbbl
• Plans for abandonment are well-advanced.
Expected to commence in this year
• Final lifting in H2 2013 should cover most of
PA Resources’ share of abandonment costs
• Further costs and provisions possible
Licence Group: Operator Murphy Oil 50%,
PA Resources 35%, SNPC 15%
Azurite field
8. 8
EG – Aseng and Alen generate profitable barrels
PA Resources 5.7%
• Total field production of 37 mmbo since start
in November 2011 (2+ mmbo to PA Resources)
• Initial plateau level of 50,000 bopd, increased to around
60,000 bopd
• In April 2013 the field began coming of plateau,
average production of 50,000 bopd in Q2 2013 (2,850
bopd net to PA Resources)
• Production reduced due to increased associated gas
production having reached facility’s capacity
• Investments recovered in 2012, current investments
recovered almost immediately
• Field generates good cash flow with frequent liftings
Aseng field in Bock I – PA Resources 5.7%
Licence Group Block I: Operator Noble Energy 38%, Atlas
Petroleum 27.55%, Glencore 23.75%, PA Resources 5.7%,
GEPetrol 5%
Alen field in Bock I/Block O – PA Resources 0.29%
• Production start in Q3 2013, volumes being ramped up,
full operations expected in late Q3 2013
• Alen field contribution to PA Resources modest
(~100 bopd)
• Sharing of facilities and costs with Aseng, reducing
Aseng operating costs by some USD 3 million per year
for PA Resources
10. • Part of the farm-out to EnQuest
• Appraised discoveries with 7 wells drilled located in the
Gulf of Gabes within access to existing infrastructure
• Total gross recoverable hydrocarbons of c. 123 mmboe
(c. 40% liquids)
Zarat:
• The largest remaining Tunisian field to be developed,
total estimated recoverable hydrocarbons of approx.
120 mmboe
• Field shared with Joint Oil Block in the North.
Unitisation process expected to be completed soon.
• Estimated development costs of USD 13-18 per boe
• First oil expected in 2017
Elyssa:
• Appraisal well planned in 2014, potential development
plan based on access to existing infrastructure
• First gas possibly in 2016
• 2 additional undeveloped discoveries with tie-back
potential to existing/planned infrastructure
• Additional prospects and leads
Zarat and Elyssa fields
Tunisia: Zarat Permit - Zarat and Elyssa Fields
Zarat Permit
BRING
MAP
10
Elyssa
Zarat Field
11. Tunisia: Significant onshore exploration acreage
PA Resources – Jelma 70%, Makthar 100% and Jenein Centre 35%
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:
• Makthar and Jelma Permits surrounding
Douleb, Semmama and Tamesmida (DST)
fields
• Large exploration acreage in prospective
area (Makthar 4,052 km², Jelma 5,722
km²)
• Seismic programme in 2014 to mature
prospects and to identify deep potential in
Jelma
• Farm-out and drilling in 2014/15
• Jenein Centre:
» Discovery in Accacus play
» Importance/extend to be assessed
» Additional prospectivity,
» Commitments fulfilled for current period
(to 2015)
11
12. Congo – MPS: farm-out process
PA Resources 85%
• Following Murphy’s withdrawal, PA Resources
obtained additional 50% working interest and
operatorship in the exploration area
• Azurite Exploitation area part of the MPS PSC
(to be relinquished after abandonment)
• Second exploration phase extended until
November 2013, allowing time to assess
exploration potential and offering a farm-out to
industry
• Data room closed early August, visited by 14
Companies. Awaiting responses
• Decision in Q3 2013 whether to enter the third
and final exploration period (with a firm well
commitment) or to relinquish
12
Licence Group: Operator PA Resources 85%, SNPC 15%
Mer Profonde Sud – exploration licence area
Mer Profonde Sud area
Azurite field
13. EG Block I – Successful drilling campaign underway
PA Resources 5.7%
Progressing two exciting fields towards development
1. Carla North and South exploration/appraisal
» 2011 Carla North discovery in adjacent Block
O appraised in 2013 with additional oil
reservoir found
» Carla South exploration well in Block I and
its sidetrack encountered oil in two different
good quality sandstone reservoirs
» Implication of results being evaluated
2. Diega appraisal
» Appraisal well currently being drilled
» Plans to perform a long-term flow test
following the drilling of a horizontal reservoir
penetration
13
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
Diega
14. Denmark 12/06 – Two promising 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
decision in Q1 2014 on either appraisal drilling or to move
into development Front End Engineering Design (FEED)
• Ongoing discussions with owners of infrastructure within
reach for a potential tie-back
• Discovery established 35 API oil in Miocene sandstone
at c. 900m – exceptionally light oil for such shallow depth
• Further appraisal well(s) required
• Remaining deeper potential in Chalk and Middle Jurassic
• Efforts to locate available rig for appraisal drilling continue
for a 2014 drilling campaign
• Advanced negotiations for a farm-out of 40% interest to a
reputable operator
14
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
12/06 farm-out
15. Other North Sea assets: UK, Germany and Netherlands
15
• PA Resources operator with 100% in Bergman
(Fiddich) gas/condensate discovery
• Field discovered in 1984, flowed 15 mmscfpd
and ~1500 bcpd, studies commenced to assess
the economics of appraisal and/or development
• Initial discussions with potential candidate host
facilities to which the field could be tied back to
commence shortly
• Drill or drop decision before end of 2014
UK – Block 22/19a
• Adjancent to Danish licence 12/06
• Seismic 3D data acquired, evaluation progressing
Germany – B20008/73
• Q7-FA gas discovery offshore Netherlands
Netherlands – Block Q7, 10a and Schagen
Licence Group: PA Resources operator 100%
Licence Group: PA Resources operator 90%, Danoil 10%
Licence Groups: Operator Tulip Oil 30%,
Energie Beheer Nederland 40%, PA Resources 30%
17. Minimum funding requirements of SEK 1.7 billion
17
-0.8
Estimated funding need for H2 2013 and 2014 (SEK billion)
-0.8
-0.8
Assumptions for cash projection:
Minimum funding requirements Q3
2013 – Q4 2014 are based on:
• Best estimate of production
profiles
• Oil price level of USD 100
• Capex of some USD 100 million
(commitments for 2013-2014/5)
18. Short-term funding: Rights issue and new bond
18
• Shareholders with 17% holding/votes
committed to subscribe for pro rata share
• Remainder is underwritten by Gunvor Group,
Lorito Holdings and a Carnegie guaranteed
consortium
• Each existing share entitled to subscription for
3 new shares at SEK 10.50 per new share
• Final outcome - appr. 28% subscribed with
preferential right
• Gunvor Group, one of the leading global
energy commodities traders, new dominant
shareholder with just below 50% of the shares
and votes
• Undertakings in excess of SEK 500 million
secured from two institutional investors
• Terms for the bond undertakings similar to terms
for the current SEK bond but with a minimum
equity covenant of SEK 1,000 million instead of
SEK 2,000 million
• Waivers granted for both the NOK and SEK
bond and amendment of terms and conditions
• Bond to be issued in September/October
Fully underwritten rights issue
of SEK 890 million
New bond issue of up to
SEK 1,000 million
1 2
20. Medium to long-term Outlook
20
• A comprehensive review is currently undertaken
by the board and management
• Such review is not completed and therefore the
outlook presented can be subject to changes
• The objective is to present a realistic scenario
based on reasonable, not too optimistic
assumptions
• PA Resources has a relatively large, diversified
portfolio of assets, both in terms of geography
and maturity
• The portfolio contains several assets with a high
likelihood for production in the next few years
• A number of these assets are included in the
outlook for estimating future capex and
production levels
• However, a number of assets have not been
included, providing additional production upside
in the portfolio
A first scenario based on ongoing review Diversified portfolio with assets
21. Outlook scenario Key assumptions
21
Didon
Field* Continuing production with one in-fill well and successful ESP installations
Zarat
Permit*
Development of the Zarat and Elyssa fields in 2015-2017
(Capex includes the drilling of two committed exploration wells)
No ETAP back-in has been assumed (ETAP back-in would reduce projected
development costs and production level proportionally)
Block I
Continuation of the current production from the Aseng and Alen fields
Development of one notional additional field in Block I (e.g. Diega) with total reserves in
Block I of 30 mmboe in 2015-2017 (given results of recent wells, such additional
development is considered likely)
Denmark
12/06**
Development of only one of the two discoveries made, with assumed total field
reserves of 32 mmboe
Tunisia
onshore
The capex profile includes USD 23 million for committed exploration expenditures
onshore Tunisia in 2014 and 2015, no success and/or farm-out assumed
* 30% Equity after farm-out. Work programme from the new operator EnQuest not yet available, may lead to changes
** PA Resources’ working interest is assumed to be 24 per cent after farm-out (appraisal wells carried)
22. Investment outlook: Medium to long-term
22
Capital expenditure projection (MUSD) • Total capital expenditures of approx. USD
600 million until 2017
• Majority of capital expenditures are
related to development costs
• Successful rights issue in combination
with new bond loan expected to finance
plans until year-end 2014
• Further funding required after 2014
0
50
100
150
200
250
300
2013 2014 2015 2016 2017 2018
Projected Capex 2013 H1
23. Production projection: Medium to long-term
23
Production profile (boe per day) • The scenario entails an average
production of approx. 15,000 – 20.000
boepd in 2018 to PA Resources
• It includes the following assets to be
developed (PA Resources’ share of
reserves)
» Zarat field (13.7 mmboe in 2P and 6
mmboe in 2C), first oil 2017
» Elyssa field (16 mmboe in 2C),
first gas 2016
» Notional field in Block I (1.7 mmbo -
Diega or Carla South), first oil 2017.
» Notional field in Danish licence 12/06
(8mmboe - Broder Tuck or Lille John),
first production 2018
0
5 000
10 000
15 000
20 000
25 000
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Fields to be developed Currently producing
24. 24
• EnQuest’s track record suggests potential increase in
Didon reserves through enhanced recovery and
extended field live
• Over-performance of one or more developments (e.g. the
notional field development in Block I may well be larger
than assumed - well results point in this direction)
• Gas developments and sales in Block I
• Success in one or more ventures currently assumed
abortive, e.g.
» Only one development assumed in the North Sea, whereas PA
R’s portfolio has four discoveries in Denmark, UK and
Netherlands
» Successful farm-out of the MPS license
» Successful farm-out of and/or development(s) in the Tunisian
on-shore assets
ADDITIONAL UPSIDE
• The presented scenario
is relatively conservative
• Tangible upside not
considered
Potential projects not included :
Outlook scenario: Upside
