Mirabaud - APCL Research Note.pdf

African Petroleum

MIRABAUD Securities LLP 33, Grosvenor Place London SW1X 7HY, UK T +44 (0)20 7321 2508 F +44 (0)20 7930 4066 www.mirabaudsecurities.co.uk

Energy Research 8 June 2015

Buy

Bloomberg APCL NO Price (NOK/shr) 0.35 Target Price (NOK/shr) 0.88 Upside (%) 151% 12mth hi/low (NOK/shr) 1.65 / 0.18 Shares out (mill) 969.2 Fully diluted (mill) 1,133.1 Mkt Cap (US$m) 43.9 Enterprise Value (US$m) 20.3

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Resources Sales

Pav Sanghera +44 (0) 20 7878 3380 [email protected]

Harry Baker +44 (0) 20 7878 3401 [email protected]

Grant Barker +44 (0) 20 7878 3402 [email protected]

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Guy Wheatley +44 (0) 20 7878 3365 [email protected]

Resources Sales Trading

Lucas McHugh +44 (0) 20 7866 0085 [email protected]

Standing on the shoulders of giants


2

Contents

Investment case .............................................................................. 3

Corporate background .................................................................... 6

Asset overview ................................................................................ 8

Asset (i): Côte d’Ivoire .................................................................... 9

Asset (ii): Senegal and The Gambia ............................................. 14

Asset (iii): Liberia and Sierra Leone .............................................. 20

Funding ......................................................................................... 24

Valuation ....................................................................................... 26

Appendix 1: Valuation assumptions .............................................. 28

Appendix 2: West African Transform Margin ................................ 29

Appendix 3: West Africa – politics and economy .......................... 30

Appendix 4: Management & Board ............................................... 32


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Investment case

Standing on the shoulders of giants

African Petroleum (APCL) is an Oslo-listed explorer with a regional focus on West Africa.

The company’s strategic remit is to pick up early stage exploration assets ahead of the

pack, work up the prospectivity in house and then look to sell-down to the industry at a

premium in exchange for a carry through drilling. Much of the hard graft has been done

already. The company signed its first two licences offshore Liberia a decade ago and has

progressively expanded the portfolio, adding eight blocks in nearby Côte d’Ivoire, Sierra

Leone, Senegal and Gambia. It now presides over the largest net acreage position in the

prolific West African Transform Margin (WATM). Moreover, following an intensive period

of data gathering, APCL has acquired 3D seismic over all its licences and matured a drill-

ready prospect inventory with an estimated 12.5 bn bbls of net prospective oil resources

(independently assessed by ERC Equipoise).

Figure 1: APCL regional map and licences (in yellow)

Source: African Petroleum; Company data.

The primary focus for the company now is to close out an advanced, multi-asset farm-out

process. At the forefront of these talks are its Côte d’Ivoire and Gambia/Senegal assets

which have attracted a flurry of industry interest (due to proximal oil discoveries in 2014

by Total in Côte d’Ivoire and Cairn in Senegal – see Figure 1, above) and are poised for

drilling to start in late 2015-16. Despite a subdued farm-out market, we remain confident

that APCL will secure exploration funding on attractive terms (2 for 1, or better), providing

industry endorsement and line of sight on a near-term, high impact multi-well programme.

Moreover, in contrast to many small-caps, APCL has retained operatorship and control of

all its licences through the seismic acquisition phase, providing the flexibility to sell down


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without undue dilution to drilling. With an unrisked NAV of 47x the current share price, we

believe that the equity market is materially undervaluing the potential of the portfolio.

Accordingly, we reiterate our BUY recommendation with a NOK 0.88/shr price target.

Asset portfolio – heating up

Historically unexplored for hydrocarbons, the WATM region has yielded a number of

major oil discoveries in recent years – most notably offshore Ghana by Tullow, Kosmos,

Hess and partners (see Appendix 2 for WATM regional overview). Seeking to replicate

this success, APCL has pursued an aggressive exploration strategy investing some

US$433m across its portfolio since its Australian IPO in 2010. To date, most of APCL’s

time and financial resources have focused on Liberia, where it has drilled three

exploration wells (2011-13), proving the existence of a working petroleum system and

moveable light oil (32m of net oil pay) in variable quality sands with the Narina-1

discovery. While Liberia still holds interesting potential, further higher resolution 3D

seismic is required to better understand the sub-surface and APCL’s primary exploration

focus has shifted to its undrilled assets in Côte d’Ivoire and Gambia/Senegal.

APCL holds a 90% operated interest in two adjacent deepwater licences in Côte d’Ivoire

which lie in the west of the country, around 300km from existing oil production in the east.

This unexplored area received a major boost in 2014 with a play-opening oil discovery at

Saphir-1 (40m net oil pay) by Total/CNR in block CI-514, lying immediately to the east of

APCL’s acreage, and drilled in excess of 400m down-dip from the crest of the structure.

Alleviating uncertainty over source rock presence and maturity, the result proves an

active, oil prone system and materially de-risks the San Pedro basin. Encouragingly,

APCL has mapped a series of prospects in similar, Cretaceous age fan systems to

Saphir-1, including the 331 mmbbl Ayamé West prospect just ~20km away.

Moving eastwards, we also have high hopes for APCL’s acreage position in Senegal and

Gambia, where the group has 90%-100% operated interests in four contiguous licences.

This untapped area lies outside the core WATM trend and is geologically different with a

dominant carbonate shelf that extends into the offshore which has a major bearing on the

hydrocarbon potential. Like Côte d’Ivoire, a key breakthrough occurred in 2014 with two

consecutive oil discoveries by Cairn/Conoco/FAR in the Sangomar licence, the first ever

deepwater discoveries in this part of the margin. Moreover, the second well in the

sequence, SNE-1 (330 mmbbls), is potentially the world’s largest offshore oil find of 2014.

Ideally placed to leverage off this success, APCL holds all of the prospective acreage

around Sangomar, with similar structures mapped on 3D seismic. Of particular interest is

the 410 mmbbl Mahogany shelf edge clastic prospect, lying on trend with the SNE-1 find.

Farm-out discussions

APCL has formally opened a dataroom on its Côte d’Ivoire, Gambian/Senegal and

Liberian assets with a view to soliciting bids from farm-out partners. Thus far, the

company has negotiated two interim deals: (1) a 10% farm-out of CI-509 in Côte d’Ivoire

to Buried Hill for funding 21% of the next well, and (2) a term sheet for the sale of 50% of

LB-08 in Liberia on ground floor terms (the proposed partner is yet to be disclosed,

pending finalisation of contract terms). Whilst these transactions show industry interest in

the assets, APCL needs to secure further deals to fund the full cost of drilling – most

notably in Côte d’Ivoire and Gambia/Senegal to satisfy well commitments in Q4 2015-16.

We believe that APCL is strategically well positioned to attract industry capital, even in the

current environment, given recent discoveries surrounding its acreage and the amount of

running room. Additionally, the asset portfolio has a number of key commercial attributes:


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firstly, the cost of drilling is relatively low due to the benign drilling environment (no high

pressure / high temperature issues or challenging salt layers to drill through). A deepwater

well in APCL’s acreage is expected to cost ~US$40m, a fraction of the Gulf of Mexico or

offshore Brazil and Angola. Secondly, as an early entrant into the WATM, APCL’s

licences benefit from excellent fiscal terms compared to more recently awarded blocks in

the region and other deepwater frontiers around the globe.

Valuation case

We have calculated a sum of the parts valuation for APCL using a 10% discount rate and

a long-run Brent oil price of US$80/bbl flat nominal. Our Total NAV ascribes value to three

prospects (in Côte d’Ivoire, Gambia and Liberia), targeting combined gross prospective

resources of 925 mmbbls with chances of success ranging from 16% to 23%. To account

for future dilution, we have assumed in each case that a farm-out deal is secured on 2 for

1 terms halving APCL’s stake in exchange for a free carry on drilling. After adjusting for

corporate items, the result is a Total NAV of NOK 3.16/shr – with the largest contributor

being the 410 mmbbls Mahogany prospect in The Gambia (NOK 1.23/shr). As illustrated

in Figure 2, below, on an unrisked basis the three prospects each offer share price upside

of between 12-21x and success in any one case would unlock significant follow-on

potential.

Figure 2: Share price upside for key exploration prospects

12.1

21.2

13.1

2.8 3.5 2.1 0

5

10

15

20

25

Ayame West, Cote d'Ivoire Mahogany, Gambia Narina West, Liberia

Mul

tiple

of s

hare

pric

e (x

)

Unrisked NAV Risked NAV

Source: Mirabaud Securities estimates.

As it stands APCL shares currently trade at a hefty 89% discount to our risked NAV.

While this gap is likely to gradually narrow as funding is secured and drilling approaches,

in our experience risked NAV is a fairly poor indicator of market value in the pre-drill

stage. As such, we have set our target price at NOK 0.88/shr which is based on invested

capital in Côte d’Ivoire and Gambia/Senegal (of US$111m) and offers over 150% upside.


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Corporate background

The past and the present

African Petroleum’s origins date back to 2005 when European Hydrocarbons (EH), an

entity controlled by Frank Timis (26% APCL shareholder), was awarded an interest in LB-

08 and LB-09 in partnership with Regal Petroleum. As part of a reorganisation, the assets

of EH were purchased by APCL which was then listed on Australia’s National Stock

Exchange (NSX) in 2010 via a reverse takeover of shell company Global Iron Limited.

Following the IPO, APCL’s asset portfolio was expanded to include exploration acreage in

Senegal, Gambia, Côte d’Ivoire and Sierra Leone, targeting a common WATM theme.

The company’s first exploration well was drilled in 2011 in wholly-owned Liberia LB-09

(dry hole) and two further Liberian wells were drilled in 2012/2013 resulting in a non-

commercial oil find. Figure 3, below, shows APCLs key corporate events since inception.

Figure 3: African Petroleum corporate timeline

Date Activity

Jun 2005 European Hydrocarbons (EH) and Regal awarded LB-08 & LB-09, Liberia.

Nov 2007 EH acquires Regal’s 25% interest in Liberia blocks 8 & 9 for a nominal sum.

Jan 2010 European Hydrocarbons acquired by APCL in corporate reorganisation.

Jun 2010 APCL lists on Australia’s NSX raising A$222m at A$0.55/shr.

Aug 2010 African Petroleum farms into 60% of Buried Hill’s Gambian blocks A1 & A4.

Feb 2011 Sierra Leone parliament ratifies award of Block SL-03.

Jul 2011 A$250m equity placement at A$1/shr.

Sept. 2011 Apalis-1 in Liberia LB-09 encounters oil shows, target reservoir absent.

Nov 2011 Senegal licences Rufisque Offshore and Offshore Sub Profond awarded.

Dec 2011 Offshore Côte d’Ivoire block CI-513 awarded.

Feb 2012 Oil discovery announced at Narina-1 well – 32m of net, light oil pay.

Mar 2012 Second Côte d’Ivoire block CI-509 awarded.

Jul 2012 A$85m equity placing at A$1.35/shr.

Jul 2012 MoU signed with PetroChina over possible investment (lapsed without deal).

Sept 2012 Block SL-4A-10 awarded offshore Sierra Leone.

Feb 2013 Bee Eater-1 well results – oil shows, target reservoir absent.

Nov 2013 Two year extension of SL-03 licence ratified by Sierra Leone Government.

Feb 2014 Dr. Stuart Lake appointed as CEO, formerly VP of Exploration with Hess.

Feb 2014 Liberia LB-08 & 09 granted two year extension; two well commitment deferred.

Feb 2014 A$20m raised at A$0.24/shr.

Apr 2014 First exploration periods on CI-513 & 509 Cote d’Ivôire extended by one year.

May 2014 Lists on Oslo Axess, raising NOK49m (US$8m) at NOK1.3/shr / A$0.24/shr.

Jul 2014 Farm-out agreement signed with Buried Hill for 10% of CI-509, Côte d’Ivoire.

Aug 2014 US$13m loan made to NSX-listed International Petroleum converted into equity.

Nov 2014 Gambian blocks reinstated with extended term and deferred drilling obligation.

Dec 2014 SOSP enters First Renewal Period, well commitment deferred for 18 months.

Dec 2014 Term sheet signed with undisclosed party for 50% farm-out of LB-08, Liberia.

Mar 2015 NOK99m (US13m) equity placing at NOK0.35/shr.

Source: African Petroleum.

The arrival of former Hess VP of Exploration Stuart Lake as CEO (see Appendix 4 for

management biographies) in early 2014 has ushered in a new era and change of strategy

away from drilling sole risk wells. In May 2014, APCL listed on the Oslo Axess Exchange

in Norway, a more recognised trading platform with deeper liquidity. Additionally, under

new leadership, a number of corporate issues have been tidied up, including a backlog of


7

licence commitments (which have been deferred) and a soured loan to International

Petroleum (which has been converted into equity resulting in APCL owning 14% of the

Niger-focused explorer). In parallel, APCL has reinvigorated farm-out talks with a view to

securing exploration funding, sealing interim deals in Côte d’Ivoire and Liberia thus far.

And lastly, the company successfully negotiated the reinstatement of its Gambian

licences with the Government for an extended two year term.


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Asset overview

Licence summary

APCL currently has majority interests and operatorship of ten exploration licences

offshore West Africa, two in each of Côte d’Ivoire, Gambia, Liberia, Senegal and Sierra

Leone. The portfolio covers a combined area of 32,200km2 (gross) along the West African

Transform Margin (WATM) – a prolific deepwater Cretaceous play fairway uncovered in

2007 by Tullow Oil’s discovery of the Jubilee oilfield offshore Ghana (see Appendix 2 for

WATM background). As an early entrant into the under-explored deepwater, APCL

controls one of the largest net acreage positions in the WATM region, rivalling industry

heavyweights including Chevron and US-independent Anadarko. Figure 4, below, shows

a summary of the company’s asset portfolio and exploration activity carried out to date.

Figure 4: African Petroleum licence activity

Country Licence name WI‡ Partner Oil resource¥ Licence activity

Côte d’Ivoire CI-509* 90%1,2 Petroci 2,367 mmbbls

4,200 km2 3D seismic completed. 1 well obligation on CI-513 by Dec 2015

and also CI-509 by Mar 2016. Agreed 10% farm-out of CI-509 to Buried Hill. CI-513* 90%1 Petroci

Gambia A1* 100%1 - 3,078 mmbbls

2,500 km2 3D seismic survey completed. 1 well commitment on A1 or A4 by

Sept. 2016. A4* 100%1 -

Liberia LB-08* 100% - 4,192 mmbbls

5,100 km2 3D seismic survey completed. Three wells drilled in LB-09. Agreed

terms for 50% farm-out of LB-08. 3D seismic commitment by June 2016. LB-09* 100% -

Senegal ROP* 90%1,5 Petrosen 1,977 mmbbls

5,100 km2 of 3D seismic completed / reprocessed. 1 well obligation on ROP

by Oct. 2015. Drill or drop decision on SOSP in Apr. 2016. SOSP* 90%1,5 Petrosen

Sierra Leone SL-03* 100%3 - 1,354 mmbbls

Acquired 2,500 km2 of 3D on SL-03 and 1,000 km2 on SL-4A-10. ‘Contingent’

one well commitment on 4A-10 by Sept. 2015 and SL-03 by April 2017**. SL-4A-10* 100%3,4 -

Source: African Petroleum, ERC Equipoise. *African Petroleum operated. **Contingent on technology being available to drill in ultra-deep water >3,000m (i.e likely to be deferred). ¥Gross mean unrisked prospective resources (on block only). ‡APCLs current, undiluted working interest.1Government has back-in rights to acquire a 10% paying interest in the licence. 2APCL has agreed to farm-out 10% of its 90% WI to Buried Hill. 3Government has back-in rights for a 10% carried interest. 4Government has back-in rights for an additional 5% paying interest. 590% interest is held by African Petroleum Senegal, owned 90% by APCL and 10% by Prestamex.


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Asset (i): Côte d’Ivoire

Côte d’Ivoire’s oil industry is well established by WATM standards and its proximity to the

Jubilee field offshore Ghana ranks it amongst the most prospective (see Figure 5, below).

Hitherto seen as less attractive than the producing east, APCL has two licences in the

country’s unexplored western margin, where a play opening oil find by Total in 2014 has

prompted a rethink. Located immediately adjacent to Total’s Saphir-1 discovery, APCL is

ideally placed to prosper with 2.4bn bbls of prospective resources in similar fan prospects.

Asset overview

APCL owns 90% of two adjacent deepwater blocks (CI-513 and CI-509) offshore Côte

d’Ivoire in partnership with the state oil company Petroci which has a 10% carried interest

(see Figure 5, below). The licences cover a combined area of 2,537 km2 and lie in water

depths ranging from 917 to 3,259 metres. Awarded in 2011 and 2012 respectively, CI-513

and CI-509 are in the first exploration phase and each carry a one well commitment (by

December 2015 and March 2016) which APCL plans to fund through industry farm-outs.

Figure 5: Côte d’Ivoire licence overview

Licence summary

CI-513 APCL 90%‡

CI-509

Partners: Petroci 10%*

Water depth: 917-3,259m

Work to date: 4,200 sq km 3D seismic**

Well commitments: 1 well Dec 2015 (CI-513)

1 well Mar 2016 (CI-509)

Audited resources: 2,367 mmbbls gross†

Source: African Petroleum. ‡Undiluted interest. Petroci has an optional 10% back-in right on both licences and a further 10% of CI-509 has been farmed

out to Buried Hill (yet to complete). †ERC Equipoise (Jan 2015) gross unrisked mean prospective resources (on block only). *Petroci has a 10% fully

carried interest + back in rights for a further 10% paying interest. **Includes seismic data acquired over nearby CI-508 operated by Vitol.

As part of the ongoing partnering process, in July 2014, APCL signed a 10% farm-out

agreement with Buried Hill on CI-509. Under the terms of the deal, Buried Hill is

committed to funding 21.1% of the cost of the next exploration well, subject to the

transaction closing. On signing of the deal the pair agreed to a backstop date of 1

November 2014 which has been extended to allow time for certain conditions to be met.

Regional context

Côte d’Ivoire is a modest hydrocarbon producer with oil production of ~40 kbopd from a

cluster of near-shore fields located in the east of the country which lie around 300km from

APCL’s licences in the west. Following the Jubilee discovery by Tullow in neighbouring

Ghana (in 2007), the industry has shown increasing interest in Côte d’Ivoire’s unexplored

deepwater potential. In 2011, a consortium led by Lukoil drilled the Independence-1

exploration well (see Figure 6, below), finding 8m of net hydrocarbon pay in good quality

Turonian sands. This was followed in 2012 by Anadarko’s Paon-1 well which found 31


10

metres of oil pay in similar age reservoirs. Both of these discoveries are now under

appraisal, with Anadarko rumoured to be readying itself for a commercial development.

Figure 6: Côte d’Ivoire’s eastern producing region and key deepwater discoveries

Source: RPS Energy, Vioco.

APCL’s licences are located in the San Pedro area of the Ivorian basin offshore Côte

d’Ivoire where there has been little historic exploration activity. The hydrocarbon potential

of this region received a major boost in 2014 when Total and partner CNR announced a

breakthrough light oil discovery immediately to the east of APCL’s acreage (see Figure 7,

below). The Saphir-1 well in CI-514 encountered a series of thick Upper Cretaceous

sands (350m) with ~40m of net oil pay (34º API). In our opinion, this event was hugely

significant being the first discovery in the San Pedro basin and proving a mature, oil prone

source rock which had previously been cited as a key technical risk in this part of the

margin (due to the relatively shallow depth of burial of the prognosed Cretaceous source).

Furthermore, we understand that Saphir-1 was boldly located some 400m down-dip of the

crest of the structure, confirming that the stratigraphic trapping mechanism in this area is

capable of holding a substantial oil column without breaching.

Figure 7: APCL’s CI-509 and CI-513 blocks and Total’s Saphir-1 discovery in CI-514

20 km

Buyo

Fan

Sassandra

Fan

Cavalla

Fan

Ayame

Fan

Leraba

Fan

Nono

Fan

CI-508

CI-509

CI-513

Saphir

Fan

Saphir-1XB

CI-514

20 km20 km

Buyo

Fan

Sassandra

Fan

Cavalla

Fan

Ayame

Fan

Leraba

Fan

Nono

Fan

CI-508

CI-509

CI-513

Saphir

Fan

Saphir-1XB

CI-514

A

A

A

A



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Total has stepped up its activities in CI-514 and recently drilled an exploration well called

Rubis-1 targeting a different play to Saphir-1. According to partner CNR, the well has

been plugged and abandoned and the results are currently being evaluated (no further

public information is available at present). Additionally, we understand that Vitol – which

operates CI-508 in board of APCL’s CI-509 – plans to drill its first exploration well in late

2015-2016 targeting an Albian-age reservoir objective. Interestingly, Exxon has also

entered the country after 32 years of absence (in November 2014), picking up ultra-

deepwater blocks CI-602 and CI-603 lying outboard of Total’s licences (east of APCL) in

water depths of 3,000-4,000m.

The search for analogues

In 2012 APCL completed an extensive 3D seismic shoot over CI-509 and CI-513,

acquiring 4,200 km2 of data in a regional survey with Vitol including the adjacent CI-508

licence. Importantly, on completion, the company pre-traded the seismic dataset over its

own licences with Total’s on CI-514 – sight of the Saphir-1 discovery (as well as Vitol’s on

CI-508). Using this information, APCL has identified a series of large, similar-looking

Upper Cretaceous fan systems running along the margin with clear feeder channels

acting as the conduit for the sands (see the seismic amplitude map in Figure 8, below).

Figure 8: Total’s Saphir-1XB oil discovery and basin floor fan prospects in CI-513


APCL has mapped multiple, large stratigraphic and stratigraphic-structural Cretaceous

age prospects at the Turonian level (primary objective, proven at Saphir-1) with upside

potential in the Santonian, Cenomanian, Albian and Aptian. The play types across CI-513

and CI-509 can be split into three discrete categories: (1) up-dip feeder prospects (such

as Nzi, Lobo and Soubre, see Figure 8, above), with a similar trapping style to the Saphir-

1 discovery, comprising up-dip pinch out against impermeable basement (see green

dashed line in Figure 8, above). (2) slope prospects (such as Sassandra and Cavalla),

down-dip of the feeder prospects, which pinch out against a major structural step (caused

by a strike slip fault) that intersects CI-513 and CI-509 (3) large basin floor fan prospects

further out-board, with structural-stratigraphic trapping styles, such as Ayamé and

Agnéby. ERC has conducted an audit of the top nine prospects in CI-513 and CI-509

ascribing 2.4bn bbls of gross prospective resources (see Figure 9, below) based solely on

the Turonian potential (although drilling will likely see multiple stacked zones tested with a

single well, intersecting shallower Santonian and deeper Cenomanian and Albian sands).


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Figure 9: Côte d’Ivoire prospect inventory – January 2015

Prospect Licence Reservoir¥ Play type Water depth

Gross,

unrisked† WI‡

Net,

unrisked† CoS

Net,

risked†

Meters Mmbbls % mmbbls % mmbbls

Ayamé CI-513 Turonian Basin floor 2,560 558* 90% 502 23% 116

Ayamé W. CI-513 Turonian Basin floor 2,930 331* 90% 298 23% 69

Lobo East CI-513 Turonian Feeder 2,100 101 90% 91 20% 18

Lobo West CI-513 Turonian Feeder 2,100 142 90% 128 17% 22

Nzi CI-513 Turonian Feeder 2,000 103 90% 93 16% 15

Cavalla CI-513 Turonian Slope 2,300 190 90% 171 16% 27

Soubre CI-513/509 Turonian Feeder 2,100 288* 90% 259 19% 49

Sassandra CI-513/509 Turonian Slope 2,500 194* 90% 175 16% 28

Agnéby CI-509 Turonian Basin floor 2,560 460 90% 414 27% 112

Total 2,367 2,130 456

Source: ERC Equipoise. †Mean prospective oil resources. ‡Current working interest, prior to Government back-in. *APCL block resources only; prospect

partially extends onto third party licence. ¥Upside in other Cretaceous age reservoirs is excluded from ERC’s resource estimates.

In CI-513 APCL has prioritised the Ayamé fan system (located in water depths of 2,560-

2,930m), a large Upper Cretaceous basin floor fan covering some 370 km2. The primary

target is a stratigraphic pinch out in the Turonian (see seismic line in Figure 10, below) –

the oil bearing horizon in Saphir-1 – with additional upside in the underlying Cenomanian

section. APCL’s auditor ERC has ascribed resources to two separate traps within the

wider fan system, namely Ayamé (558 mmbbls) and Ayamé West (331 mmbbls), both of

which carry a 23% chance of success. With reservoir and charge de-risked by the

neighboring Total find, we view the integrity of the stratigraphic trapping mechanism as

the key geological uncertainty. That said, seismic data (over both Ayamé and Ayamé

West) shows a clear thinning and pinch out of the reservoir up-dip (see Figure 10, below,

for Ayamé West) with good amplitude support (higher amplitudes in the up-dip trap

position) that may be indicative of hydrocarbon presence. Furthermore, while the

amplitude response is yet to be calibrated, we understand that APCL is in talks to trade

offset well data ahead of drilling in order to address this concern.

Figure 10: Seismic line over the Ayamé West prospect in CI-513

2.5km

Ayame West-1

Top Ayame West- Turonian

Reservoir Pinchout


Turning to CI-509, APCL’s favored drilling location is the Agnéby prospect (formerly

Leraba, as shown in Figure 7, above) in 2,500m of water. Agnéby is a stratigraphic pinch

out trap with stacked potential in Santonian, Turonian and Cenomanian sands. ERC has


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ascribed the Turonian target 460 mmbbls of gross prospective resources and a chance of

success of 27%. Like Ayamé, we believe that trap integrity is the main geological concern,

however, some reassurance is provided by the well-defined pinch-out and amplitudes that

appear to shut off at a common depth (as shown in the AVO analysis in Figure 11, below).

Figure 11: AVO analysis – Agnéby prospect, CI-509


Pending a successful farm-out, the most likely well to be drilled first is the Ayamé West

prospect which is located adjacent to Saphir-1 and would fulfill the forthcoming well

commitment on CI-513 (end December 2015). While the drilling schedule would need to

be agreed by any incoming partner, in theory, once the funding is in place APCL could

spud a well within 3 months given current deepwater rig availability and the fact that long

lead items are secured and environmental permits submitted. In terms of costs, we

estimate that a well on Ayamé West would likely come in at around US$40m gross.


14

Asset (ii): The Gambia and Senegal

Originally seen as the poorer cousin, industry interest in the Senegalese and Gambian

margin has surged in recent months following Cairn’s FAN-1 and SNE-1 oil discoveries in

Senegal and Kosmos’s giant Tortue gas find on the Mauritanian border. Ideally placed to

benefit, APCL controls the acreage around Cairn’s Sangomar Deep discoveries with look-

a-like prospectivity and substantial running room, with some 5 bn bbls of gross resources

(as independently assessed by ERC Equipoise).

Asset overview

APCL operates a large contiguous deepwater position offshore Gambia and Senegal

covering a combined area of ~18,500km2 (as shown in Figure 12, below). The portfolio

comprises 90% working interests in two Senegalese blocks, namely Rufisque Offshore

Profond (ROP) and Senegal Offshore Sud Profond (SOSP), held in partnership with the

State oil company Petrosen (10%). These licences were awarded to APCL in 2011 and

include a one well commitment on ROP by October 2015 (which is the subject of

extension talks with the authorities following an 18 month deferral on the SOSP licence).

Figure 12: Gambia & Senegal licence overview

Senegal

Rufisque Offshore Profond (ROP) APSL 90%*

Senegal Offshore Sud Profond (SOSP)

Partners: Petrosen 10%**

Water depth: 1,000-4,000m

Work to date: 3,600 sq km 3D seismic (SOSP)

Well commitments: 1 well by Oct 2015 (ROP)


Gambia

Licence A1 APCL 100%

Licence A4

Partner: None


Work to date: 2,500 sq km 3D seismic

Well commitments: 1 well by Sept. 2016.


Source: African Petroleum. †ERC Equipoise (Mar 2015) gross unrisked mean prospective resources (on block only). *African Petroleum Senegal Ltd,

owned 90% by APCL and 10% by Prestamex, holds 90% of ROP and SOSP. **Petrosen has optional back-in right for a further 10% paying interest.

APCL also holds 100% of the A1 and A4 blocks located on Gambia’s narrow strip of

coastline, in between the ROP and SOSP licences. APCL was re-awarded 100% of A1

and A4 in November 2014 with an extended initial exploration term lasting until

September 2016, by which time one well must be drilled on either block. The company

first became interested in the blocks in 2010 via a farm-in with Buried Hill under which

APCL agreed to pay for 80% of a 3D seismic survey and one well in exchange for a 60%

interest. The initial exploration term then lapsed before the well was drilled and the


15

licences were purportedly revoked by the authorities, leading APCL to initiate arbitration

proceedings. This arbitration was subsequently dropped when the blocks were reinstated

with APCL as sole owner.

Regional context

APCL’s Senegalese and Gambian licences are located within the Mauritania-Senegal-

Bissau-Conakry basin, extending from Morocco to Guinea. The basin is geologically very

different from those further to the east (i.e. Sierra Leone and beyond), having rifted earlier

in its history, most likely in the late Triassic-early Jurassic. In contrast with the core West

Africa Transform Margin, the most notable geological feature of this part of margin is the

presence of a Jurassic / Early Cretaceous carbonate platform which has a strong bearing

on the regional play types and exploration potential. Until recent times, exploration has

been confined to the shallow water areas, yielding one producing oil field offshore

Mauritania (Chinguetti field; production ~5 kbopd gross) and a number of fallow

discoveries in Morocco, Mauritania, Guinea Bissau and Senegal (including the Dome

Flore heavy oil field, see Figure 13 below), with the deepwater area remaining virtually

untested (other than the Ophir-operated Kora deepwater well in 2011 in the AGC Profond

licence offshore Senegal and Guinea Bissau which failed to find reservoir).

Figure 13: APCL licence map and nearby discoveries offshore Gambia and Senegal

Gadiaga FieldSenonian Sands

Dome Flore1.5 Billion barrels 10-14 API L. Mio-Maastrictian sands/carbs.

Tortue-1 (Ahmeyim) Gas DiscoveryL. Cenomanian Sands 88m net pay,U.Cenomanian 19m net pay and 10m + Lower Albian (GDT as could not drill on)

Faucon -1Senonian SandsGas Discovery

Diam Niadio FieldMaastrictian gas 41 API

Fan-1 DiscoveryLower Cret sands.500m oil column, 29m net pay29-40 API

WY-1 oil shows Maastrictian sands

DKM-2 oil shows Neocomian Carbonates

SNE-1 DiscoveryAlbian sands.95m oil column, 36m net oil pay32 API, Associ. Gas Cap

RF-2 and RF -3 oil Minor shows Neocomian sands,Cenomanian silts, AptianCarbonates

SF-4 Maastrictian sands Sands. 13bbls, 34 API

East Sinapa FieldGross Oil column 124mAlbian Discovery, 35 API170 MMbbls STOIIP

CH-7AlbianLight Oil shows

Dome GeaOligocene Heavy Oil

Gas window (Aptian -30 deg/km)

Oil window (Aptian -30 deg/km)

Oil discovery

Gas discovery

African Petroleum acreage

Surface Oil Seep satellite (mod-high confidence)

Salt basin

Oil shows

Hydrocarbon Fields and shows and Maturity


The deepwater potential of the margin was materially de-risked in 2014, with two key oil

discoveries by Cairn, Conoco and FAR in the Sangomar Deep licence offshore Senegal

which lies adjacent to APCL’s A1 (to the north) and ROP (to the east) licences (see

Figures 12 and 13, above). Additionally, in Q4 2014, Kosmos Energy farmed into the

deepwater Cayar Offshore Profond (COP) and St. Louis Offshore Profond (SLOP)

licences to the north of APCL’s ROP licence – a move that has been vindicated by the

US-independent’s 8 Tcf Tortue gas discovery in Mauritania this year (which extends

across the border into Senegal). As the source maturity map shows above (in Figure 13),

the regional Aptian source rock offshore Senegal is more deeply buried to the north (with

elevated temperatures) and therefore in the gas window, whereas to south (in APCLs

acreage) it is in the oil window.


16

Given APCL is seeking partners for its Gambia and Senegal licences the recent farm-in

by Kosmos to COP and SLOP provides a useful benchmark (although we suspect that

Kosmos’s appetite to sign the acreage was driven by what it could see from propriety 3D

seismic on its adjacent licences in Mauritania). Under the terms of the transaction,

Kosmos acquired an initial 60% interest from Timis Corporation in exchange for a full

carry on 7,000 km2 of 3D seismic and up to two exploration wells (with an option to

increase by 5% for a third well). Assuming the full gross work programme of US$400m,

the deal places a read through valuation on these exploration blocks of US$615m (gross).

Cairn oil discoveries

Led by operator Cairn, the Sangomar Deep partners drilled two exploration wells in 2014.

The first (known as FAN-1) tested a large stacked fan structure of Mid-Upper Cretaceous

age situated on the slope section of the basin (see Figure 14, below). Cairn estimated

pre-drill mean prospective resources of 817 mmbbls across the two main target intervals.

The well found a gross oil bearing interval of some 500 metres with 29 metres of net oil

pay across a number of separate zones (in the Albian section). While the net to gross was

low (at around 6%), we note that the pay was in discrete sand units and not distributed

throughout the gross oil bearing interval. Oil samples were recovered to surface showing

distinct oil types varying between 28° and 41° API, proving the presence and

effectiveness of multiple oil prone source rocks. Due to the variable reservoir quality, the

recoverable potential of the find is yet to be ascertained, with Cairn estimating an initial

OIP range of 250-950-2,500 mmbbls (P90-50-10) pending further evaluation. For APCL,

most importantly, the FAN-1 discovery validated its regional model and proved the

existence of a potentially prolific petroleum system in close proximity to its own acreage.

Figure 14: FAN-1 and SNE-1 seismic illustrations

Source: Cairn Energy.

Cairn’s second well targeted an entirely different play located on the shelf (see Figure 14,

above), with a dual target of Mid-Lower Cretaceous clastics (Cenomanian-Albian) and

underlying karstified and fractured carbonates (Aptian). The two structural traps were

estimated by the operator to contain pre-drill mean prospective resources of 182 mmbbls

and 256 mmbbls, respectively. Encouragingly, in the shallower clastics target, the well

encountered a gross oil bearing interval of ~100 metres, with 30 metres of net light oil pay

(32º API) in good quality reservoir sands (plus 19m of gas). Cairn estimates that the

discovery is almost twice the size of its pre-drill estimate with P50 oil resources of 330

mmbbl (P90 150 mmbbls; P10 670 mmbbls) and large enough to exceed the

commerciality threshold (which Cairn pegs at around 200 mmbbls). Conversely, the


17

underlying carbonate zone in the Aptian was found to be water bearing at this location

(due to the lack of top seal).

On the back of the SNE-1/FAN-1 success, Cairn and its partners are currently planning a

three well campaign (plus three contingent wells) offshore Senegal, starting in Q4.

Subject to final agreement, this is likely to include two firm appraisal wells on the SNE-1

discovery (aimed at de-risking the current resource volumes) and one exploration well.

While APCL is yet to secure funding for drilling, planned activity in the nearby Sangomar

block should help to further de-risk the basin and retain industry interest. Meanwhile,

although of limited geological significance, E&A drilling is also pencilled in by Kosmos in

Q3-4 on the Senegalese portion of the Tortue find in the St. Louis Offshore Profond block.

The search for analogues

Of APCL’s four licences in Senegal/Gambia, the two Gambian blocks are the most

mature. In 2010 the company completed a 2,500 km2 3D seismic programme over the

whole of A1 and A4, resulting in the identification of more than 30 prospects and leads.

The geological setting of A1 & A4 is very similar to Cairn’s Sangomar licence to the north

with both structural traps running along the shelf edge (SNE-1) and turbidite fans plays

further outboard comprising stacked structural-stratigraphic traps (FAN-1) – as illustrated

in Figure 15, below. The main reservoir targets are the same Cretaceous-age clastics (as

well as carbonates), with the charge provided by multiple proven source rocks lying

outboard and structurally beneath the mapped prospects (as shown in Figure 14, above).

Figure 15: APCLs Gambian licences and prospect map

Source: African Petroleum. *ERC audited, mean unrisked prospective resources. **Cairn Energy estimates.


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The top six prospects in A1 & A4 have been independently assessed by ERC to contain

3.1bn bbls of gross prospective resources, with chances of success ranging from 11% to

24% (post the Cairn discoveries) – as shown in Figure 16, below. Given Cairn’s success

at Sangomar, APCL has prioritised the shelf edge play in A1 and A4 and expects to drill

its first well on the Mahogany prospect (or possibly Lamia), lying 40km to the south and

on trend with SNE-1. Assuming a successful farm-out deal, APCLs current plan is to spud

the well in Q2 2016.

Figure 16: Senegal-Gambia prospect inventory – March 2015

Prospect Reservoir Play type Water depth

Gross,

unrisked† WI*

Net,

unrisked† CoS

Net,

risked†

Meters Mmbbls % mmbbls % mmbbls

Alhamdulilah (stacked) Santonian Salt anticline 2,220 527 100% 527 15% 81

Sami Albian Slope fan 2,100 282 100% 282 17% 48

Rosewood Santonian Slope fan 2,400 208 100% 208 24% 49

Mahogany (stacked) Apto-Albian Shelf edge 2,200 410 100% 410 16% 68

Lamia (stacked) Apto-Albian Shelf edge 2,600 1,515 100% 1,515 11% 168

Acacia Santonian Slope fan 2,800 137 100% 137 23% 32

Total Gambia 3,078 3,078 445

Baobab (stacked) Albian-Maa’ Slope fan 823+ 459 90% 413 14% 59

Jaloo Cenoman’ Slope fan 2600 254 90% 229 23% 52

Kapok (stacked) Aptian-Cen’ Slope fan 2,760+ 681 90% 613 21% 129

Jaloo/Kapok Albian Slope fan 2870 583 90% 525 16% 85

Total Senegal 1,977 1,779 325

Grand Total 5,055 4,857 770

Source: ERC Equipoise. †Mean prospective oil resources (on block only). *Current working interest, prior to Government back-in.

Mahogany is independently estimated by ERC to contain 410 mmbbls of gross

prospective resources, split 60:40 between the Aptian and Albian sandstone targets, with

individual chances of success of 14% and 20% (the greater CoS for the Albian reflects the

fact it is the main reservoir interval in SNE-1). ERC sees the principal geological risks as

reservoir (especially for the Aptian which is prognosed to contain a mix of clastics and

carbonate) and trap – which relies on 3-way dip closure. Encouragingly, like SNE-1,

Mahogany (and other mapped shelf edge prospects) appears to exhibit amplitude

conformance with structure – as shown in Figure 17, below – which may be a positive

indicator for hydrocarbon presence (although the response is yet to be calibrated).

Figure 17: Amplitude map (left) and seismic line through the Mahogany prospect (right)



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The Senegalese acreage is at an earlier stage of evaluation than Gambia due to its more

recent award and greater size (15,796 km2). Initially, APCL licenced over 10,000km of

pre-existing 2D seismic to compile a regional database and then shot 3,600km2 of

targeted 3D seismic over SOSP and purchased 1,500km2 of existing 3D over ROP. The

northerly ROP licence is located outboard of the shelf break and its prospectivity is

therefore confined to the turbidite fan play proven by FAN-1. Thus far, ERC has assessed

a single prospect called Baobab in the eastern corner of the licence, ascribing 459

mmbbls of gross prospective resources across five stacked horizons (Albian to

Maastrictian) and a blended 14% CoS (see Figure 18, below, for prospect location). As

discussed earlier, APCL is in discussions to defer the upcoming well commitment on ROP

(October 2015) with a view to acquiring further 3D seismic to better understand the wider

prospectivity of the block ahead of deciding the best location for the first exploration well.

Figure 18: APCLs Senegalese/Gambian licences and prospect map

SNE-1 – 330 MmbblContingent Res.

Fan-1 – 950 MmbblIn-place

PaprikaVol. tbc

NemaVol. tbc

Mahogany410 Mmbbl*

Lamia1515 Mmbbl*

Alhamdulilah527 Mmbbl*

Sami282 Mmbbl*

Rosewood208 Mmbbl*

Acacia 137 Mmbbl*

SottoVol. tbc

Kapok876 Mmbbl*

Jaloo492 Mmbbl*

Karst targets

Vol. tbc

Albian shelf targetsVol. tbc

Baobab 413 Mmbbl*


In the SOSP licence, meanwhile, the carbonate shelf crosses the eastern side of the

block offering more play diversity. So far, APCL has identified two large fan prospects –

Kapok and Jaloo (which could be part of the same structure in an upside case) – with

combined mean prospective resources of 1.5bn bbls in stacked reservoir targets (Aptian

to Cenomanian age). In addition, there is also the potential for clastic and carbonate

structural traps associated with the shelf edge although these are at an earlier stage of

evaluation and are currently not included in ERC’s resource assessment of the licence.

APCL has a drill of drop option on SOSP in April 2016 which, if exercised, will commit the

company to one well by October 2017. As such, no near-term drilling activity is planned.


20

Asset (iii): Liberia and Sierra Leone

In the wake of the Jubilee discovery offshore Ghana, the industry turned its attention first

to Sierra Leone and Liberia in the hunt for lookalike discoveries. While a commercial

success has proven elusive thus far, the key elements of working hydrocarbon system

have been established, and we believe the margin continues to hold promise. As one of

the earliest entrants into the deepwater, APCL understands the Liberian basin better than

most and is well-placed to attract a partner to test the second generation of play concepts.

Licence overview

Covering a 500km stretch of coastline, the Liberian basin extends over much of Liberia

and Sierra Leone’s offshore. APCL holds 100% of four licences in the basin covering a

combined area of 11,000km2 comprising LB-09 and LB-08 on the eastern flank in Liberia

and SL-03 and SL-4A-10 on the western flank in Sierra Leone (see Figure 19, below).

The Liberian licences were originally awarded in 2005 together with Regal Petroleum

(25%) which later sold out to APCL for a nominal sum (as part of a reorganisation). Now

in their second exploration term, LB-08 & LB-09 carry a residual 3D seismic commitment

(the extent of which is under discussion with the Government), but no drilling obligations

in the current phase which expires in June 2016. The water depth in LB-08 and LB-09

varies from 100m up to 3,000m with most of the mapped prospectivity in 1,500-2,500m of

water.

Figure 19: Liberia and Sierra Leone licence overview

Liberia

LB-08 APCL 100%

LB-09

Partners: None

Gross area 5,350 sq km


Work to date: 3 wells (LB-09)

5,100 sq km 3D seismic

Well commitments: None


Sierra Leone

SL-03 APCL 100%*

SL-4A-10

Partner: None

Gross area: 5,855 sq km


Work to date: 2,500 sq km 3D seismic (SL-03)

1,000 sq km 3D seismic (SL-4A)

Well commitments: 2 contingent wells**


Source: African Petroleum. †ERC Equipoise (Jan 2015 Liberia and Apr. 2015 Sierra Leone) gross unrisked mean prospective resources (on block only). *Government has back-in rights for a 10% carried interest on SL-03 and SL-4A-10 and an additional 5% paying interest on SL-4A-10. **Contingent on availability of a rig capable of drilling in ultra-deep water.

APCL’s two licences in Sierra Leone were granted in 2010 (SL-03) and 2012 (SL-4A-10)

and are in the second and first exploration phases respectively, with a contingent well

commitment on SL-03 by April 2017 and SL-4A-10 September 2015. As shown above,


21

SL-4A-10 is roughly half the surface area of SL-03 and comprises the relinquished

deepwater portion of a larger block that extended to the shoreline (originally held by Elixir

Petroleum). The outer reaches of the two Sierra Leone licences are located in ultra-deep

water with the key Vega lead (3,400-3,640m) in SL-4A-10 lying at the limits of current

drilling technology (the deepest water depth ever drilled is 3,174m by ONGC offshore

India). As a result of the water depth the well commitments are classified as contingent

and may be subject to deferral until the technology is readily available to execute drilling.

Regional context

The licenced acreage in the Liberian basin is predominantly held by Oil Majors and IOCs.

While there is no existing production, the deepwater potential of the margin has seen

heightened exploration activity since 2009 with around 20 wells drilled. The industry’s

main exploration objective has been Upper Cretaceous stratigraphic traps, akin to the

Jubilee discovery offshore Ghana. Led by US-independent Anadarko, the first deepwater

wells were drilled in Sierra Leone with sub-commercial oil discoveries at Venus, Mercury

and Jupiter in quick succession (see Figure 20, below). In the aftermath of the Venus find

Anadarko claimed that it had established the ‘bookends’ of a major Cretaceous play

fairway extending 1,100km to Ghana. However, the basin has struggled to live up to its

early promise. While subsequent drilling has yielded technical successes, including

APCL’s Narina-1 well in Liberia, the industry is yet to make a standalone commercial find.

Figure 20: APCL’s Sierra Leone acreage map and selected deepwater wells in the Ivorian basin

Sierra Leone

Venus-B1 Anadarko 2009 14m net oil & gas pay

Mercury 1 Anadarko 2010 42m of net oil pay

Jupiter-1 Anadarko 2012 30m net oil & gas pay

Mercury 2 Anadarko 2012 Oil shows

Djembe-1 Talisman 2012 Water bearing

Savannah-1X Lukoil 2013 3m of net oil pay

Liberia

Apalis-1 APCL 2011 Oil shows, no reservoir

Montserrado-1 Anadarko 2011 8m net oil & gas pay

Narina-1 APCL 2012 32m of net oil pay

Carmine Deep-1 Chevron 2012 Rumoured oil shows

Nighthawk-1 Chevron 2012 Rumoured oil shows

Bee Easter-1 APCL 2013 Oil shows, no reservoir

Timbo Anadarko 2014 Non-commercial oil

Iroko Anadarko 2014 Non-commercial oil

Source: African Petroleum. Company data.

Liberia LB-08 & LB-09 – activity to date

Liberia has been a key exploration focus for APCL, with US$287m spent across LB-08

and LB-09 to date – more than on all of its other blocks put together. In 2010, the

company completed the acquisition of 5,100 km2 of 3D seismic over the entire licence

area, leading to the identification of more than 40 prospects and leads. The following year

APCL drilled its first well on the Apalis prospect in LB-09. The target comprised a 4-way

dip closed structure with pre-drill prospective resources of 408 mmboe in stacked

reservoirs of Lower Tertiary to Mid-Cretaceous age. The well failed to find reservoir

quality sands in the main objectives and was unsuccessful. However, it did encounter oil


22

shows in several secondary intervals as well as a thick oil prone source rock (thought to

be Cenomanian/Turonian in age), providing encouragement for follow-on exploration

drilling.

The second exploration well in LB-09 was drilled on an entirely different feature: a large

Upper Cretaceous stratigraphic fan play, akin to the Jubilee field along the coast in Ghana

(ERC estimated pre-drill mean prospective resources of 840 mmbbls). The Narina-1 well

was APCL’s most successful to date, finding 32 metres of net light oil pay (38-40º API) in

two separate zones: 21 metres in the Turonian and 11 metres in the underlying Albian.

The discovery was initially heralded as a major breakthrough: although the reservoir

quality was mainly poor the assumption was that the well had tagged the flank of a large

fan system and that thicker, better quality sands would exist in the heart of the feature.

Encouraged by the success of Narina-1, in 2013, APCL drilled a bold step-out well called

Bee Eater-1, 9.5km to the northwest, which found a thick section of shale in the primary

Turonian objective. The result suggested that the Narina fan was much more restricted

than originally thought. Indeed, in 2015, ERC ascribed 184 mmbbls of mean prospective

resources to the Narina West prospect which extends laterally from the Narina-1 location.

Exploration activity since 2013 has focused on a new play concept in LB-08 and LB-09,

down-dip of the wells drilled to date. As illustrated in Figure 21, below, post well analysis

of the Bee Eater-1 probe suggests that the shelf edge slope is a bypass zone for sands

travelling into the basin and in fact the bulk of the Upper Cretaceous prospectivity lies

outboard in basin floor fans (which remain untested in LB-08 and LB-09). Interestingly,

other operators in country seem to be moving towards a similar model following a number

of technical successes along the margin where oil has been discovered in poorly

developed reservoir. That said, two non-commercial oil discoveries by Anadarko in 2014

on LB-10 (Timbo & Iroko), just to the west of LB-09, show that the industry is yet to crack

the code.

Figure 21: LB-09 wells and model sand distribution


Future plans and prospect inventory

As part of a two year licence extension (negotiated in January 2014), APCL has agreed to

acquire new 3D seismic over LB-08 and LB-09 to overcome data quality issues and

highlight future drilling targets (seismic imaging over the blocks is hampered by shallow

channelling). We would expect that any incoming partner is unlikely to rush into drilling on

either block without new seismic with the next wells probably a year or more away.


23

ERC’s January 2015 resource update indicated gross unrisked mean recoverable

resources in LB-08 and LB-09 of some 4.2 billion barrels (as summarised in Figure 22,

below). Of this amount, a significant proportion is thought to be contained within two

Upper Cretaceous basin floor fan prospects known as Lovebird (529 mmbbls; 20%

chance of success) and Night Heron (650 mmbbls on the block, with a possible extension

into neighbouring LB-10; 14% CoS). ERC sees the main risks as being reservoir quality

and trap integrity now that the presence and effectiveness of the source rock has been

completely de-risked in the area.

Figure 22: Blocks LB-08 and LB-09 prospect inventory

APCL prospects* mmbbls1 GCoS2

Barbet 270 22%

Sunbird 532 18-27%

Lovebird 529 20%

Night Heron3 650 14%

Wildbird4 1,065 9%

Narina West 184 16%

Turaco A3 84 25%

Turaco B 363 15%

Turaco C 199 13%

Hornbill 316 19%

Sum total 4,192

Source: African Petroleum. *audited by ERC Equipoise. 1gross unrisked mean recoverable oil. 2geological chance of success. 3On-block resources only. 4Wildbird is a Lower Cretaceous carbonate prospect, unlike the others which are Upper Cretaceous slope and basin floor fan prospects.

Beyond the Upper Cretaceous fan play, the majority of the remaining prospective

resource is contained within the Wildbird prospect (1,065 mmbbls), which represents an

entirely different, older (syn-rift) carbonate play. Wildbird has been recognised from

seismic facies analysis as a possible microbial carbonate build up, similar to new

discoveries in the Brazilian pre-salt and Angola’s Kwanza Basin. Unsurprisingly, the

geological risks are higher, with ERC ascribing a 9% chance of success. However, if

successful, this would represent an exciting new frontier for the microbial carbonate play.

Turning to Sierra Leone, APCL acquired 2,500 km2 of 3D seismic on SL-03 in 2011 and

1,000km2 on SL-4A-10 in 2014 which has led to the mapping of four Cretaceous-aged fan

prospects with 1.4bn bbls of gross mean prospective resources. As shown in Figure 20,

above, the licences lie close to the initial deepwater discoveries in the Liberian basin by

Anadarko (as well as the more recent Savannah discovery by Lukoil in adjacent SL-05),

so source rock presence and maturity is proven in the immediate area. The focus of

APCLs recent activities has been the ultra-deep water block SL-4A-10, lying in water

depths of 3,000-4,000m (assessable only with new generation drillships). Here, a large

structure called the Vega lead has been mapped with a supporting AVO response at the

Campanian reservoir level for which resource estimates are currently being evaluated.


24

Funding

APCL has historically funded its business through equity markets, raising ~US$575m

since its 2010 Australian IPO. This approach reflects previous management’s preference

for retaining high working interests through the drilling phase (to minimise dilution to any

discovery), as well as the strong appetite for risk in equity markets in the company’s

earlier years. Since the management change in 2014, APCL’s funding strategy has

shifted to one where costly drilling activity will be financed using other companies’ balance

sheets through industry partnerships, thus reducing the overall risk profile of the business.

Importantly, with operatorship and controlling equity stakes in all its licences, APCL has

plenty of scope to sell down while retaining transformational upside exposure to the drill

bit.

Managing licence commitments

The breadth of APCL’s portfolio brings with it a range of contractual commitments and

timelines that need to be adhered to. Over the course of 2014, APCL successfully

renegotiated the duration and work obligations under its key exploration contracts in

Liberia, Côte d’Ivoire, Sierra Leone and Senegal (some of these licences had near-term

drilling commitments which APCL was unlikely to fulfil in the time required). As well as

highlighting the strength of APCL’s relations with host Governments, these extensions

have removed the risk of default in the near-term and freed up more time to negotiate

farm-outs. As Figure 23 shows, below, APCL currently has two firm near term well

commitments in Côte d’Ivoire and Senegal in Q4 2015 (the former on CI-513 is expected

to be funded by a farm-out transaction, while a deferral is being sought for the latter on

ROP, as discussed earlier) and a further two wells in Côte d’Ivoire and Gambia in 2016.

Figure 23: Exploration licence duration, remaining commitments and back costs

Country Licence Expiry† Sunk costs Remaining Commitments¥

date US$m

Liberia LB-08 Jun. 16 32 3D seismic commitment to be agreed with NOCAL

Liberia LB-09 Jun. 16 255 3D seismic commitment to be agreed with NOCAL

Côte d’Ivoire CI-513 Dec. 15 27 1 well commitment outstanding

Côte d’Ivoire CI-509 Mar. 16 20 1 well commitment outstanding

Sierra Leone SL-03 Apr. 17 23 Contingent 1 well commitment outstanding‡

Sierra Leone SL-4A-10 Sept. 15 12 Contingent 1 well commitment‡

Senegal ROP Oct. 15 10 1 well commitment outstanding

Senegal SOSP Oct. 17 22 Further geoscience and 1 contingent well commitment*

Gambia A1 Sept. 16 20 Drill 1 well on either A1 or A4

Gambia A4 Sept. 16 12 Reprocess 3D seismic; drill 1 well on either A1 or A4

Total 433

Source: African Petroleum. †Expiry date of current exploration phase. ¥For current phase only. ‡Contingent on 3D interpretation and availability of a rig

capable of drilling in ultra-deep water. *APCL has a drill of drop option by April 2016.

Ample near-term liquidity

In March 2015 APCL completed a secondary equity placing raising ~US$13m to fund the

reinstatement of the Gambia A1 and A4 (US$4m fee payable to the Government) and

recent 3D seismic over SL-4A-10 (US$4m), as well as for working capital purposes. At the

end of Q1 the company had US$12m of cash in the bank, plus a further US$12m of

restricted cash in relation to future exploration programmes (which will be released on

achievement of certain drilling milestones in Côte d’Ivoire). The company’s current G&A

burn rate is approximately US$750k per month (US$9m per annum) following a series of


25

cost cutting measures including a reduction in headcount and moving office premises. On

top of this, we estimate maintenance (non-drilling) capex of ~US$10m across its portfolio

in 2015, roughly 40% of which has already been incurred. As such, excluding the two

2015 drilling commitments, we believe that APCL has sufficient liquidity to finance the

business until around year-end.

Seeking industry partnerships

The farm-out market in Africa has been challenging for some time with North American

independents withdrawing from the region and many participants shying away from

expensive deepwater exploration, in particular. While falling oil prices since mid-2014

have significantly reduced drilling and seismic costs, capital budgets across the industry

are under pressure and some parties are reluctant to commit to near-term drilling

programmes. Despite these headwinds, a number of deals have been struck in recent

months across the WATM region (see Figure 24, below), demonstrating continued

interest. Furthermore, compared to other deepwater provinces, APCL’s licences benefit

from generous fiscal terms and low well costs (~US$40m), increasing their attractiveness.

Figure 24: Key recent farm-out transactions in the WATM region

Farmor Farminee Date Country Licence Comments

name Name name

Kosmos Chevron Feb-15 Mauritania C12,8&13 30% stake for ‘disproportionate share’ of 1 well plus 1 optional well.

Govt. Liberty et al Jan-15 Liberia LB-16 Relinquished Anadarko block. US$10.5 signature bonus paid.

APCL Undisclosed Dec-14‡ Liberia LB-08 50% stake on ground floor terms (i.e no promote).

Timis Corp. Kosmos Oct-14 Senegal Cayar & St. Louis 60% for full carry on 3D & 2 wells + incr. 5% option for 1 well.

Anadarko Mitsubishi Sept-14 Côte d’Ivoire CI-103 20% stake in Paon discovery licence, terms undisclosed.

APCL Buried Hill Jul-14* Côte d’Ivoire CI-509 10% in return for funding 21.1% of 1 well plus pro-rata back costs.

Source: Mirabaud Securities estimates; Company data. ‡Term sheet agreed, final contract to be negotiated by backstop date 30 Jun 2015. *Yet to complete.

APCL has opened a dataroom over its entire licence portfolio with a view to soliciting

farm-out bids. Thus far, the company has secured a deal with Buried Hill, its former

Gambia partner, on CI-509 in Côte d’Ivoire. Under the agreed terms, Buried Hill has

agreed to take a 10% stake in exchange for pro-rata back costs and the funding of 21.1%

of the cost of the next exploration well. Thus, APCL will retain an 80% stake, paying

78.9% of the well. Additionally, APCL has also signed a term sheet with an undisclosed

party to farm-out LB-08 in Liberia, divesting 50% of the licence on ground floor terms (in

part reflecting the poor quality of the existing 3D seismic data over the block). The

deadline for completion of the deal has been extended several times, most recently to the

end of Q2, to allow time for conditions affecting the proposed partner to be met or waived.

Success in the eyes of the equity market will be measured by APCLs ability to attract a

major industry player(s) into one or more licences with deep enough pockets to provide a

full carry on drilling. Management has set an informal target to close a deal by mid-2015

with the Côte d’Ivoire and Senegal/Gambia licences at the forefront of ongoing talks (and

the most likely to yield a positive outcome). Taking into account the recent deals along the

margin, our belief is that 2 for 1 terms (or better) are achievable on the most prospective

blocks – providing funding for drilling one well in exchange for half of APCLs equity stake.


26

Valuation

Sum of the parts

We have valued African Petroleum on a sum of the parts basis using a 10% discount rate

and assuming the ICE Brent Crude forward strip until 2020 reverting to a long-run Brent

oil price of US$80/bbl flat nominal thereafter. In reaching our valuation we have focused

on the three assets that are most likely to see near-term drilling via farm-out transactions

(The Gambia, Côte d’Ivoire and Liberia) and ascribed value to one prospect in each area.

The outcome is a Total NAV of NOK 3.16/shr – comprising NOK 2.93/shr of risked asset

value and NOK 0.23/shr of corporate items – and a fully unrisked NAV of NOK 16.45/shr.

The oil & gas asset component of our valuation is broken down into three parts as follows:

Côte d’Ivoire: APCL’s Côte d’Ivoire assets have a well commitment by the

year-end (in CI-513) and are expected to be the first to be drilled. In our NAV,

we have ascribed NOK 0.97/shr of risked value to the Ayamé West prospect, a

stacked Upper Cretaceous fan play with 331 mmbbls of gross prospective

resources and a 23% chance of success. Our analysis assumes a 2 for 1 farm-

out is secured providing funds for the drilling of the well in exchange for half of

APCL’s equity (reducing APCL’s stake to 40% after 10% Government back-in).

The Gambia: the Mahogany prospect on the border of A1 and A4 is pencilled in

as the first drilling location on the Gambia/Senegal licences (Q2 2016). In our

NAV, we have ascribed NOK 1.23/shr of risked value to the structure – a shelf-

edge Aptian-Albian play located on trend with Cairn’s SNE-1 discovery – with

410 mmbbls of gross prospective resources and a 17% chance of success. As

with Côte d’Ivoire we have assumed that APCL’s stake is diluted by 50% pre-

drill as part of a hypothetical farm-out transaction to fund the drilling of the well.

As such, after 10% Government back-in, APCL is left with a residual 45% stake.

Figure 25: Valuation summary table

NPV10, US$80/bbl LT Gross Net Unrisked Risked

Asset MMboe1 Interest3 MMboe1 US$/bbl US$m NOK/shr CoS2 US$m NOK/shr

Ayamé West, Côte d’Ivoire 331 40% 132 4.66 617 4.24 23% 142 0.97

Mahogany , Gambia 410 45% 185 5.85 1,079 7.41 17% 179 1.23

Narina West, Liberia 184 50% 92 7.23 665 4.57 16% 106 0.73

Add: cash 24 0.16 24 0.16

Add: options & warrants 9 0.06 9 0.06

Total NAV 925 409 2,394 16.45 460 3.16

Source: Mirabaud Securities estimates, ERC Equipoise. 1Prospective oil resource estimates. 2Chance of success. 3APCL working interest post Government

back in (where applicable) and factoring in hypothetical 2 for 1 farm-out. Forex: US$/NOK = 7.7.

Liberia: APCL’s licences offshore Liberia continue to hold promising potential,

in particular LB-09 where three wells have been drilled to date. In our NAV we

have ascribed NOK 0.97/shr of risked value to the Narina West prospect – a fan

play to the west of the Narina-1 oil discovery where the sands are interpreted to

thicken on seismic. In line with ERC estimates, we have assumed 184 mmbbls

of gross prospective resources and a chance of success of 16%. Additionally,

like the other prospects in our NAV, we have factored in 50% farm-out dilution.

While APCL shares trade at a fraction of our risked NAV (89% discount) – which in itself

only considers a small number of prospects – in our experience, this is a relatively poor

guide for the market valuation of early stage exploration companies. As such, for the time

being, we have set our target price in line with sunk costs on Côte d’Ivoire and


27

Senegal/Gambia, amounting to US$111m or NOK 0.88/shr. Looking ahead, we believe

that the key to a re-rating is the farm-out process, which will: (1) provide a read through

valuation on the key assets (and consequently help to underpin the value proposition), (2)

endorse the hydrocarbon potential, and (3) provide funding for a multi-well programme.

Comparable analysis

There are numerous small cap pure-play explorers listed in London and internationally

with acreage in Africa. In our opinion, drawing any firm conclusions from top-down

comparable analysis is challenging because different companies adopt different levels of

resource disclosure. Additionally, this type of analysis takes no account of geological

specifics, management credentials, or dilution effects. However, for what it’s worth, our

simple scatter chart below shows that, for a company of its market value, APCL holds a

considerable resource base and one that we know is far from an exhaustive prospect list.

Figure 26: African pure-play explorers – market cap vs. net unrisked resources

APCL

Chariot

Savannah

Can. OverseasFastnetAzonto

TowerHyderDyn.

Pura VidaPancontinental

Eco Atlantic

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0

Unr

iske

d re

sour

ces

(bn

boe)

Market cap (US$m)


Sensitivity analysis

The slump in oil prices has refocused the industry’s attention on breakeven economics.

As Figure 27 shows, below, on our numbers, APCL’s assets are resilient at much lower oil

prices than today, with Côte d’Ivoire achieving a 10% IRR at US$49/bbl, Gambia at

US$47/bbl and Liberia at US$44/bbl – helped by, amongst other things, the attractive

fiscal regimes in these countries. For a summary of our key valuation assumptions see

Appendix 1, below.

Figure 27: Valuation sensitivity table for key APCL licences

-3.00

-2.00

-1.00

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

40 45 50 55 60 65 70 75 80

Per

bbl

val

ue, 1

0% d

isco

unt r

ate

(US

$/bb

l)

Brent price (US$/bbl)

Cote d'Ivoire Gambia Liberia



28

Appendix 1: Valuation assumptions

Modelling approach

We have modelled a hypothetical 350 mmbbl deepwater oil development scenario under

a variety of different fiscal regimes (Liberia, Gambia, and Côte d’Ivoire) to derive per

barrel valuations for the key exploration prospects within APCL’s portfolio. We have

assumed that the development concept comprises a leased FPSO vessel with sub-sea

infrastructure and off-take of crude via tanker – the same as the Jubilee project off Ghana.

Key assumptions

Production profile: We have assumed an initial production rate per well of 10 kbopd,

lower than the 18 kbopd initial flow rates reported at the Jubilee field to reflect the

unknown reservoir quality. The field production profile (see Figure 28, below) in our model

is based on 18 producers and 9 injectors generating a three year plateau of 100 kbopd

commencing in January 2021. We have assumed a relatively aggressive decline curve

with each producer declining 30% in year 1 then easing off over a 25-year production life.

Figure 28: 350 mmbbl field production profile

0

50

100

150

200

250

300

350

0

20

40

60

80

100

120

2015 2020 2025 2030 2035 2040

Cum

ulat

ive

prod

uctio

n (m

mbb

ls)

Dai

ly p

rodu

ctio

n (k

bopd

)

Daily oil production Cumulative oil production


Capital costs: We have assumed full cycle capital costs of US$12.9/bbl (US$4.5bn),

including US$8.3/bbl (US$2.9bn) of sub-sea and associated infrastructure spend. We

have assumed that drilling accounts for the balance of capex (US$1.6bn), with each

production and injector well costing US$60m on average to drill and complete. Finally, we

have also included abandonment costs of 5% of sunk capex over the field life (US$226m).

Figure 29: 350 mmbbl field economic summary at US$80/bbl flat Brent prices

Gov take* Recovery Capex Opex NPV10** NPV10** % MMbbl US$/bbl US$/bbl US$m US$/bbl

Liberia 47% 350 12.9 15.5 2,530 7.23

Gambia 51% 350 12.9 15.5 1,842 5.85

Côte d’Ivoire 59% 350 12.9 15.5 1,304 4.66

Source: Mirabaud Securities estimates. *Total royalties, profit share, bonuses etc to Government divided by pre-tax CF over life of field. **After accounting for back-in rights where applicable.

Operating costs: We have assumed fixed annual opex of US$110m for the running of

the FPSO, and a further US$7.0/bbl of variable opex (including G&A costs). These

operating costs equate to an average unit cost of US$15.5 per barrel over the project life.

A summary of the various valuation outputs for Liberia, Gambia and Côte d’Ivoire are

shown in Figure 29, above. In general, APCL operates in countries with favourable fiscal

terms reflecting the relatively nascent state of their petroleum industries (47%-59%

Government take). Unsurprisingly, Côte d’Ivoire offers the harshest terms – being the only

country with any oil & gas production – with Liberia and Gambia slightly more attractive.


29

Appendix 2: West African Transform Margin

Regional overview

The WATM comprises a series of under-explored basins (shown in Figure 35, below) that

were formed during the parting of the Atlantic Ocean, stretching westwards around the

coastline from Benin to Sierra Leone (core WATM) and up to Senegal (the Guinea to

Senegal stretch is sometimes referred to as the Northwest African Transform Margin).

Until the early 2000s the deepwater potential of the margin was totally untested and what

little exploration did take place focused on the shelf areas in easier to drill shallow water.

Tullow’s giant Jubilee oil discovery (1.0bn bbls gross oil resources) in 2007 opened up a

completely new stratigraphic play in the deepwater, targeting Upper Cretaceous fan

systems. This provided the catalyst for a wave of industry activity offshore Ghana, leading

to further major oil discoveries and invigorated the search for oil along the wider margin.

Figure 35: West African Transform Margin map


Despite a significant amount of drilling activity, the success seen offshore Ghana has not

been easily repeated. The first wave of drilling (2009-2011) in Sierra Leone and Liberia

yielded a multiple technical successes (Venus, Mercury, Montserrado) but no commercial

discoveries. While many of the wells intersected thick good quality sands, the discovered

oil zones were modest and tended to be in less well developed sand sections. On the

back of these results, Tullow Oil, the explorer at the forefront of the initial WATM drive,

withdrew from its licences in Sierra Leone and Liberia – marking a low point in sentiment.

Over the past year, however, the margin has seen a notable revival in fortunes, with

several key oil discoveries in Senegal (by Cairn) and Côte d’Ivoire (by Total) which are

emerging as the region’s new exploration hot spots – a trend that plays into APCL hands.


30

Appendix 3: West African – politics and economy

Regional overview

Since the end of colonialism, West Africa has been marred by periods of conflict and civil

war in countries including Liberia, Guinea-Bissau, Côte d’Ivoire and Sierra Leone. While

the region remains inherently unpredictable and prone to political crises, a form of

democracy has established itself across most West African countries, and recent years

have witnessed a period of healthy foreign direct investment and economic growth rates.

Indeed, the regional economy grew by around 7% in 2014 despite notable headwinds

caused by the slump in commodity prices and the disruption of the Ebola virus outbreak.

Figure 36: West Africa map

Source: African Development Bank.

The Ebola epidemic that swept across the region last year was felt the hardest in Liberia,

Sierra Leone and Guinea, causing thousands of deaths and severely restricting the

movement of people, equipment and trade. Exxon imposed travel bans to effected

countries and delayed the spud date of the Mesurado-1 well offshore Liberia in

partnership with AIM-listed Canadian Overseas Petroleum. Fortunately, the virus now

appears to be under control, with the number of reported cases falling significantly in

recent months, raising hopes that the region will gradually return to normality during 2015.

Figure 37: Key statistics for APCL countries of operation

APCL acreage Population GDP (2014) GDP growth %

km2 Mill US$bn 2013 2014

Côte d’Ivoire 2,537 22.8 34.0 8.7% 8.5%

Liberia 5,350 4.1 2.1 8.7% 2.5%

Senegal 15,796 13.6 15.9 3.5% 4.5%

Sierra Leone 5,855 5.7 5.4 20.1% 8.0%

The Gambia 2,772 1.9 0.9 6.3% 7.4%

Source: CIA World Factbook.


31

APCL holds acreage in five West African countries, all of which is located offshore. A

summary of the key country facts and economic statistics is shown in Figure 37, above.

Liberia

The bulk of African Petroleum’s investment to date has been directed towards Liberia.

Although the country has a chequered past, it is currently enjoying a period of relative

calm, with Nobel Peace Prize winner Ellen Johnson Sirleaf awarded a second term in

office following the 2011 presidential election. Reflecting Liberia’s return to stability, in

2012 the UN Security Council has committed to halve the number of UN troops in country

by 2015. Liberia was amongst the hardest hit by the Ebola epidemic, with economic

growth slowing to 2.5% in 2014 from 8.7% the prior year, although the country was

recently given the all clear by the World Health Organisation raising hopes of a recovery.

Côte d’Ivoire

A former French republic, Côte d’Ivoire gained independence in 1960. The country boasts

the second largest economy in West Africa, behind Nigeria, and is a major exporter of

agricultural commodities, most notably cocoa beans, coffee and palm oil. While the Ivory

Coast, as it is also known, has been marred by unrest during much of the 2000s, the

unseating of former President Laurent Gbagbo following disputed elections in 2010 has

ushered in a period of relative stability and economic growth. The current president

Alassane Ouattara is considered to have far closer ties to the West, but faces ongoing

threats from supporters loyal to Gbagbo who is awaiting trial in The Hague for crimes

against humanity. Upcoming Presidential elections are scheduled for October this year.

Senegal

Senegal is one of the most stable democracies in West Africa, with a long history of

international peacekeeping and regional mediation. Since April 2012, the country has

been ruled by President Macky Sall – formerly Senegal’s Prime Minister (2004-2007) –

who succeeded former President Abdoulaye Wade after a decision to run for a third term

(disregarding the two-term limited he himself had imposed) sparked public outcry. In a

move designed to strengthen Senegal’s democracy Sall has pledged a referendum for the

reduction of his Presidential term from seven to five years, pencilling in elections for 2017.

Sierra Leone

Sierra Leone has a turbulent past, marred by a bloody civil war from 1991 to 2002 that

saw thousands killed and led to a displacement of a third of the population. A transition to

democratic rule has occurred through the 2000s, with peaceful elections held in 2007 and

most recently 2012, leading to the re-election of incumbent President Ernest Bai Koroma.

While the country has come a long way, corruption remains rife and the economy has

been badly bruised by the drop in commodity prices, including Iron Ore – a major export.

The country has also been hard hit by the Ebola epidemic and while the number of cases

has reduced dramatically it has yet to see a sustained period of no new cases like Liberia.

The Gambia

Occupying a slither of land either side of The Gambia River, Gambia is the smallest

country in West Africa and geographically surrounded entirely by Senegal. The current

President, strongman Yahya Jammeh, has held power since a military coup in 1994 and

is currently in his fifth term, having won the last election in 2011. Gambia’s economy relies

heavily on remittances from foreign workers and the tourist industry, as well as

agriculture, notably peanuts – a major export.


32

Appendix 4: Management & Board

Board of Directors

Charles Matthews OBE, Non-Executive Chairman

Mr Matthews has over 10 years’ experience in chairman and director positions,

having been on the board of a number of listed manufacturing and technology

companies, including FTSE 250 LSE listed company FKI Plc. He has previously held

senior management positions at Cosworth Group, Rolls Royce and Bentley Motor

Cars, and has served as a Member of the Vickers Group Executive Board.

He is currently Chairman of LSE listed Porvair Plc, a specialist filtration technologies

business in the aerospace and general engineering sectors. Mr Matthews holds a

BSc in Geography and Oceanography from the University of Wales, as well as an

MBA from Cranfield Business School and a Strategic Marketing qualification from

Harvard Business School.

Dr. Stuart Lake, Chief Executive Officer and Executive Director

Dr Lake has over 28 years of experience in a wide variety of roles including the Hess

Corporation, four years at the Apache Corporation and over 19 years in Shell. In

Hess as Vice President of Exploration he oversaw all the new ventures work re -

establishing a proactive basin master approach which led to significant strategic

partnerships. He also oversaw the highly successful exploration campaign in Ghana

that resulted in seven consecutive hydrocarbon discoveries and the subsequent

submission of the appraisal plans for those discoveries and likewise directed more

than 30 discoveries in Russia (before the asset was sold to Lukoil for US$2.05bn). Dr

Lake has demonstrated himself to be a proven oil finder, maintaining a high 85%

geological success rate in all three companies, based on drilling over 300 wells in 11

countries over his 28 year career. He has a BSc Hons in Geology from the University

of Wales and a PhD in Geology from the University of Durham, England. Dr Lake

also remains on the Advisory Board of the Energy and Geoscience Institute (E.G.I.)

at the University of Utah and is a Non-Executive Director of Tamboran Resources.

Mark Ashurst, Non-Executive Director

Mr Ashurst graduated from Sheffield University with a degree in law and is a qualified

Barrister and Chartered Accountant. Mr Ashurst has been employed as a senior

investment banker with a broad range of corporate finance and broking skills gained

from over 20 years in the City of London. Institutions Mr Ashurst has worked for

include BZW, Hoare Govett and, more recently, Canaccord Adams. He has advised

both UK and overseas listed companies and has significant expertise in IPO's, fund

raising and mergers and acquisitions. Mr Ashurst is a Non-Executive Director of NSX

listed International Petroleum Ltd.

Gibril Bangura, Non-Executive Director

Mr Bangura is an Executive Director of African Minerals Limited and the General

Manager of all of African Mineral Limited's Sierra Leone subsidiaries. Mr Bangura is

the former Financial Controller of Regent Star International, and Deputy General

Manager and Director of Bond Tak Mining Company.


33

Jeffrey Couch, Non-Executive Director

Mr Jeffrey Couch is Managing Director and Head of Investment and Corporate

Banking Europe for BMO Capital Markets, a leading North American financial

services provider. Previously, Mr Couch was Head of Business Development and

M&A at Eurasian Natural Resources Corporation PLC. Mr Couch is a qualified

Canadian lawyer, and attended the University of Western Ontario Business School

and Osgoode Hall Law School in Canada. Mr Couch has 15 years of investment

banking and capital markets experience having worked for Kleinwort Benson,

Citigroup (Salomon Brothers) and Credit Suisse. He has extensive experience in the

natural resources sector having advised and raised capital for clients globally, with a

particular focus in emerging markets and Africa.

David King, Non-Executive Director

Dr King is a professional geoscientist and has over 30 years ’ experience in oil and

gas and other natural resources industries. He has co-founded, as well as held

executive and non-executive board positions with, a number of successful ASX listed

oil and gas exploration companies, including Eastern Star Gas Limited, Gas2Grid

Limited and Sapex Limited. He is a Fellow at the Australian Institute of Company

Directors, the Australian Institute of Geoscientists, and Australian Institute of Mining

& Metallurgy and a Chartered Professional (Management). Dr King has an MSc in

Geophysics from Imperial College, London, and a PhD in Seismology from the

Australian National University, Canberra.

Dr King is currently non-executive Chairman of two ASX listed companies; oil & gas

exploration company Galilee Energy Limited, and biotechnology research and

development company, Cellmid Limited. He is also a Director of unlisted Shale

Oil/Gas explorer Tamboran Resources. In a long corporate career, he has also

served as Managing Director of ASX listed gold producer North Flinders Mines, and

CEO of Oil/Gas producers Beach Petroleum and Claremont Petroleum.

Bjarne Moe, Non-Executive Director

Mr Bjarne Moe has over 35 years’ experience in the oil and gas industry including

being the former Director General of the Oil and Gas Department of the Ministry of

Petroleum, Norway. Since 2011, Mr Moe has been an advisor to the oil and gas

industry and has had several large, international companies as clients.

Timothy Turner, Non-Executive Director

Mr Turner is a senior partner with Australian accounting firm, Hewitt Turner &

Gelevitis. Mr Turner specialises in domestic business structuring, corporate and trust

tax planning and the issuing of audit opinions. Mr Turner has in excess of 21 years’

experience in new ventures, capital raisings and general business consultancy. Mr

Turner is also a Non-Executive Director of ASX listed entities Cape Lambert

Resources Limited and Legacy Iron Limited and a Non-Executive Director of NSX

listed International Petroleum Limited.

Anthony Wilson, Non-Executive Director

Mr Wilson has had a long career in a number of senior financial positions. Having

qualified as a Chartered Accountant, he initially became a partner in general practice

before moving into the investment banking sector initially with Wedd Durlacher

Mordaunt & Co, the stockjobber, and latterly with BZW, the investment banking

division of Barclays. Mr Wilson was Finance Director for BZW Securities and BZW


34

Asset Management over a period of 10 years. Following BZW, Mr Wilson held

various senior management roles as a director for DAKS Simpson Group Plc and

Panceltica Holdings Plc.

Angeline Hicks, Company Secretary

Angeline Hicks is a Chartered Accountant with global corporate and financial

experience. After gaining her qualifications at Deloitte, Ms Hicks furthered her career

in the banking industry in London for eight years, working for investment banks such

as Barclays Capital, Credit Suisse and JP Morgan, focusing on managing compliance

and corporate and financial reporting. Ms Hicks was previously Chief Financial

Officer and Company Secretary of UK (AIM) listed Hot Tuna and is currently

Company Secretary for ASX listed Minera Gold Limited.

Senior Management

Stephen West, Finance Director

Mr West is a qualified Chartered Accountant who holds a Bachelor of Commerce

(Accounting and Business Law) from Curtin University of Technology in Australia. He

has over 22 years of financial and corporate experience gained in public practice, oil

and gas, mining and investment banking spanning Australia, United Kingdom,

Europe, CIS and Africa. Mr West is currently a non-executive director of ASX listed

Apollo Consolidated Limited (mining exploration company with permits in Australia

and Côte d’Ivoire) and Zeta Petroleum plc (oil & gas exploration and production

company with permits in Romania).

Jens Pace, Chief Operating Officer

Mr Pace is a highly regarded geoscientist, who has had a successful career at BP, and its

heritage company Amoco, spanning over 30 years. Jens has held senior positions at BP

for over 10 years, gaining substantial exploration and production experience in Africa,

namely: Algeria, Angola, Congo, Gabon and Libya, having also gained extensived

experience in Europe, Russia and Trinidad. He has contributed to a number of BP’s

exploration discoveries over his career. Most recently, Jens managed a very large and

active exploration portfolio for BP in North Africa. Additionally, he has gained highly

sought after experience in the areas of field development and as a commercial manager,

dealing with national oil companies and African governments. Jens holds a BSc in

Geology and Oceanography from the University of Wales and an MSc in Geophysics from

Imperial College, London.

Michael Barrett, Exploration Director

Mr Barrett has over 20 years global exploration experience from his career at

Chevron, and more recently at Addax/Sinopec International. Michael has a BSc in

Geology & Geophysics from Durham University and a MSc in Petroleum Geology &

Geophysics from Imperial College, Royal School of Mines. Michael has held a variety

of technical roles covering exploration and new ventures, and was part of Chevron’s

global Exploration Review Team, specialising in Play and Prospect risk assessment,

volumetric analysis, commercial evaluation and portfolio management. Michael also

brings added strength to the team with his background in quantitative geophysics,

stratigraphic interpretation workflows and 3D visualisation.

RECOMMENDATIONS HISTORY Market index Oslo Axess All Share

Date Market Index

level

Share Price

(NOK/shr)

Target Price

(NOK/shr)

Opinion

African Petroleum

4 Nov. 2014 78.8 0.63 3.87 BUY 8 Jun. 2015 84.0 0.35 0.88 BUY

RATINGS, CERTIFICATION AND DISCLOSURE

RATINGS SYSTEM

BUY: The stock is expected to generate absolute positive price performance of over 20% during the next 12 months.

ACCUMULATE: The stock is expected to generate absolute positive price performance of 10-20% during the next 12 months

NEUTRAL: The stock is expected to generate absolute price performance of between 10% positive and 10% negative

during the next 12 months.

REDUCE: The stock is expected to generate absolute negative price performance of 10-20% during the next 12 months

SELL: The stock is expected to generate absolute negative price performance of over 20% during the next 12

months.

RISK Qualifier: Speculative

Stocks bear significantly higher risk that typically cannot be valued by normal fundamental criteria. Investments in the stock may result in material loss.

INVESTMENT ANALYST CERTIFICATION

All research is issued under the regulatory oversight of Mirabaud Securities LLP

Each Investment Analyst of Mirabaud Securities LLP whose name appears as the Author of this Investment Research hereby certifies that the recommendations and opinions expressed in the Investment Research accurately reflect the Investment Analyst's personal, independent and objective views about any and all of the Designated Investments or Relevant Issuers discussed herein

that are within such Investment Analyst's coverage universe.

INVESTMENT RESEARCH DISCLOSURES

The following disclosures relate to this document: 2, 8

1. This is a commissioned or a non-objective research note/comment.

2. In the past 12 months Mirabaud Securities or its affiliates have had Corporate Finance mandates or managed or co-managed a public offering of the relevant Issuer's securities or received compensation for Corporate Finance services from the Relevant Issuer, excluding acting as a corporate broker, on a retained basis, for the Relevant Issuer.

3. Mirabaud Securities expect to receive or intend to seek compensation for Corporate Finance services from this company in the next 6 months, excluding acting as a corporate broker, on a retained basis, for the Relevant Issuer.

4. The Investment Analyst or a member of the Investment Analyst's household has a long position in the shares or

derivatives of the Relevant Issuer.

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derivatives of the Relevant Issuer.

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7. A senior executive or director of Mirabaud Securities, or a member of his / her household, is an officer, director, advisor, or board member of the Relevant Issuer and/or one of its subsidiaries.

8. Mirabaud Securities acts as corporate broker, on a retained basis, for the Relevant Issuer.

The Investment Analysts who are responsible for the preparation of this Investment Research are employed by Mirabaud Securities LLP a securities broker-dealer. The Investment Analysts who are responsible for the preparation of this Investment Research have received (or will receive) compensation linked to the general profits of Mirabaud Securities LLP.

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Mirabaud - APCL Research Note.pdf

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