Africa Oil and Gas Nov 17%255B1%255D[1]

Oil and gas Africa

Sector reportEquity Research

17 November 2008

Crude valuationsLow cost oil and M&A in Africa

Adam J. Zive+234 (01) 448 [email protected]

Alexander Burgansky+7 (495) 258 [email protected]

Elena Savchik+7 (495) [email protected]

Evgenia Dyshlyuk+7 (495) 258 [email protected]

Irina Elinevskaya+7 (495) 783 [email protected]

Odalo Addeh+234 (01) 448 [email protected]

Important disclosures are found at the Disclosures Appendix. This research material is released by Renaissance Securities (Cyprus) Limited. Regulated by the Cyprus Securities & Exchange Commission (License No: KEPEY 053/04).

Crude valuations Low cost oil and M&A in Africa

Adam J. Zive +234 (01) 448 5387 [email protected] Alexander Burgansky +7 (495) 258 7904 [email protected] Elena Savchik +7 (495) 725-5265 [email protected] Evgenia Dyshlyuk +7 (495) 258 7777 [email protected] Irina Elinevskaya +7 (495) 783 5662 [email protected] Odalo Addeh +234 (01) 448 5387 [email protected]

Sector report Equity Research

November 2008

Oil and gas Africa

�

� We are initiating coverage of the Sub-Saharan African oils. Our BUY-rated companies are Addax Petroleum, Afren plc, Heritage Oil and Oando plc. Our HOLD-rated companies are Mart Resources, Sterling Energy and Tullow Oil.

� Crude valuations. We believe current valuation levels create a buying opportunity for long-term investors in large capitalisation companies such as Addax Petroleum at a significant discount to NAV, and companies with significant potential to increase reserves that have limited financing risk such as Afren. Our top near-term M&A candidate is Heritage Oil which we believe could attract significant bid premia. Oando plc is attractive relative to the Nigerian petroleum marketers and offers integrated growth with an indigenous advantage, in our view. Our NAV models indicate that the sector is currently trading at $41/bbl Brent, half of our long-term oil price forecast of $80/bbl.

� Potential financing constraints and relative value. Our HOLD-rated companies are Mart Resources, Sterling Energy and Tullow Oil. Mart and Sterling are both undervalued relative to our NAV estimates; however, financing constraints could curtail future production growth and/or exploration. Of the larger capitalisation names, we believe Addax offers better relative value than Tullow as well as a stronger near-term production profile.

� Switch from unconventional to conventional. With lower finding and development (F&D) and operating costs, African oil producers should be favoured in a lower oil price environment and will continue to provide robust returns on capital. The African continent also offers many of the most prolific conventional onshore and offshore exploration and development opportunities.

Important disclosures are found at the Disclosures appendix. This research material is released by Renaissance Securities (Cyprus) Limited. Regulated by the Cyprus Securities & Exchange Commission (License No: KEPEY 053/04).

Report date: 17 November 2008 Total sector MktCap, $mn 9,912.90 Target MktCap, $mn 14,437.45 Average sector 2010E P/E 2.7 Average sector 2010E EV/EBITDA 2.0 Average sector EV/2P reserves, $/boe 8.51 Average sector EV/2010E production, $/boe 38,714

Summary sector ratings Ticker Company Current price Target price Rating Upside MktCap $mn EV, $mn AXC Addax BPN820.00 BPN2,400.00 BUY 192.7% 2,094.41 3,565.80 AFR Afren BPN39.50 BPN91.00 BUY 130.4% 273.28 488.43 HOIL Heritage Oil BPN179.50 BPN290.00 BUY 61.6% 715.56 787.34 UNIP Oando NGN125.28 NGN200.00 BUY 59.6% 960.71 1,597.71 MMT Mart CAD0.065 CAD0.35 HOLD 438.5% 20.20 52.00 SEY Sterling BPN3.75 BPN3.00 HOLD -20.0% 136.36 78.40 TLW Tullow BPN453.5 BPN600.00 HOLD 32.3% 5,139.28 5,616.50

Source: Renaissance Capital estimates

Figure 1: Price performance – 52 weeks Figure 2: Sector stock performance – 3 months

-110%

-10%

90%

190%

290%

Nov-

07

Dec-

07

Jan-

08

Feb-

08

Mar

-08

Apr-0

8

May

-08

Jun-

08

Jul-0

8

Aug-

08

Sep-

08

Oct-0

8

S&P Energy Index HOIL TLWSEY AXC AFRMMT Oando

SEYMMTAXCAFRHOILTLW

OANDO

-500% -400% -300% -200% -100% 0%

Source: MSCI, Bloomberg Source: MSCI, Bloomberg

2007 Reviewed

November 2008 Africa oil and gas Renaissance Capital

2

Executive summary 3

Crude valuations: Low cost oil and M&A in the African oil patch 3 Crude valuations: Easiest trade is Addax, Heritage for M&A, Afren and Oando for growth 6

Increasing M&A activity 9 Elephant hunters: An endangered E&P species 11 Niger Delta 12

Significant low risk development opportunities in the Niger Delta 12 But no end in sight for the ongoing conflict… 12

Nigeria gas monetisation… a long-term strategy 14 Nigerian flares down? 14

Growing low cost reserves 15 Near –term commodity price weakness 18

Near-term commodity price weakness, position for long term 18 The companies 21

Addax Petroleum 23 Afren plc 51 Heritage Oil 75 Oando plc 95 Mart Resources 117 Sterling Energy 133 Tullow Oil 147

Disclosures appendix 179

Contents

Renaissance Capital Africa oil and gas November 2008

3

Crude valuations: Low cost oil and M&A in the African oil patch We are initiating coverage of the African oils. We believe the African oils sector offers an attractive combination of low valuation, low cost and prolific development and exploration opportunities. While the current deterioration of global economic prospects and medium-term oil demand risk suggest continuing relative weakness for the sector, our long-term view of the oil price stabilising at the level of marginal production cost ($80/bbl) is unchanged. This creates a significant buying opportunity for investors with a longer-term horizon with our coverage universe currently reflecting long-term oil price expectations of only $41/bbl Brent.

Our BUY-rated E&Ps are Addax Petroleum (BUY, BPN2,400/share target price), our preferred large cap African producer; Afren (BUY, BPN91/share target price) with differentiated financing sources which should allow for continued NAV growth; and Heritage Oil (BUY, BPN290/share target price), which is, in our view, the most likely M&A candidate in our coverage universe.

Our BUY-rated Nigerian petroleum marketer is Oando (BUY, NGN200/share target price), which offers integrated growth with an indigenous advantage.

Our HOLD-rated E&Ps are Mart Resources (HOLD, CAD0.35/share target price), which offers deep value but likely requires M&A and/or privatisation to realise NAV; Sterling Energy (HOLD, BPN3/share target price) with significant exploration prospects but financing risk particularly prior to the sale of the company’s US business; and Tullow Oil (HOLD, BPN600/share target price) where production ramp-up does not begin until post the end of the decade.

The tables below show the comparable trading multiples of our coverage universe and our Brent oil price assumptions. On our estimates, our universe is currently trading at 5.5x and 3.6x 2008 and 2009 P/CF, 4.1x and 4.2x EV/EBITDA, 6.4x and 4.2x P/E, $38,714 per daily 2008 flowing barrel, and $8.51/barrel on a proved plus probable reserve basis. This is below global exploration and production (E&P) peers trading at 4.2x and 4.2x 2008 and 2009 P/CF, 3.7x and 3.5x EV/EBITDA, 8.7x and 7.8x P/E, $60,335 per daily flowing barrel and $13.40/barrel on a proved plus probable reserve basis, on our estimates.

Executive summary

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5

Figure 4: Oil price forecast, bbl 2009E 2010E 2011E 2012E

Brent 70 80 80 80 Bloomberg consensus 83 99 101 98

Source: Bloomberg, Renaissance Capital estimates

Although the African oil patch has certainly received increased interest in the recent rising oil price environment, significant investor and industry interest has also been directed toward unconventional resources such as the Canadian oil sands. With the recent decrease in oil prices and increases in development and operating costs, we believe that a preference towards conventional resources from unconventional resources is underway for investors, corporates and national oil companies (NOCs). The African continent, with F&D costs and operating costs below the $5/bbl range for many onshore and shallow water developments, should benefit from a shift in relative interests in a commodity price environment that will still allow for very attractive returns for conventional oil prospects.

M&A activity is likely to increase in the African oil patch driven by a combination of: 1) lower public equity valuations which will entice cash-rich NOCs and access to resource buyers as well as larger capitalisation E&Ps and integrateds, and 2) a lack of exploration risk capital that will force distressed companies without access to capital and/or cash flow to sell at a fraction of potential NAV. There are two ways to benefit from this trend. First is to invest in large capitalisation oils, such as Addax Petroleum, which will have the opportunity to consolidate African oil assets at depressed prices. Second is to buy companies, like Heritage Oil, which own operated interests in large oil discoveries, are well capitalised and have relatively low enterprise values. We would caution investors against buying companies that are not well capitalised and therefore may not be able to continue exploration programmes and will be forced to sell at a significant discount to NAV.

Although risked prospective resources are not receiving value in the current market, Africa continues to offer some of the most prolific global exploration prospects and a number of emerging basins and new play types. This has recently been demonstrated by the Jubilee discovery offshore Ghana (Tullow Oil), the largest oil discovery in 2007 with estimated P90-P50-P10 reserves of 500 mmbbl, 1,000 mmbbl and 1,800 mmbbl, respectively. The discovery of the Lake Albert Basin (Tullow, Heritage Oil), which is likely to be greater than a billion barrels in place, also demonstrates the ongoing potential of Africa. Significant near-term exploration targets to be drilled by our coverage universe include the Cuda prospect on the Keta Block offshore Ghana (Afren), a series of exploration wells in the Joint Development Zone (Addax Petroleum, Afren), and in East Africa targets in Tanzania (Heritage, Tullow Oil) and Madagascar (Sterling). Within our coverage universe, Addax, Heritage and Sterling also have significant exploration targets to be drilled in Kurdistan.

Africa also offers many of the most prolific low geological/reservoir risk development opportunities, particularly in the Niger Delta. Nigeria is producing approximately 1.98 mmbpd, below production capacity of 2.55 mmbpd that does not include additional shut-in volumes of 500 kbpd as estimated by the International Energy Agency (IEA). Remaining commercial reserves are estimated by Wood Mackenzie at 19bn barrels of liquids (oil/condensate) in Nigeria, with 71% estimated to be in the onshore or shelf areas of the Niger Delta. There have been a number of successful E&P companies built out of the Niger Delta including Addax Petroleum and Afren plc and

2007 Reviewed


6

we see many similarities between this highly prospective region and the North Sea and Gulf of Mexico 15 years ago – a time period that allowed for the creation of many successful junior companies that later became super-independents. Additionally, political sentiment in Nigeria is clearly focused on further indigenous development of assets. Local indigenous companies and those international companies with technical expertise and financing that can partner with the right local indigenous companies will continue to be rewarded in this space.

The African continent also accounts for 8.2% of global natural gas reserves and 6.5% of total natural gas production. Nigeria alone is estimated to have 187 tcf of natural gas reserves (BP Statistical Review of World Energy 2008) and currently flares approximately 2 bcfpd (although technically gas flaring is supposed to stop by year-end). We expect to see significant continuing opportunities for African natural gas to be monetised in conjunction with the development of the global LNG market and to satisfy domestic energy markets that are shockingly undersupplied. We also note that exploration in the region has traditionally not focused on natural gas and therefore there is significant potential to grow natural gas reserves going forward. However, the key drivers to natural gas monetisation in many cases is allowable sales gas pricing and local domestic energy requirements, highly politicised issues that can delay projects significantly.

The African refinery complex is also significantly lacking and/or underutilised. Nigeria, for instance, currently has four refineries with combined nameplate capacity of 445 kbpd which operated at approximately 10% of capacity in 2007. Refining also tends to be a highly politicised issue due to state ownership of infrastructure.

Crude valuations: Easiest trade is Addax, Heritage for M&A, Afren and Oando for growth Our preferred large capitalisation African oil is Addax Petroleum (BUY, BPN2,400/share target price), an African value play with exploration upside. Addax offers an attractive combination of: 1) low valuation, 2) expected production growth potential per annum of approximately 10%-plus in 2009 and 2010, 3) high impact exploration in West Africa and Kurdistan, 4) ramp-up of production volumes at Taq Taq in Kurdistan, 5) possible natural gas monetisation in Nigeria, and 6) a strong balance sheet with debt facilities available that could allow the company to consolidate African E&P assets at depressed prices and/or drill further high impact exploration wells at reduced rig rates.

We recommend Addax Petroleum as a long-term core holding in an African and global E&P portfolio. The company has an attractive combination of development, appraisal and exploration assets in West Africa and significant exploration and development opportunities in Kurdistan. We believe that current valuation levels present an opportunity to build equity positions for investors with a long-term time horizon in a company that has a proven track record of creating value for shareholders.

Afren (BUY, BPN91/share target price) offers attractive valuation, while the recent Sojitz strategic alliance allows for continued growth. Afren offers an attractive combination of: 1) low valuation, 2) unique positioning to continue to exploit low risk development opportunities in Nigeria, 3) production ramp-up at Okoru Setu to 21


7

kbpd, 4) 2H08 is expected to be the first interim of positive operating earnings and cash flow, 5) near-term high impact exploration potential in Ghana, 6) the company has access to a differentiated source of financing with the Sojitz strategic alliance and $269mn of cash as at 30 June 2008, and 7) longer-term potential for Nigerian gas monetisation.

With differentiated sources of financing, we believe that Afren will have the opportunity to continue to consolidate African oil and gas assets. This is particularly true in the Niger Delta where we expect the majors to continue to divest non-core and sub-scale assets to indigenous companies and throughout Africa where we believe there will be significant opportunities to acquire exploration and development assets at discounted prices in the near term.

Lake Albert Basin drives near-term M&A potential for Heritage Oil (BUY, BPN290/share target price). Heritage offers an attractive combination of: 1) compelling valuation, 2) significant non-producing asset value with potential to declare commerciality in Uganda by year-end, 3) further high impact exploration in Uganda with four wells expected to be drilled in 4Q08 and the first Kurdistan well to be drilled in 1Q09, 4) first production from the West Bukha field in Oman, 5) most likely M&A candidate of our coverage universe with an undeveloped world-class discovery at Lake Albert and an enterprise value of only $855.50 mn, 6) potential for divestiture of assets in Russia and Oman, 7) a strong balance sheet with $113 mn in cash.

Our preferred Nigerian petroleum marketer is Oando (BUY, NGN200/share target price), which offers integrated growth with an indigenous advantage. Oando has strong growth prospects and is well positioned with: 1) preferential access to upstream resources and services contracts as an indigenous company, 2) production growth in the upstream and strong sustainable revenue growth in gas & power and energy services, 3) plans to monetise a portion of the retail marketing business, 4) high-grading of the business mix with growth in higher margin segments, and 5) potential to benefit from the privatisation of NNPC and the Nigerian Gas Master Plan.

With recent expansion into the upstream and energy services, Oando has the opportunity to benefit from preferential access to resources and upstream energy contracts due to the company’s indigenous status. In the near term, we believe that Oando is well positioned to expand the company’s presence in the higher margin upstream, services and gas and power distribution businesses and could potentially monetise a portion of the value of the retail marketing business.

Mart Resources (HOLD, CAD0.35/share target price) offers deep value in a marginal field pure play; however, M&A/privatisation is likely required to realise NAV.

Mart Resources offers a combination of: 1) deep value trading at less than a third of our NAV estimate and at approximately 1x estimated 2009 operating cash flow, 2) potential for 2009 production growth of 50% with further success at Umusadege, 3) potential for a local financing advantage given the current liquidity in the Nigerian banking system although financing remains a key risk for the company’s growth plans, and 4) potential M&A or take private potential with the company trading at a significant discount to NAV and as an attractive asset package for entry into Nigeria.

2007 Reviewed


8

While our analysis indicates that the company is considerably undervalued, we believe that it is likely that Mart would have to be acquired or privatised for investors to realise value in the near term. Based on our estimates, we forecast that Mart will be earnings and cash flow positive in 2H08 and 2009 based on our $70/bbl Brent price forecast.

While Sterling Energy (HOLD, BPN3/share target price) offers significant high impact exploration in 2009, the sale of the US business is key to de-risking the story.

Sterling Energy offers a combination of: 1) high-impact exploration prospects in Kurdistan and potentially Madagascar that are to be drilled in 2009 with unrisked best estimate net prospective resources of 500 mmboe, 2) recently increased production levels at Chinguetti should allow for the company to be cash flow positive in 2009, 3) the pending sale of the US business and recently signed farm-out agreements would allow for the company to retire all outstanding debt and to be left with a significant cash balance.

Sale of the US business derisks the story. We are bullish on the near-term exploration prospects for Sterling, particularly at Sangaw North in Kurdistan where the company has recently farmed out to Addax Petroleum. However, in the current financing environment, we are cautiously optimistic on the company pending the sale of the US business. Sterling has a sales agreement in place for the company’s US assets conditional on financing and this sale is key to de-levering and de-risking the Sterling story to move the company to a net cash position.

Tullow Oil (HOLD, BPN600/share target price) has significant non-producing asset value but investors can wait with production ramp-up not occurring until 2011.

Tullow Oil offers a combination of: 1) world class developments at Jubilee and Lake Albert in Uganda, 2) significant non-producing asset value with the potential to almost triple net production by 2013, 3) further potential high impact exploration in Uganda, Ghana, Cote d’Ivoire, and Mauritania and 4) a significant expected near-term reduction of net debt with the closing of the M’boudi and Hewett divestitures. The main risks for Tullow are execution risk at the Jubilee development as the company’s first major operated deepwater asset, and timing of first production at Lake Albert, particularly in a prolonged low oil price environment.

Although current valuation levels are below NAV for the company, investors can afford to wait with production ramp-up not occurring until post the end of the decade.


9

M&A activity is likely to increase in the African oil patch driven by a combination of: 1) lower public equity valuations that will entice cash-rich NOCs and access to resource buyers as well as larger capitalisation E&Ps and integrateds, and 2) a lower appetite for exploration risk capital that will force distressed companies without access to capital to sell at a fraction of potential NAV.

There are two ways to benefit from this trend. First is to invest in large capitalisation oils such as Addax Petroleum which will have the opportunity to consolidate African oil assets at depressed prices.

Second is to buy companies like Heritage Oil which own operated interests in large oil discoveries, are well capitalised and have relatively low enterprise values. There is significant scope for further acquisitions in Africa given ongoing access to resources issues, the growing appetite of NOCs and sovereign wealth funds to acquire energy assets and the unique combination

We would caution investors against buying companies that are not well capitalised and therefore may not be able to continue exploration programmes and therefore are forced to sell at a significant discount to NAV.

We would not completely rule out any of the E&P companies in our coverage universe as acquisition candidates given ongoing access to resources issues, the growing appetite of NOCs and sovereign wealth funds to acquire energy assets and the unique combination with our universe of large resource potential, relatively low development costs as compared with unconventional resources, and low enterprise value relative to potential resources and production. However, we believe that Addax Petroleum as a result of the asset base, size and management shareholding of the company, Tullow Oil due to the company’s non-operated interests and size, and Afren are less likely to be acquired. While Heritage is the most likely company in our universe to be acquired for significant bid premia, there is also M&A potential for Sterling Energy, however, we believe further farm-ins are more likely. We also believe that Mart Resources is likely a take private or M&A candidate given current company valuation.

Please see the following ftables that show Africa historic transactions.

Increasing M&A activity

2007 Reviewed

10


Figure 5: Recent Africa M&A transactions

Announced date Buyers Sellers Location

Total transaction value, $mn

Proved+Probable (2P) reserves total

mn boe @6:1 Daily boe/D production EV/2P

EV/Daily production

(boe) 9/8/2008 Eni SpA First Calgary Petroleums

Ltd Algeria 954.1 585.5 - 1.63 -

7/25/2008 Oando Plc Eni SpA Nigeria 188.4 - 2,710 - 69,529 5/30/2008 Beach Petroleum Ltd Egypt Kuwait Holding Co Egypt 110.0 8.0 - 13.75 - 4/8/2008 GEPetrol Devon Energy Corporation Equatorial

Guinea 2200.0 208.3 20,000 10.56 110,000

4/2/2008 Eni SpA Royal Dutch Shell plc Nigeria 625.8 - 9,000 - 69,529 3/16/2008 Sudan National

Petroleum Corporation; Mohamed Abdulmohsin Al Kharafi and Sons Company

Thani Investments LLC; Al Thani Corporation

Sudan 500.0 - 10,000 - 50,000

3/5/2008 Afren plc Devon Energy Corporation Cote d'Ivoire

205.0 28.3 5,000 7.24 41,000

2/25/2008 Oando Plc Royal Dutch Shell plc Nigeria 625.8 - 9,000 - 69,529 1/31/2008 Korea National Oil

Corporation Tullow Oil plc Congo 435.0 30.7 4,070 14.17 106,880

11/13/2007 Oranje-Nassau Groep BV

Devon Energy Corporation Gabon 205.5 10.2 3,750 20.24 54,800

9/27/2007 Petroliam Nasional Berhad

Woodside Petroleum Ltd Mauritania 418.0 24.0 7,307 17.42 57,205

9/5/2007 TransGlobe Energy Corporation

Tanganyika Oil Company Ltd; Private Co

Egypt 59.0 6.3 1,500 9.37 39,333

8/2/2007 Logria Corp; National Petroleum Company SAE; Citadel Capital Company

Rally Energy Corporation Egypt 807.5 105.2 6,294 7.67 128,295

4/18/2007 Dana Petroleum plc Devon Energy Corporation Egypt 308.0 30.0 12,500 10.27 24,640 4/13/2007 Ras Al Khaimah

Petroleum PJSC Gulf Keystone Petroleum Ltd

Algeria 299.8 - - - -

3/19/2007 Burren Energy Plc Eni SpA Congo 154.0 14.3 1,769 10.80 87,069 2/22/2007 Eni SpA Etablissements Maurel et

Prom Congo 1434.0 126.0 17,000 11.38 84,353

11/23/2006 BowLeven plc FirstAfrica Oil Plc Mauritania 106.8 - 7,000 - 15,261 11/13/2006 Dana Gas PJSC Centurion Energy

International Inc Egypt 1056.7 97.0 32,069 10.89 32,950

9/25/2006 Tullow Oil plc Hardman Resources Ltd Mauritania 1010.6 10.1 6,000 100.35 168,426 7/20/2006 Addax Petroleum

Corporation Pan-Ocean Energy UK Ltd; PanAfrican Energy Corporation (Mauritius) Ltd; Pan-Ocean Energy Corp Ltd

Gabon 1415.9 67.5 10,000 20.99 141,588

4/13/2006 Melrose Resources plc Merlon Petroleum Company

Egypt 269.3 23.2 5,325 11.60 50,579

2/22/2006 Centurion Energy International Inc

Merlon Petroleum Company

Egypt 225.0 23.2 5,325 9.69 42,256

1/9/2006 CNOOC Ltd South Atlantic Petroleum Nigeria 2692.0 270.0 - 9.97 - ----------------------------------- Median -------------------------------------------- 427 29.15 6,647 10.85 63,367

------------------------------------ Average -------------------------------------------- 679 92.65 8,781 17.43 72,161 Source: J.S. Herold


11

From an exploration perspective, new technologies and higher oil prices relative to historic levels are opening up new basins and allowing for deeper, higher-risk exploration targets to be drilled within the African continent. This has recently been demonstrated by the Jubilee discovery offshore Ghana (Tullow Oil), the largest oil discovery in 2007 with estimated P90-P50-P10 reserves of 500 mmbbl, 1,000 mmbbl, and 1,800 mmbbl, respectively. The discovery of the Lake Albert Basin (Tullow, Heritage Oil), which is likely to be greater than a billion barrels in place, also demonstrates the ongoing potential of Africa. Significant near-term exploration targets to be drilled by our coverage universe include the Cuda prospect on the Keta Block offshore Ghana (Afren), a series of exploration wells in the Joint Development Zone (Addax Petroleum, Afren), and in East Africa targets in Tanzania (Heritage, Tullow Oil) and Madagascar (Sterling). Within our coverage universe, Addax, Heritage and Sterling also have significant exploration targets to be drilled in Kurdistan.

Elephant hunters: An endangered E&P species

2007 Reviewed

12


Significant low risk development opportunities in the Niger Delta There are also significant low-risk development opportunities in SSA. This is particularly true in Nigeria with current production of 1.98 mmbpd, well below sustainable production capacity of 2.55 mmbpd that does not include additional shut-in volumes of 500 kbpd as estimated by the IEA. Proper allocation of capital, new recovery and drilling technologies and an increase in indigenous ownership or indigenous partnerships could allow for significant increases in oil production in the Niger Delta. We see many similarities between this highly prospective region and the North Sea and Gulf of Mexico 15-20 years ago – a time period that allowed for the creation of many successful junior companies that later became super-independents. Additionally, political sentiment in the country is clearly focused on further indigenous development of assets. Local indigenous companies and those international companies with technical expertise and financing that can partner with the right local indigenous companies will continue to be rewarded in this space.

The African continent also accounts for 8.2% of global natural gas reserves and 6.5% of total natural gas production. Nigeria alone is estimated to have 187 tcf of natural gas reserves (BP Statistical Review of World Energy 2008) and currently flares approximately 2 bcfpd (although technically gas flaring is supposed to stop by year-end), We expect to see significant continuing opportunities for African natural gas to be monetised in conjunction with the development of the global LNG market and to satisfy domestic energy markets that are shockingly undersupplied.

We also believe there is a unique opportunity for Nigerian petroleum marketer Oando to benefit from preferential access to upstream assets in Nigeria.

But no end in sight for the ongoing conflict… While the Niger Delta was originally destabilised due to disassociated communities and environmental degradation in the region, we believe the predominant motivation for ongoing attacks, bunkering and kidnapping at this stage is profit driven. At current oil prices and assuming approximately 100 kbpd is stolen in the Delta, this equates to a $2bn per annum business (excluding ransom payments).

Military action in the region has a short-term impact but ongoing occupation will be required to have long-standing implications and will be very difficult given that the Delta is a swampy mangrove. Additionally, while it is possible to negotiate to an extent with local leaders, in many cases the local leaders cannot control the actions of their ‘local boys’. Furthermore, in the past, many local leaders have not used funds provided by oil companies to improve their communities.

Most of the attacks and kidnappings in the region are directed at the majors, particularly Shell. The smaller international companies and indigenous producers have not had the same problems although there have been isolated events. Additionally most of the activity is concentrated in the south central Delta. It is difficult for the various militant groups to have mobility throughout the Delta given historical tribal boundaries. In this respect, the best way to manage security issues in the shallow water is to produce from assets in the Northwest or Southeast area of the Delta.

Niger Delta


13

Recently, there has been an increase in the sophistication of militant activity with MEND attacking Shell’s Bonga facility 120 km offshore in June. Previously, offshore facilities were assumed to be too difficult for the militants to access which is why much of the new capital investment of the international oil companies has been shifted to these developments.

14


Although natural gas sales have occurred in Nigeria since 1976, the major customer is PHCN, the government electricity producer that pays producers approximately $0.10/mcf. While some industrial customers pay closer to commercial rates at a level of $3.00, this is a very small part of current demand and an even smaller portion of potential supply.

The Nigerian Gas Master Plan was announced in May 2008 with the aim to fully exploit the natural gas resources in the country, in pursuit of the federal government’s 10% GDP growth aspirations. The plan includes an integrated infrastructure strategy to support domestic, regional and export LNG markets. We note that that Emmanuel Odusina, the minister of state for energy in charge of gas, was dismissed in the recent cabinet reshuffle – a situation which could delay the implementation of the Nigerian Master Gas Plan.

Additionally, monetisation of natural gas resources continues to be highly politicised. For example, on 1 Aug 2008, the federal government of Nigeria granted approval to a consortium of Addax Petroleum, Chrome Oil Services Limited and Korea Gas Corporation for an integrated gas utilisation project on OML137. The project could secure the gas reserves necessary to commercialise a new LNG production facility of up to 10mn tonnes per annum to be situated on Brass Island in Bayelsa State, provide domestic power generation capacity of up to 1,000 MW, and provide feedstock for the development of petrochemical facilities. However, the consortium still must negotiate with the Nigerian Ministry of State for Energy (Gas), the Department of Petroleum Resources and the Nigerian National Petroleum Corporation to establish fiscal and commercial terms for the upstream and downstream portions of the project.

Nigerian flares down? We note that although Nigeria currently flares approximately 2 bcfpd of natural gas, the government has never enforced the no-flaring legislation that was originally introduced in the 1980s. Historically, operators have paid a flaring penalty of $0.07/mcf, although the federal government has stated that this penalty is to rise to up to $3.50/mcf beginning in Jan 2009. However, we understand that the required legislation to put this penalty into force is unlikely to be passed before this deadline.

Nigeria gas monetisation… a long-term strategy


15

In 2007, Africa accounted for 13% of total global oil production, 9.5% of total global reserves and only 3.8% of global refining capacity (BP Statistical Review of World Energy 2008).

Please see the figure and charts below that illustrate global proved oil reserves and African reserves and production from the BP Statistical Review of World Energy 2008.

Figure 6: 2007 proved reserves, bn bbls

Source: BP Statistical Review of World Energy 2008

Figure 7: Africa proved reserves 2007, ‘000 mmbbl

05

1015202530354045

Libya

Nige

ria

Alge

ria

Ango

la

Suda

n

Egyp

t

Gabo

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Rep

of C

ongo

(Bra

zzav

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Equa

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l Guin

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Chad

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ca

Tunis

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Growing low cost reserves


16

Figure 8: Africa oil production, kbpd

0

500

1,000

1,500

2,000

2,500

Nige

ria

Alge

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Libya

Ango

la

Egyp

t

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Equa

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l Guin

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Rep.

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ongo

(Bra

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Chad

Tunis

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Othe

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Cam

eroo

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The African continent also accounts for 8.2% of global natural gas reserves and 6.5% of total global natural gas production. Please see the tables below that illustrate African natural gas reserves and production.

Figure 9: Africa gas reserves, tcf

020406080

100120140160180200

Nigeria Algeria Egy pt Liby a Other Africa



17

We expect oil and natural gas production and reserves in Africa to grow on an absolute basis and also as a percentage of total global production and reserves. The continent has had significant growth in reserves relative to global reserve growth, particularly in the past five years with reserve growth of 56.1% relative to global reserves growth of only 5%.

Africa also offers some of the lowest finding and development costs, particularly in the onshore and shallow water. In Nigeria, for instance, finding and development costs for oil in many cases remain below $5/bbl with operating costs in the same range. This is compared to global F&D costs for the supermajors in 2007 of $19.91/boe and other Global Emerging Market (GEM) oils of $10.52/boe.

Figure 10: 2007 gas production, bcf

0102030405060708090

Algeria Egy pt Nigeria Liby a Other Africa


18


Near-term commodity price weakness, position for long term Forecasts from the IEA, the US Department of Energy’s Energy Information Administration (EIA) and OPEC now average 0.4% demand growth in 2008 (lower than the July 2008 estimate of 1.0% and the Dec 2007 estimate of 1.9%). The three agencies now envisage 2009 demand growth of 0.9% vs the 1.5% forecast by EIA in May 2008. These forecasts are summarised in Figure 10.

Figure 12: Crude oil consumption: long-term trends, mmbpd

49.3 49.1 50.9 51.6 52.2 53.3

4.8 5.5 5.9 6.3 6.6 6.915.3 18.1 21.2 24.3 27.4 30.85.9 6.8 7.5 8.2 8.9 9.5

2.9 3.4 3.7 4 4.1 4.3

5.5 6.3 6.6 7 7.3 7.8

0

20

40

60

80

100

120

2005 2010E 2015E 2020E 2025E 2030E

OECD North America, Europe and Asia Non-OECD Europe and Eurasia Non-OECD Asia Middle East Africa Central and South America

59% 47%

Source: US DOE EIA

Near-term commodity price weakness

Figure 11: World oil supply/demand balance, mmbpd FY07 1Q08 2Q08 3Q08E 4Q08E FY08E 1Q09E 2Q09E 3Q09E 4Q09E FY09E Demand 85.9 86.5 85.4 85.9 87.9 86.5 87.4 86.2 86.8 88.7 87.3 IEA 86.1 86.8 85.7 86.5 88 86.8 87.8 86.5 87.3 89 87.6 US DOE 85.8 86 85.2 85.6 87.7 86.1 86.9 86 86.6 88.2 86.9 OPEC 85.9 86.7 85.4 85.7 88 86.5 87.5 86.1 86.4 88.9 87.2 Supply 84.7 86.2 86.3 86.2 87.9 86.7 87.5 87.2 87.5 87.9 87.5 Non-OPEC 49.4 49.3 49.4 48.8 50.4 49.5 50.5 50.2 50.1 50.4 50.3 IEA 49.6 49.8 49.7 49.1 51 49.9 51.4 50.6 50.1 50.6 50.7 US DOE 49 48.6 48.9 48.3 49.3 48.8 49 49.3 49.8 49.9 49.5 OPEC 49.4 49.6 49.6 48.9 50.8 49.7 51.1 50.6 50.3 50.8 50.7 Of which FSU 12.6 12.7 12.7 12.5 13.1 12.7 13.1 13.1 13 13.1 13.1 IEA 12.8 12.8 12.9 12.8 13.3 12.9 13.3 13.3 13 13.1 13.2 US DOE 12.6 12.6 12.6 12.3 12.8 12.6 12.8 12.8 13 13 12.9 OPEC 12.5 12.6 12.7 12.5 13.1 12.7 13.1 13.1 12.9 13.1 13.1 OPEC NGLs 4.5 4.7 4.7 4.9 5.1 4.8 5.3 5.5 5.8 6 5.7 IEA 4.8 4.9 4.9 5.1 5.4 5.1 5.6 5.8 6 6.1 5.9 US DOE 4.5 4.6 4.6 4.8 4.9 4.7 5.2 5.6 5.9 6.1 5.7 OPEC 4.2 4.5 4.7 4.8 4.9 4.7 5.1 5.2 5.5 5.6 5.4 Call on OPEC crude and stocks 32.1 32.5 31.3 32.2 32.5 32.2 31.6 30.5 30.9 32.3 31.3 IEA 31.7 32.1 31.1 32.2 31.7 31.8 30.8 30.1 31.2 32.3 31.1 US DOE 32.3 32.8 31.8 32.5 33.4 32.6 32.8 31.2 30.9 32.1 31.7 OPEC 32.3 32.6 31.1 32 32.3 32.1 31.3 30.3 30.6 32.5 31.1 OPEC crude 30.9 32.2 32.2 32.5 32.4 32.4 31.7 31.5 31.6 31.5 31.6 IEA 30.7 32.4 32.2 - - - - - - - - US DOE 30.9 32.1 32.3 32.7 32.4 32.4 31.7 31.5 31.6 31.5 31.6 OPEC 31 32.1 32.1 32.4 - - - - - - - Stock-build/(draw) -0.1 0.2 0.5 0.1 1 0.3 1 -0.4 -0.7 0.6 0.1 IEA -0.5 0.3 1.1 - - - - - - - - US DOE 1.4 0.7 -0.6 -0.2 1 0.3 1 -0.4 -0.7 0.6 0.1 OPEC -1.3 -0.5 1 0.4 - - - - - - -

Source: International Energy Agency October 2008 Monthly Oil Market Report, Department of Energy, OPECx


19

Declining US oil consumption has continued to drive down OECD oil demand by more than 1.8% in 2008, as estimated by OPEC. Factors affecting world oil demand, such as the slowing global economy, high retail prices and hurricanes led to a decline of more than 1.0 mmbpd in total OECD consumption in Sep 2008. At the same time, non-OECD oil demand growth increased 1.2 mmbpd YoY in September, led by Asia and the Middle East, as reported by OPEC.

Non-OPEC supply-growth estimates have again been reduced in recent months, meaning OPEC remains in the driving seat. Current non-OPEC supply growth expectations are 0.2% in 2008 (vs the July 2008 estimate of 0.4% and the Dec 2007 estimate of 2.1%) and 1.7% in 2009 (unchanged from July 2008 estimates). FSU supply growth accounts for a massive 102% of this in 2008 (vs just 63% estimated back in May 2008), with this ratio forecast to decline to 39% in 2009. This means FSU production is projected to grow 0.114 mmbpd in 2008 (vs the May 2008 estimate of 0.363 mmbpd) and 0.326 mmbpd in 2009 (0.650 mmbpd). This seems a stretch to us, given the trends in Russia and growing resource nationalism and concerns over production growth in Kazakhstan.

Taking the above demand and non-OPEC supply forecasts at face value, the IEA, EIA and OPEC forecasts of 7.6% growth in OPEC NGLs supply this year (broadly unchanged from their average May 2008 estimate), and a strikingly higher, and therefore suspect, in our view, 17.0% (0.820 mmbpd) in 2009 (vs an already high estimate of 11.5% in May 2008), balanced markets should require 0.3% (0.090 mmbpd) more OPEC crude (and stock draws) in 2008 than in 2007. This is likely to reverse in 2009, with the call on OPEC crude and stocks declining in 2009 for the first time in recent years by 0.860 mmbpd, or 2.8%.

In summary, declining global GDP growth continues to reduce oil demand estimates, but these have also been accompanied by supply restrictions which remain firmly under OPEC’s control. This is a very important issue, as Figure 13 indicates. Arguably, insufficient non-OPEC supply growth has been behind the price strength we have seen over the past three years. These conditions are now expected to continue at least until 2Q09 assuming, of course, that bullish non-OPEC supply growth estimates for 2009 actually hold. Actual demand growth and delays in project completion remain key global uncertainties for 2009, in our view.

We believe the world resource base is adequate overall to meet growing demand, although the current production capacity is limited, while development risks are high amid growing costs. Using reported 2007 data for global oil majors, GEM alternatives and Russian oil producers (discussed in detail in our 2008 Oil & Gas Yearbook, published on 29 July 2008), we estimate that average three-year finding and development costs have grown 14.0% for the supermajors, 20.7% for GEM and 21.1% for Russian oil companies over the past year.


20

Figure 13: Non-OPEC supply growth fails to meet demand growth, mmbpd

-2

-1

0

1

2

3

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1Q04 3Q04 1Q05 3Q05 1Q06 3Q06 1Q07 3Q07 1Q08 3Q08 1Q09E 3Q09E

-60

-30

0

30

60

90

120

Demand (mnbpd, LHS) Non-OPEC supply (mnbpd, LHS)Brent, $/bbl higher YoY (RHS)

Non-OPEC cannot meet demand grow th. Prices rise!

Non-OPEC cannot meet demand grow th. P i i !

Note: Non-OPEC production includes OPEC NGLs.

Source: IEA Monthly Oil Report, US DOE EIA’s Short Term Energy Outlook, OPEC Monthly Oil Market Report, Renaissance Capital estimates

The oil price has corrected sharply, and, as previously noted, is now below our long-term forecast of $80/bbl, which we see no reason to change. We believe the supply response will be very substantial if the oil price stays below $80/bbl for an extended period. Our analysis indicates that greenfield upgraded mining projects in the Alberta oil sands, the global marginal oil barrel, will require a minimum long-term oil price of $80/bbl to allow for an 8% return on capital. This analysis assumes long-term capital costs of: 1) CAD130,000/flowing barrel, 2) operating costs of CAD30/bbl, 3) a long-term $/CAD exchange rate of $0.90/CAD1, and 4) realisations of 97% of West Texas Intermediate (WTI). We also note that given the large number of planned oil sands projects, a lack of available skilled labour and trades in the region, major deficiencies in basic infrastructure to support growth and continuing environmental concerns, our capital and operating cost assumptions could prove to be low.

OPEC President Chakib Khelil has also confirmed that the $70-90/bbl range is ideal for the organisation, given the current economic environment. We view this as a very important statement given OPEC’s remaining control over global supplies (see Figure 13). At the same time, Christophe de Margerie, CEO of Total, said on 14 Oct that a lot of its projects will be dropped if the long-term oil price is $60/bbl.

Reduced calls on OPEC crude production in 2009, combined with estimated significant growth in OPEC’s surplus crude production capacity next year (see Figure 15; not least as a result of Saudi Arabia’s 500 kbpd AFK/Khursaniyah project, expected by IEA to be launched in the next few months) indicates a more balanced supply/demand outlook. However, given the significant project development risks facing most major projects worldwide, we believe these expectations could take longer to be realised, although the long-term trend is towards less volatile prices, in our view.

For further details please see our note published on 21 Oct 2008 entitled Oil and gas: The aftermath.


21

Th

e co

mpa

nies

22


Addax Petroleum Value play with exploration upside

Adam Zive +234 (1) 448-5300 x5387 [email protected]

Initiation of coverage Equity Research

17 November 2008

Oil and gas Africa

Report date: 30 October 2008Rating SELLTarget price (comm), $ 36Target price (pref), $ n/aCurrent price (comm), $ 12.12Current price (pref), $ n/aMktCap, $mn 1,886EV, $mn 2,959Reuters AXC.LBloomberg AXC:LNADRs/GDRs since 2006ADRs/GDRs per common share 1Common shares outstanding, mn 0Change from 52 week high: 73.06%Date of 52 week high: 06 September 2008Change from 52 week low: 0.00%Date of 52 week low 23 October 2008Web: www.addaxpetroleum.comFree float in $mn 0Major shareholder: STAY LOCAL LTD with 20.13%Average daily traded volume in $mn 518.68Share price performance over the last 1 month 57.39% 3 months 64.12% 12 months 63.22%

Figure 1: Price performance – 52 weeks

0

1,000

2,000

3,000

4,000

Nov-

07

Dec-

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Jan-

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Feb-

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05001,0001,5002,0002,5003,000BPNS&P Energy Index AXC

Source: Bloomberg

Figure 2: Sector stock performance – 3 months

OANDOTLWHOILAFRAXCMMTSEY

-500% -400% -300% -200% -100% 0%

Source: Bloomberg

Summary valuation and financials, $mn

Revenue EBITDA EPS, $ CFPS EV/

EBITDA P/E P/CF Net debt / Capital

Produc-tion mbpd

Oil Weight

Net Capex Plowback Dividend

Yield 2007 2,827.0 2458.0 3.39 8.48 1.45 3.78 1.51 0.41 116 100 1225 93% 1.65 2008E 4,063.8 3574.1 5.86 11.41 1.0 2.19 1.12 0.31 136 100 1612 87% 3.29 2009E 3,052.2 2542.7 4.22 8.87 1.4 3.04 1.45 0.31 150 100 1608 111% 3.29 2010E 4,542.5 3989.2 7.14 13.40 0.99 1.80 0.96 0.20 190 100 1693 77% 3.29


Report date: 17 November 2008 Rating BUY Target price (comm), BPN 2,400 Target price (pref), $ n/a Current price (comm), BPN 820 Current price (pref), $ n/a MktCap, $mn 2,094.41 EV, $mn 3,565.80 Reuters AXC.L Bloomberg AXC:LN Common shares outstanding, mn 163.4 Change from 52 week high: -71.58% Date of 52 week high: 06 September 2008 Change from 52 week low: 5.40% Date of 52 week low 23 October 2008 Web: www.addaxpetroleum.comFree float in $mn 1,350.89 Major shareholder with shareholding

Addax & Oryx 35.5%

Average daily traded volume in $mn 518.68 Share price performance over the last 1 month -21.16% 3 months -59.92% 12 months -61.80%

� We are initiating coverage of Addax Petroleum (AXC) with a BUY rating and BPN2,400/share target price. Our target price is equivalent to 4.0x 2009E cash flow and our production and development DCF-derived NAV estimate. Our total company NAV estimate rises to BPN2820/share after including best-estimate risked prospective resources. Total company NAV includes value for producing assets in Nigeria and Gabon, the Taq Taq development asset in Kurdistan, and risked exploration potential for Sangaw North in Kurdistan, Nigeria and the Joint Development Zone (JDZ). Addax is currently trading at 29% of our total company NAV and at a significant multiple discount to African and global E&P peers on 2009 multiples at 1.5x P/CF, 1.4x EV/EBITDA and at $11.67/bbl of 2P reserves.

� The company has an attractive combination of: 1) a low relative valuation; 2) expected annual production growth potential of approximately 10%-plus in 2009E and 2010E; 3) high impact exploration in West Africa and Kurdistan; 4) a ramp-up of production volumes at Taq Taq in Kurdistan; 5) the potential to monetise natural gas in Nigeria; and 6) a strong balance sheet with debt facilities available that could allow the company to consolidate African E&P assets at depressed prices and/or to drill further high impact wells at reduced rig rates.

� Core holding in African E&P. We recommend Addax Petroleum as a long-term core holding in an African and global E&P portfolio. The company has an attractive combination of development, appraisal and exploration assets in West Africa and significant exploration and development opportunities in Kurdistan. We believe that current valuation levels present an opportunity to build equity positions for investors with a long-term time horizon in a company that has a proven track record of creating value for shareholders.

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November 2008 Addax Petroleum Renaissance Capital

We are initiating coverage of Addax Petroleum (AXC) with a BUY rating and BPN2,400/share target price. Our target price is equivalent to 4.0x 2009E cash flow and is equal to our production and development DCF-derived NAV estimate. Our total company NAV estimate rises to BPN2,820 after including best-estimate risked prospective resources. Total company NAV includes value for producing assets in Nigeria and Gabon, the Taq Taq development asset in Kurdistan and risked exploration potential for Sangaw North in Kurdistan, Nigeria and the Joint Development Zone (JDZ). We have not included any value for Nigerian natural gas monetisation at this time.

On multiples, our target price equates to 4.2x 2009E and 2.8x 2010E P/CF, 3.0x and 1.9x 2009E and 2010E EV/EBITDA 8.9x 2009E and 5.3x 2010E P/E, $55,900 per 2009 daily flowing barrel and $24.88/2P bbl on a net basis (excluding natural gas).

Addax Petroleum is an E&P company with an enterprise value of $3,566mn. The company’s assets are located both onshore and offshore Nigeria and Gabon, in the JDZ between Sao Tome and Nigeria, Kurdistan and Cameroon.

Addax’s production is currently derived from properties in Nigeria offshore (74%), Nigeria onshore (5.3%), Gabon onshore (5.3%) and Gabon offshore (15.3%), and is 100% oil-weighted. As of the company’s last reserve report of 31 Dec 2007, oil reserves based on forecast prices and costs consisted of gross proved reserves (1P) of 233.3 mmbbl (176.7 mmbbl net), gross proved plus probable reserves (2P) of 446.7 mmbbl (305.5 mmbbl net), and gross proved plus probable plus possible reserves (3P) of 580.3 mmbbl (389.9 mmbbl net). Best estimate net contingent Nigerian natural gas resources are estimated at 2,414.8 bcf.

Addax Petroleum has an attractive combination of: 1) a low relative valuation; 2) expected annual production growth potential of 10%-plus in 2009E and 2010E; 3) exploration upside with 25 wells to be drilled in 2009E, targeting unrisked prospective resources of just under 700 mmbbl ; 4) a ramp-up of production at Taq Taq in Kurdistan; 5) the possibility that natural gas will be monetised in Nigeria; and 6) a strong balance sheet and debt facilities available that should allow the company to consolidate African E&P assets at depressed prices.

Addax Petroleum remains undervalued relative to international peers, trading at 1.45x 2009E and 0.96x 2010E P/CF, 1.40x 2009E and 0.89x 2010E EV/EBITDA, 3.04x 2009E and 1.80x 2010E P/E, $26,206 per 2008 daily flowing barrel and $11.67/2P bbl on a net basis (excluding natural gas). This is compared to global E&P peers, which are trading at 4.2x 2009E and 3,76x 2010E P/CF, 3,51x 2009E and 3,12x 2010E EV/EBIDA, 7,80x 2009E and 5,49x 2010E P/E, $60,336 per daily flowing barrel and $13.41/2P boe.

Investment summary

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Renaissance Capital Addax Petroleum November 2008

Near-term catalysts

Figure 4: Addax Petroleum - quarterly diluted operating EPS, $/share

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Figure 5: Addax Petroleum - quarterly diluted operating CFPS, $/share

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Near-term production profile attractive and reduced 2008E production guidance attainable Figure 6: Addax Petroleum - production profile, kbpd

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Addax revised downward its 2008 production outlook on 6 Aug 2008 to 136-140 kbpd from 140-145 kbpd previously, which equates to production growth of 8% in 2008. This production estimate was revised downward due to 1) operational issues in Gabon, including delays from rectifying a well completion failure and 2) higher-than-expected rates of decline in some production wells, which inhibited production growth at the current drilling rates. In 2007, total production was 126 kbpd, up 40% from production levels of 90 kbpd in 2006.

Near-term outlook

Figure 3: Addax Petroleum near-term catalysts Activity Expected timing Addax will drill 25 exploration wells with unrisked prospective working interest oil resources of approximately 700mn bbl 2009 Commence drilling in the Joint Development Zone (JDZ4 Kina, JDZ3 Lemba, JDZ2 Tome) 2H09 Production growth of 16% in 2009E and 19% in 2010E 2009/2010 Ramp-up of production and continued exploration drilling at Taq Taq 2009 Agreement for export license at Taq Taq 2009 Sangaw North exploration in Kurdistan 2H09 Further Nigerian gas monetisation developments 2009 Potential acquisitions Ongoing

Source: Company data

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Nigeria: Core assets with significant development and exploration upside Production in Nigeria was 103.6 kbpd in 3Q08, accounting for 78.9% of Addax Petroleum’s total production. Over 90% of Nigerian production is offshore, with total Nigerian production 100% oil-weighted. Addax operates all of its producing assets in Nigeria.

Addax Petroleum’s assets in Nigeria include onshore producing property OML 124, as well as offshore producing properties OML 123 and OML 126/OML 137 (contiguous). Other offshore properties include development assets at Okwok, and exploration prospects at OPL 291 and in shallow water at OPL 227. Please see the table and map below for illustrations of the characteristics and locations of the company’s assets in Nigeria.

Figure 8: Addax Petroleum – licence areas in Nigeria


Addax was also recently awarded by Express Petroleum & Gas and Petroleum Prospects International a 40% interest in OPL 227 with work commitments including

Nigeria

Figure 7: Addax Petroleum principal properties – Nigeria

Licence Area ('000 net acres) Interest Operator 2Q08 average

production 2P Reserves1 3P Reserves1 Major fields and status

OML 123 90.7 100.0% Addax 57.3 161.4 220.6 Adanga, Ebughu, Oron West, North Oron OML 124 74.1 100.0% Addax 7 23.4 38.9 Izombe, Ossu OML 126 178.3 100.0% Addax 41.2 52.4 59.9 Okwori, Nda – continued development OML 137 209.5 100.0% Addax - 17.1 19.8 Exploration - 870 km2 3D seismic shot needed Okwok 9 40.0% Addax - 8.4 9.5 Appraisal drilling - as early as 2009 OPL 227 84.1 40.0% Express - - - Exploration - seismic to be shot OPL 291 230.6 72.5% Addax - - - Exploration - seismic to be shot in 2008 As at 31 Dec 2007


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80% of the costs of a 500 km2 3D seismic survey as well as 80% of all capital and operating costs with cost recovery.

The majority of Addax Petroleum’s interests in Nigeria are governed by Nigerian production sharing contracts (PSC) (at OML 123, OML 124, OML 126, OML 137 and OPL 291) with the Nigerian National Petroleum Corporation (NNPC). Nigerian PSCs are structured so that the contractor bears the development and exploration risk and funds all capital expenditures. The contractor is then entitled to recover the cost of capital expenditures and operating costs and to receive a designated share of oil production after the payment of royalties and taxes. Oil production is allocated into the following four categories: 1) royalty oil, 2) cost oil, 3) tax oil and 4) profit oil. Royalty oil and tax oil are allocated to the NNPC while Addax receives cost oil and a portion of profit oil that is allocated between Addax and the NNPC.

Figure 9: Nigerian production sharing contract

Oil Revenue

Royalty Oil

Non-Capital Cost Oil

Tax Oil

Capital Cost Oil

Profit Oil

Addax Petroleum

NNPC


The PSCs’ fiscal terms reduce the percentage of revenues paid as tax oil during periods of lower oil prices and increase the percentage paid during periods of higher oil prices.

The Okwok property is governed by fiscal terms for Nigerian marginal fields. Marginal fields in Nigeria are subject to royalty and tax oil payable to government agencies with royalty oil calculated on a field-by-field basis, varying with production rate and water depth. Tax oil is specified by the Petroleum Profits Tax act and the applicable rate is anticipated to be 55%. In Addax’s case, as is common in the marginal fields, the company’s interest in Okwok is also subject to the terms of the Oriental Joint Venture.

Other royalties paid in Nigeria include the NDDC levy of 3% of operating costs and capital expenditures and education tax, which is calculated as 2% of assessable profit.

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In 3Q08 the average total government take of Addax’s Nigerian oil production as a percentage of revenues was 64.2%.

Nigerian gas monetisation: Huge value potential but timing uncertain Addax Petroleum recently formed a consortium with Chrome Oil Services Limited, a Nigerian conglomerate whose interests include oil and gas exploration and production, and Korea Gas Corporation, South Korea’s national gas company and the world’s single largest LNG buyer, to develop an integrated gas utilisation project within the framework of Nigeria’s Gas Master Plan.

On 1 Aug 2008, the federal government of Nigeria granted approval for the integrated gas utilisation project. The project may include the potential monetisation of natural gas on OML137 where Addax has best-estimate contingent natural gas resources of 925.7 bcf (as estimated by Netherland, Sewell & Associates Inc. [NSAI] as at 31 Dec 2007). The consortium expects the project to secure the gas reserves necessary to commercialise a new LNG production facility with capacity of up to 10mnt per year to be situated on Brass Island in Bayelsa State. The facility would provide domestic power generation capacity of up to 1,000 MW, and feedstock for the development of petrochemical facilities. The main risk to the timing and development of this initiative is that the consortium must still negotiate with the Nigerian Ministry of State for Energy (gas), the Department of Petroleum Resources and the Nigerian National Petroleum Corporation to establish fiscal and commercial terms for the project’s upstream and downstream activities. Addax has targeted a final investment decision for the end of 2009.

Although natural gas sales have occurred in Nigeria since 1976, the major customer is Power Holding Company of Nigeria, the government electricity provider that pays producers approximately $0.10/mcf. While some industrial customers pay prices that are closer to commercial rates in the $3.00 range, this comprises a very small part of current demand and an even smaller portion of potential supply.

The Nigerian Gas Master Plan was announced in May 2008 with the aim to fully exploit the country’s natural gas resources, estimated at 182 tcf, in pursuit of the government’s 10% GDP growth aspirations. The plan includes an integrated infrastructure strategy to support domestic, regional and export LNG markets.

Monetisation of natural gas resources offers a significant opportunity for value creation for Addax Petroleum. NSAI estimates best-estimate contingent as resources for Addax Petroleum in Nigeria of 2,414.8 bcf and associated liquids of 77.2 mmbbl. This estimate includes natural gas from producing licence areas in the shallow water and onshore licences.

Nigeria: “Flares down by 2008” Addax Petroleum has initiated programmes to comply with the flares down initiative in Nigeria. This has been accomplished through the use of incremental gas compression and gas re-injection on OML 124 and re-injection for enhanced oil recovery on OML 126 to ensure its flares are down by the end of 2008. On OML

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123, the company plans to export natural gas for power generation and/or re-injection with a project design that is still being finalised.

We note that although Nigeria currently flares approximately 2 bcfpd of natural gas, the government has never enforced the no-flaring legislation that was originally introduced in the 1980s. Historically, operators have paid a flaring penalty of $0.07/mcf, although the federal government has stated that it will increase this penalty to $3.50/mcf beginning in Jan 2009. However, we understand that the required legislation to put this penalty into force is unlikely to be passed before this deadline.

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Production in Gabon was 27.7 kbpd in 2Q08, which accounted for 21.1% of Addax Petroleum’s total production. 76.5% of the company’s production in Gabon is onshore. All of the company’s offshore production in the country is non-operated and production is 100% oil-weighted.

Addax Petroleum’s assets in Gabon include onshore producing assets at the Tsiengui field (Maghena licence area), the Obangue field (Panthere NZE licence area), and the Remboue field (Remboue licence area). Onshore development assets in Gabon include the Kouala, Tsiengui west and Damler fields (Awoun licence area). The company expects first production from the Kouala field in 2009. Other onshore assets in Gabon include the Autour field (Panthere NZE licence area) which has probable reserves and the Epaemeno field (Epaemeno licence area) that is located immediately north of the Maghana and Awoun licence areas.

Offshore producing assets in Gabon include the Etame field (Etame Marin licence area) and the Avouma and Sout Tchibala fields (Etame Marin licence area). The company’s only offshore development asset is the Ebouri field (Etame Marin licence area). Exploration assets offshore Gabon are the Kiarsseny licence area, the shallow water Iris Marin licence area, and Ibekelia (Technical Evaluation Agreement).

The table and map below illustrate the characteristics and location of Addax Petroleum’s assets in Gabon.

Gabon

Figure 10: Addax Petroleum’s principal properties – Gabon


production 2P Reserves1 3P Reserves1 Major fields and status

Maghena 150.2 92.5% Addax 17.6 38.8 38.8 Tsiengui - continued development Panthere NZE 27.5 92.5% Addax 1.7 36.5 41.1 Obangue - continued development Etame Marin 238.2 31.4% VAALCO 7 13.4 22.5 Etame, Avouma, Ebouri Kiarsseny 571.6 42.5% Tullow Oil - - - Exploration Gryphon Marin 1204.6 50.0% Addax - - - Exploration wells to be drilled in 2009 Other 423.1 various Addax, Shell,

Sterling 1.1 20.8 25.9 Koula, Damier, Remboue, Iris Marin, Epaemeno, Ibekelia


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Figure 11: Addax Petroleum - Gabon licence areas


Addax has recently experienced what we expect to be temporarily higher-than-expected rates of production decline in Gabon. However, we expect new production

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from the Awoun licence and increased capacity with the completion of pipeline facilities to Shell’s Rabi facility to offset this to a degree.

We note that Addax recently acquired an additional interest in the Iris Marin licence area offshore Gabon through the acquisition of a subsidiary of Sterling Energy Plc. As a result of this acquisition, the company will hold up to a 51.33% working interest in the licence and, pending government approval, will become operator of the asset.

Addax Petroleum’s interests in Gabon are governed by PSCs with the exception of the Ibekelia technical evaluation agreement. PSC contracts in Gabon are structured so that the contractor funds all exploration and development expenditures. The contractor is entitled to cost recovery of capital expenditures and operating costs and to receive a designated share of profit oil after the payment of royalties. Oil production is allocated into the following three categories: 1) royalty oil, 2) cost oil, and 3) profit oil. Royalty oil is allocated to the government of Gabon, while Addax receives cost oil and a portion of profit oil that is allocated between Addax and the government. In 2Q08 the average total government take of Addax’s Gabon oil production was 41.3%.

The diagram below shows the allocation of oil production under Gabon PSCs.

Figure 12: Gabon production sharing contract


Oil Revenue

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Profit Oil l

Addax Petroleum

State

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Addax operates the Taq Taq property through a farm-in agreement with Genel Enerji A.S., holding a 45% interest in the property, or a 36% interest after taking into account the Kurdistan Regional Government’s (KRG) 25% back-in rights. Future production potential is up to approximately 140 kbpd gross, depending on export capability.

Addax also recently acquired a 33.3% interest in the Sangaw North PSC that is operated by Sterling Energy and is located 80 km southeast of the Taq Taq field. The contract is subject to assignment under the Korean National Oil Company, which will reduce Addax’s stake to 26.67%. Additionally, the KRG has the option to acquire a 25% interest that would further reduce Addax’s interest to 20%. The Sangaw North Block is estimated to contain best-estimate gross unrisked prospective resources of 212 mmbbl by independent consultants RISC.

The table and map below illustrate the characteristics and location of the company’s assets in Kurdistan.

Kurdistan

Figure 14: Addax Petroleum - Kurdistan licence areas


Figure 13: Addax Petroleum’s principal properties – Kurdistan region of Iraq Licence Area

('000 net acres) Interest Operator 2Q08 average production (mmbpd) 2P Reserves1 3P Reserves1 Major fields and status

Taq Taq 105.8 45.0% Addax - 74.6 103.4 Continued appraisal drilling and development Sangaw North 32.4 26.7% Sterling Energy - - - Core exploration area


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Addax has completed the construction of an early production system with a capacity of 30 kbpd at Taq Taq. It has expected sales to the local market of up to 10 kbpd and refinery sales of 10 kbpd in 2009E. The early production system has the potential to increase capacity to up to 60 kbpd by late 2009.

There are two potential long-term transportation solutions at Taq Taq: the Taq Taq-to-Silopi pipeline (225 km) and the Taq Taq-to-Kirkuk pipeline (70 km). The Kirkuk pipeline is preferable given the shorter pipeline required and the company has awarded front-end engineering and design (FEED) and ESIA contracts for this option. The company expects FEED to take five to seven months with the construction-to-commissioning stages expected to be completed over an eight to 12-month time period. In a best-case scenario this could result in a crude export pipeline being in place as early as 2010. Addax must also receive an export licence from the KRG. With a pipeline in place and an export licence, production from Taq Taq could reach 140 kbpd gross in 2011E. The map below illustrates the two pipeline options.

The company has also been pursuing acid well stimulation in Kurdistan with positive results that indicate significantly increased flow potential. Recent results include: 1) the Shiranish formation in the TT-04 well where the flow rate almost tripled to 11,080 bpd from 3,940 bpd and 2) the TT-06 well where two intervals were acidised, resulting in an almost eight-fold increase in production to 18,850 bpd from 2,200 bpd in the Kometan formation and increased production in the Qamchuqa formation to 3,080 bpd from 1,500 bpd.

Figure 15: Kurdistan pipeline options


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Addax Petroleum’s interests in Kurdistan are governed by the Amended Revised Taq Taq Production Sharing Agreement (PSA) and the model PSA published by the KRG. The Taq Taq PSA is structured so that contractors fund all exploration and development expenditures. The contractor is entitled to cost recovery of capital expenditures and operating costs and to receive a designated share of oil production after the payment of royalties. Oil production is allocated into the following three categories: 1) royalty oil, 2) cost oil, and 3) profit oil. The Taq Taq PSA was amended in Feb 2008 to conform to the model PSA published by the KRG and gave the KRG the right to assign back-in rights of 20% to a government-nominated entity.

We also note that discussions between the KRG and the federal government of Iraq are ongoing in regard to the development of federal Iraqi hydrocarbon laws. A joint KRG-Iraqi committee was created in June 2008 to develop federal oil and gas laws.

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Nigeria-Sao Tome Principe JDZ: Significant near-term exploration drilling Addax owns significant exploration interests in the JDZ with interests in Block 1, Block 2, Block 3 and Block 4. There is no current production in the JDZ, which is located 180 km south of Nigeria in the Gulf of Guinea.

The table and map below illustrate the characteristics and location of the company’s interests in the JDZ.

Figure 17: JDZ licence area


Addax is embarking on a consecutive exploration programme of up to 10 wells in the region. The company originally contracted the Aban Abraham drilling rig to commence drilling on JDZ Block 4 in 4Q08, however, the rig has been delayed and is now expected to be delivered in Sep-Oct 2009. The company continues to seek a rig of opportunity to drill the Kina prospect on JDZ Block 4.

Based on independent estimates from NSAI, the total best-estimate unrisked prospective oil resources for identified JDZ prospects is 2,323.1 mmbbl gross (990.5 mmbbl risked) with Addax’s potential unrisked working interest of 726.6 mmboe (313 mmbbl risked).

All of Addax Petroleum’s interests in the JDZ are governed by PSCs. PSCs in the JDZ are structured so that the contractor funds all exploration and development expenditures. The contractor is entitled to cost recovery of capital expenditures and operating costs and to receive a designated share of profit oil after the payment of royalties and taxes. Oil production is allocated into the following four categories: 1) royalty oil, 2) cost oil, 3) tax oil, and 4) profit oil. Royalty oil is allocated to the Joint Development Authority (JDA) and varies on a sliding scale based on production

Other assets

Figure 16: Addax Petroleum principal properties - Joint Development Zone

License Area ('000 net acres) Interest Operator 2Q08 average

production 2P Reserves1 3P Reserves1 Major fields / Status

Block 4 96.4 45.5% Addax - - - Core exploration area Block 3 24.7 15.0% Anadarko - - - Core exploration area Block 2 24.5 14.3% Sinopec - - - Core exploration area Block 1 69.6 40.0% Chevron - - - Core exploration area


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rates. Capital and operating costs can be fully recovered up to a maximum of 80% of the sum of total production less royalty oil. Tax oil is calculated as 50% of taxable profit after royalties, cost oil and an investment tax allowance. Profit oil is split between the contractor and the JDA based on a sliding scale.

Cameroon: Limited success thus far Addax Petroleum owns interests in two exploration blocks in Cameroon: Ngosso and Iroko. The company is currently not producing in Cameroon.

The table and map below illustrate the characteristics and location of the company’s assets in Cameroon.

Recent results from the company’s first two wells on Ngosso had limited success, with Addax plugging and abandoning the wells and now having completed its current work commitments. Data from the Ikoro exploration well on the Ikoro licence area are being evaluated to determine future drilling plans for the licence area.

Figure 18: Addax Petroleum principal properties - Cameroon


production (mbbl/d 2P Reserves 3P Reserves Major fields / Status

Ngosso 70.3 60.0% Addax - - - Exploration Iroko 3.9 100.0% Addax - - - Exploration


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Potential acquisitions: Significant opportunities given current financial market conditions In West Africa, Addax continues to pursue potential acquisitions in the company’s core areas of Nigeria, Gabon and Cameroon as well as potential expansion into other areas in West Africa such as Angola, Chad, the Republic of Congo, Democratic Republic of Congo and Equatorial Guinea. We also would not be surprised to see the company enter Ghana.

Key factors that differentiate acquisition targets are those that are in under-developed basins and deepwater prospects where advancements in seismic technology and drilling can add significant value. This is not surprising as this strategy is consistent with how the company was built in Nigeria, where it increased production from less than 10 kbpd at OML 123, its first licence in Nigeria, in 1998 to over 130 kbpd today. This is also consistent with the company’s acquisition of Pan-Ocean Energy in Gabon in 2006.

Major opportunities for new ventures are likely to come up as a result of: 1) new acreage being tendered in further bid rounds; 2) reduction of interests, particularly in Nigeria, of the super-majors; 3) indigenous oil companies seeking financial and technical partners, again particularly in Nigeria; and 4) farm-in opportunities with exploration companies that have limited access to capital given current financial market conditions.

Outside of West Africa, Addax continues to focus on potential acquisition opportunities in the Middle East and North Africa. Building on the company’s current presence in Kurdistan, Addax continues to pursue further licences in Iraq and other countries in the Middle East. In North Africa, the company is interested in expanding into Algeria, Libya and Egypt. Addax has participated in various bid rounds in North Africa and continues to evaluate opportunities there.

In our view, another area of potential interest for the company in Sub-Sahara Africa, although a less likely one, could be in Uganda, specifically the stakes in the Lake Albert discoveries held by Heritage Oil and Tullow Oil.

Based on the company’s current net debt-to-capital position, we believe that Addax could make an acquisition of up to $0.80-1.25bn and stay within a net debt-to-capital ratio of 40-45%. Addax currently has a credit facility in place of up to $1.8bn, with $900mn of the facility drawn down and $201mn of cash as at 2Q08.

Unlikely acquisition target We would not rule out Addax Petroleum as an acquisition target. However, given the company’s enterprise value of $3,565mn and its current asset base in Nigeria and Gabon, an area where the supermajors are experiencing significant operational difficulties, we think Addax is less likely to be a candidate for acquisition than other companies in our Africa oil and gas universe. If Addax were to be acquired, we expect that this would more likely be by a super-independent than one of the super-majors.

We note that currently 35.5% of the company’s outstanding shares are held by Addax & Oryx (AOG) and that 4.2% of its outstanding shares are held by its management and directors.

Acquisitions

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Please see the table below for Addax Petroleum’s capital structure.

Figure 19: Addax Petroleum capital structure as at 30 Sep 2008 Share structure Amount Basic shares 156,537,751 Convertible bonds 5,929,234 Stock options 964,146 Fully diluted shares outstanding 163,431,131 Sources of capital Amount, $mn Long-term debt 1,025 Convertible bonds 253 Cash and cash equivalents 88 Shareholders' equity 2,482


Strong balance sheet Capital expenditures for 2008 and 2009 are expected to be approximately $1,600mn based on company guidance. We forecast exit 2009 net debt-to-capital of 26% for Addax in and debt-to-cash flow of 0.73x, based on our $70/bbl Brent estimate. The company could potentially make significant acquisitions in the near term of up to $1.25bn, which would increase net debt-to-capital to 45%.

Figure 20: Addax Petroleum net debt-to-cash flow from operations

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Figure 21: Addax Petroleum plowback ratio

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Operating costs and royalties In 2Q08 Addax Petroleum’s total company operating costs were $9.55/bbl and royalties were $19.77/bbl. Please see the chart below that illustrates historical and forecast royalties, operating costs, DDA, and netbacks.

Capital structure

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Figure 22: Addax Petroleum quarterly netbacks, $/bbl

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As of the last reserve report of 31 Dec 2007, oil reserves based on forecast prices and costs consisted of gross proved reserves (1P) of 233.3 mmbbl (176.7 mmbbl net), gross proved plus probable reserves (2P) of 446.7 mmbbl (305.5 mmbbl net), and gross proved plus probable plus probable reserves (3P) of 580.3 mmbbl (389.9 mmbbl net). Best-estimate net contingent Nigerian natural gas resources are estimated at 2,414.8 bcf. Please see the charts below that illustrate the breakdown of Addax Petroleum’s reserves and the table that shows finding and development (F&D) costs and reserve replacement ratios for 2006 and 2007.

Figure 23: Addax Petroleum YE07 2P net reserves, mmbbl

Nigeria offshore, 206.0

Gabon onshore, 51.2

Gabon offshore, 7.0 Nigeria onshore,

19.6

Kurdistan Region of Iraq,

21.8


Figure 24: Addax Petroleum F&D / reserve replacement (net, 2P) 2006 2007

Organic F&D (including revisions), $/bbl 13.70 15.15 Organic F&D (excluding revisions), $/bbl 19.05 21.72 All-in F&D (FD&A), $/bbl 20.68 16.18 Organic reserve replacement (including revisions) 209% 200% Organic reserve replacement (excluding revisions) 150% 139% All-in reserve replacement (including revisions) 439% 200%


Reserves and resources

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Our total company NAV estimate for Addax Petroleum is BPN2,820/share. Total company NAV includes value for producing assets in Nigeria and Gabon, the Taq Taq development asset in Kurdistan and risked exploration potential for Sangaw North in Kurdistan, Nigeria and the JDZ. We have not included any value for Nigerian natural gas monetisation at this time. Addax is currently trading at 29% of our total company NAV estimate.

On multiples, our target price equates to 4.2x 2009E and 2.8x 2010E P/CF, 3.0x and 1.9x 2009E and 2010E EV/EBITDA 8.9x 2009E and 5.3x 2010E P/E, $55,900 per 2009 daily flowing barrel and $24.88/2P bbl on a net basis (excluding natural gas).

The table below illustrates the sensitivity of our NAV to oil prices and discount rates.

Valuation

Figure 26: Addax Petroleum - net asset value sensitivity LT Brent oil price, $/bbl $59.56 40 45 50 55 60 65 70 75 80 85 90 95 100

15% 1,939 2,037 2,135 2,234 2,332 2,430 2,528 2,626 2,724 2,823 2,921 3,019 3,117 14% 2,008 2,110 2,213 2,316 2,419 2,522 2,625 2,728 2,831 2,934 3,036 3,139 3,242 13% 2,080 2,188 2,296 2,404 2,512 2,620 2,728 2,836 2,943 3,051 3,159 3,267 3,375 12% 2,157 2,270 2,383 2,497 2,610 2,723 2,837 2,950 3,063 3,176 3,290 3,403 3,516 11% 2,238 2,357 2,476 2,595 2,714 2,833 2,952 3,071 3,190 3,309 3,428 3,547 3,666 Di

scou

nt ra

te

10% 2,324 2,450 2,575 2,700 2,825 2,950 3,075 3,200 3,326 3,451 3,576 3,701 3,826 9% 2,416 2,548 2,679 2,811 2,943 3,075 3,206 3,338 3,470 3,601 3,733 3,865 3,996

8% 2,514 2,652 2,791 2,930 3,068 3,207 3,346 3,484 3,623 3,762 3,900 4,039 4,178 Source: Renaissance Capital estimates

Figure 25: Addax Petroleum - NAV summary NAV,

$mn NAV,

GBPmn NAV,

CADmn Per share,

$ Per share,

CAD Per share,

BPN % of

value share Production & development OML 123 / 124 (offshore, onshore Nigeria) 3925 2266 4617 24.03 28.27 1387 42% Gabon 1925 1111 2264 11.78 13.86 680 20% OML 126 / 137 (offshore Nigeria) 1611 931 1896 9.86 11.60 570 17% Taq Taq (Kurdistan) 745 430 877 4.56 5.37 263 8% Production and development NAV 8206 4739 9654 50.23 59.10 2901 87% Best estimate risked prospective resources Onshore and shallow water Gulf of Guinea 525 303 618 3.21 3.78 186 6% JDZ & OPL 291 476 275 560 2.91 3.43 168 5% Gabon 128 74 150 0.78 0.92 45 1% Sangaw North (Kurdistan) 113 65 133 0.69 0.81 40 1% Best estimate risked prospective resources NAV 1242 717 1461 7.60 8.94 439 13% Total 525 303 618 3.21 3.78 186 100% Liabilities Long-term debt 1278 738 1504 7.82 9.20 452 Less cash -193 -112 -228 -1.18 -1.39 -68 Net debt 1471 850 1731 9.01 10.60 520 Current net asset value 7976 4606 9383 49.00 57.00 2820


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Major risks for Addax Petroleum include continuing civil unrest, particularly in Nigeria and Iraq, and significant political risk throughout the company’s operations. Other risks include governmental or business corruption and uncertainty regarding the interpretation and application of foreign laws and regulations. Other key risks for the company are a transportation solution at Taq Taq as well as natural gas flaring regulations in Nigeria. Additionally, terms for commercialisation of natural gas in Nigeria will have a material impact on the value of the company’s natural gas resources in the country.

Risks inherent in the global oil and gas business include volatility of oil and natural gas pricing, currency risk, cost inflation for materials and services, geological risk, operating hazards, access to supplies and equipment, access to drilling rigs and experienced trades and unforeseen weather conditions that can impact drilling programmes. Other risks include potential changes to existing royalty regimes, regulatory environments, political regimes and environmental considerations.

Another risk specific to US shareholders is that the company may be subject to US economic sanctions if Addax chooses to enter Iran.

Key risks

44


Addax Petroleum is a Canadian corporation with offices in Geneva, Switzerland. The principal business of the company is oil and gas E&P with upstream oil and gas assets in Nigeria, Gabon, the JDZ, Kurdistan and Cameroon.

The company was originally founded in 1994 by the Addax & Oryx Group, a conglomerate with interests throughout Africa, which is comprised of energy trading, upstream oil and gas, downstream energy assets and gold mining.

In May 1998, Addax Petroleum N.V. acquired the company’s first Nigerian licences, entering into PSCs with the Nigerian government for OPL 98, OPL 118, OPL 90 and OPL 225. These blocks are now OML 123, OML 124, OML 126 and OML 137, respectively. In 1998 the company was producing 8.8 kbpd; that has now increased to 132.9 kbpd in 2Q08.

The company then expanded through the purchase of a 60% interest in the Ngosso licence area offshore Cameroon in Dec 2002, the acquisition of a 42.5% interest in the Kiarsseny licence area offshore Gabon in Jan 2004 and the entry into Kurdistan in July 2005 through a farm-in arrangement to acquire a 30% interest in the Taq Taq licence area from Genel Enerji.

In Sep 2005, Addax Petroleum was incorporated with an initial public offering of 23,100,000 common shares for gross proceeds of CAD450,450,000. The corporation acquired all of the issued and outstanding shares of Addax Petroleum N.V. concurrent with the offering for 117,000,000 common shares and CAD55,575,000. The company is currently listed on the Toronto Stock Exchange and the London Stock Exchange.

In 2006, Addax Petroleum entered the JDZ, obtaining interests in Blocks 2, 3 and 4 through a number of transactions. The company also acquired a 40% interest in the Okwok field in licence area OML67 in Nigeria and entered into a farm-out agreement and PSC regarding OPL291, which is deep offshore Nigeria. The company also acquired a 40% stake in JDZ Block 1 in 2007 from Esso Nigeria-Sao Tome.

In Sep 2006, Addax Petroleum acquired further assets in Gabon, through the acquisition of Pan-Ocean Energy for consideration of CAD1.60bn in cash and the assumption of CAD6.8mn of net debt. The company raised gross proceeds of CAD402mn in equity to partially fund the acquisition. Subsequent to this acquisition, the company acquired a 51% interest in the Epaemeno licence area onshore Gabon from BowLeven Plc in Apr 2007.

Company background

45


Board of directors and senior management profiles Peter Dey, director, chairman of the board of directors and chairman of the Corporate Governance, Nominating and Compensation Committee

Dey is chairman of Addax Petroleum Corporation. He is also chairman of Paradigm Capital Inc. and a former partner of Osler, Hoskin & Harcourt LLP, a law firm specialising in corporate and securities law. From 1994 to 2001, he was chairman of Morgan Stanley Canada Limited where he was responsible for the overall strategic direction of Morgan Stanley in Canada. From 1983 to 1985, Dey was chairman of the Ontario Securities Commission. He is chairman of the Private Sector Advisory Group of the Global Corporate Governance Forum, which was established by the World Bank and the OECD. Dey is vice chairman of the Boardroom Advisory Panel established by the OECD. He has a BSc from Queen’s University, a bachelor of law degree from Dalhousie University and a master of law degree rom Harvard University. He is also a director of Workbrain Corporation.

Jean Claude Gandur, president, chief executive officer and director

Gandur is president and chief executive officer of Addax Petroleum Corporation. Gandur worked with major commodity traders including Philipp Brothers from 1976 to 1983, where he was manager of the African/Latin American division; Sigmoil Resources N.V. from 1984 to 1986, where he was the managing director; and Kaines SA from 1986 to 1988, where he was the managing director. For 10 years Gandur was honorary consul for the Republic of Congo in Geneva. He was also

Figure 27: Addax event chart – company history

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3 Apr 2008: Addax signs a Production Sharing Contract (PSC) w ith the Republic of Cameroon, relating to the Iroko exploration license area and thus acquires a 100% interest in license area

28 June 2006: Addax completes acquisition of a 40% participating interest in the Okw ak f ield in license area OML67 in Nigeria

20 July 2006: Addax agrees to acquire tw o subsidiaries of Pan-ocean Energy Corporation Limited for CAD1.6bn

1 May 2008: Addax announces successful appraisal of the Ofrima North discovery in OML 137, offshore Nigeria

02 Sep 2008: Addax acquires 50% interest in Gryphon Marin license area subject to f inal approval from the Government of Gabon

10 Apr 2007: Addax agrees to acquire a 50% interest in the Epaemeno license area of Bow Leven plc, in Gabon

25 Sep 2007: Addax agrees to acquire 40% interest in Block 1 of the Deepw ater Joint Development Zone from Esso Exploration & Production

7 Sep 2006: Addax completes the previously announced acquisition of subsidiaries of Pan-Ocean Energy Corporation Limited for CAD1.6bn

16 Feb 2006: Completes IPO of 21mn shares at a price of CAD19.5/share and shares start trading on Toronto Stock Exchange under the ticker AXC

Source: Company data, Renaissance Capital

46


awarded a diplomatic passport by Senegal. In addition, he received the decorations of Grand Officer of the Lion Order of Senegal and Commander of the National Order of Benin. Gandur is one of the founders of Addax & Oryx Group, of which he is chairman of the supervisory board. He is also the non-executive chairman of AXMIN Inc. Gandur is a Swiss citizen and studied law at the University of Lausanne, Switzerland.

Brian Anderson, director and chairman of the technical and reserves committee

Anderson is a director of Addax Petroleum Corporation. Before retiring in 2000, Anderson had a 34-year professional career, largely in the Royal Dutch/Shell Group of Companies. Anderson was appointed managing director of the Shell Petroleum Development Company and chairman of Shell Nigeria in Jan 1994. His last assignment before retirement was three years based in Beijing as chairman of the Shell Companies in North-East Asia, principally involved in China and Hong Kong, but he also had overall responsibility for Shell’s interests in Korea and Taiwan. Anderson is currently chairman and managing director of Anderson Energy (Hong Kong) Ltd, a consulting company which he set up in 2000 to specialise in assisting companies mostly in Africa and China in the energy sector. Anderson was born in Nigeria, is a citizen of the UK and studied Metaliferous Mining Engineering at Cambourne in the UK, followed by an MSc in Petroleum Reservoir Engineering at London University.

James Davie, director

Davie is a director of Addax Petroleum Corporation. Davie has over 29 years of investment banking experience with RBC Dominion Securities Inc. He retired in 2002. Davie held a number of senior positions at RBC Dominion Securities Inc. including managing director of Investment Banking and Head of Equity Capital Markets from 1987 to 1999. Davie has a bachelor of commerce degree from the University of Toronto and an MBA from Queen’s University. Davie is also a director of Profico Energy Management Ltd., Range Royalty Management Ltd., Navigo Energy Inc., Taylor Gas Management Ltd. and the Brompton Group of Funds.

Stephen Paul de Heinrich, director

Stephen Paul de Heinrich is a director of Addax Petroleum Corporation. He has more than 30 years’ experience in trading and investment in Africa. He has been instrumental in organising counter trading export pre-financing and syndicated financial transactions in several African countries. De Heinrich is now an independent consultant as well as an associate in Beldi & Cie S.A., a Geneva-based corporate finance house. He was a non-executive director of AOG from 1988 to 1991 and since then has been the vice chairman of its supervisory board. He has been chairman and a director of SAMAX Resources Limited and Carpathian Gold Limited, among other companies. De Heinrich is a citizen of both Canada and Hungary and has a degree in economics from McMaster University, Hamilton, Canada.

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Gerry Macey, director

Macey is a director of Addax Petroleum Corporation. Macey has over 31 years of oil and gas industry experience. In particular, from 2002 to Mar 2004, he served as executive vice president and president, International New Ventures Exploration Division, of EnCana Corporation, and from 1999 to 2002, he served as executive vice president, Exploration, of PanCanadian Petroleum Corporation. Macey holds a BSc in geotechnical science from Loyola College in Montreal and an MSc in geology from Ottawa Carleton University. Macey is also a director of Verenex Energy Inc. and PanOrient Energy Corp.

Afolabi Oladele, director

Oladele is a director of Addax Petroleum Corporation. Oladele has over 25 years experience in the oil and gas industry. He worked from 1977 to 1988 for NNPC in the marketing department and from 1988 to 1999 for National Petroleum Investment Management Services (NAPIMS) latterly as group executive director, Refining and Petrochemical. Since 1999, he has been vice president of oil and gas for Capital Alliance Nigeria. Oladele is also Chairman, Subsurface Assets Management Co, chairman, Formwork Ltd, director, Freezone Fabrication International Oil & Gas Facilities Fabrication Co, director, Dorman Long Engineering Co, director, Sudelletra Nigeria Ltd, and director, AOG. Oladele is a citizen of Nigeria and studied chemical engineering at the University of Ife followed by petroleum economics at the French Petroleum Institute (IFP) in Paris and a post graduate diploma in energy modelling and large scale planning systems at the University of Southern California. Oladele also has a certificate in applied international management IFL from Sigtuna, Sweden.

Wesley Twiss, director and chairman of the audit committee

Twiss is a director of Addax Petroleum and Audit Committee Chair. Twiss is a corporate director with 35 years of energy industry experience, including 13 years as the senior financial officer of two major Canadian companies. He was executive vice president and chief financial officer of PanCanadian Energy Corporation from Oct 2000 until Apr 2002 and was executive vice president and chief financial officer of Petro-Canada from 1998 through 2000. In those roles, Twiss was responsible for directing all aspects of corporate financial affairs, as well as strategic management and corporate development. He is a director and audit committee chair of Canadian Oil Sands Trust, Keyera Facilities Income Fund and EPCOR. Twiss holds a bachelor of applied science in chemical engineering from the University of Toronto and an MBA from the University of Western Ontario. Twiss is a graduate of the Directors Education Programme, Corporate Governance College of the Institute of Corporate Directors and holds the ICD.D designation.

James Pearce, chief operating officer

Pearce is the chief operating officer of Addax Petroleum Corporation. Pearce is responsible for all of Addax Petroleum’s upstream activities including new ventures, exploration, new fields development and operations in West Africa and the Middle East. Pearce joined Addax Petroleum in May 2005 after 30 years with various Chevron subsidiaries. He has held many positions with Chevron including chief engineer in Sumatra Indonesia, manager, Petroleum Engineering in Lagos, Nigeria, general manager, Asset Development in Luanda, Angola, managing director in the

48


Republic of Congo, and most recently general manager, Deepwater in Lagos, Nigeria. In his most recent assignment with Chevron he was responsible for all deep-water operations in Nigeria including the multi-billion dollar development of the giant Agbami field.

Pearce holds a PhD in mechanical engineering from the California Institute of Technology and has received two US patents for innovative drilling platform concepts for arctic operations. Pearce is a member of the Society of Petroleum Engineers and was past chairman of the Lagos chapter. He has published in both international and American journals and has made numerous technical presentations at major conferences.

Michael Ebsary, chief financial officer

Ebsary is the chief financial officer of Addax Petroleum Corporation. Ebsary worked at the Bank of Nova Scotia from 1986 to 1987 and the Bank of Montreal from 1987 to 1989, prior to joining the international upstream oil business with Occidental in London in 1989. Following the acquisition of Occidental’s UK assets by Elf, Ebsary was appointed treasurer of Elf Petroleum UK in 1991. In 1994, Ebsary was transferred to Elf’s head office in Paris to the role of senior manager, project finance, during which time his responsibilities included major project financings in emerging markets, particularly in Nigeria, Chad and Cameroon. Ebsary joined the corporation in 1998 and became chief financial officer in 1999. Ebsary is a citizen of both Canada and the UK and studied mathematics and statistics, followed by an MBA in finance and accounting, at Queen’s University in Kingston, Canada.

David Codd, chief legal officer and corporate secretary

Codd is the chief legal officer and corporate secretary of Addax Petroleum Corporation. Codd has over 25 years’ experience in the international oil industry. After qualifying with a major UK law firm, Codd worked from 1980 to 1984 for Burmah Oil. In 1984 he joined Britoil Plc as Senior Legal Adviser. Following two years with ConocoPhillips in the UK, in 1990 he was appointed general counsel to Texaco’s integrated operations in the UK. From 1999 to 2001 Codd was managing director of Texaco in the UK, being Texaco’s senior corporate representative in the UK with business responsibility for Texaco’s regional upstream business development. Following Texaco’s merger with Chevron, Codd was chairman of a start-up company engaged in project development work in the Middle East until he joined the corporation in Feb 2005. Codd is a member of the council of the Energy Institute in the UK and a trustee of the Energy, Petroleum, Mineral and Natural Resources Education Trust. Codd is a citizen of the UK and is a solicitor with an MA (jurisprudence) and a BCL both from Oxford University.

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Figure 28: Addax Petroleum - income statement summary, $’000,000 2007 2008E 2009E 2010E 2011E 2012E 2013E 2014E 2015E Net revenues Nigeria 2,332 3,211 2,260 2,864 2,864 2,864 2,864 2,864 2,864 Gabon 495 853 721 1,300 1,300 1,300 1,300 1,300 1,300 Kurdistan 0 0 71 378 757 1,419 1,419 1,419 1,419 Total net revenues 2,827 4,064 3,052 4,542 4,921 5,583 5,583 5,583 5,583 Transportation and other Operating expenses 376 490 509 593 602 624 610 597 584 EBITDA 2,455 3,574 2,543 3,949 4,319 4,959 4,973 4,986 5,000 DD&A 581 577 638 806 816 834 834 834 834 EBIT 1,874 2,997 1,904 3,144 3,503 4,124 4,138 4,152 4,165 Interest expense, net 98 82 72 72 72 72 72 72 72 Pretax operating income 1,778 2,915 1,832 3,072 3,431 4,052 4,066 4,080 4,093 Share in associated company 0 0 0 0 0 0 0 0 0 Income taxes 1,251 1,967 1,173 1,982 2,215 2,618 2,627 2,636 2,644 Minority interest 0 0 0 0 0 0 0 0 0 Net income (per common) 482 947 660 1,090 1,216 1,434 1,439 1,444 1,449 Operating basic EPS ($) 3.40 6.11 4.40 7.44 8.31 9.82 9.86 9.89 9.92 Diluted operating EPS ($) 3.39 5.86 4.22 6.68 7.45 8.79 8.82 8.85 8.88


Figure 29: Addax Petroleum - cash flow statement summary, $’000,000 2007 2008E 2009E 2010E 2011E 2012E 2013E 2014E 2015E Net income 482 947 660 1,090 1,216 1,434 1,439 1,444 1,449 Change in working capital (450) -229 0 0 0 0 0 0 0 Cash provided by operating activities 869 1,684 1,418 2,112 1,216 1,434 1,439 1,444 1,449 Capital expenditures (1,225) -1,612 -1,608 -1,693 -1,693 -1,693 -1,693 -1,693 -1,693 Cash flow from investing (1,237) -1,612 -1,608 -1,693 -1,693 -1,693 -1,693 -1,693 -1,693 Issuance/Repayment of long-term debt 395 71 0 0 0 0 0 0 0 Issuance of common shares (29) -62 -63 -63 -63 -63 -63 -63 -63 Cash flow from financing 366 9 -63 -63 -63 -63 -63 -63 -63 Increase (Decrease) in cash & cash equivalents (2) 81 -253 357 598 886 892 898 904 Cash and cash equivalents 32 113 -140 217 815 1,700 2,592 3,490 4,394


Figure 30: Addax Petroleum - balance sheet summary, $000,000 2007 2008E 2009E 2010E 2011E 2012E 2013E 2014E 2015E Cash & cash equivalents 32 113 -140 217 815 1,700 2,592 3,490 4,394 Total current assets 512 867 644 1,075 1,673 2,558 3,450 4,348 5,252 Capital assets, net 3,247 4,189 5,188 6,110 7,032 7,954 8,876 9,798 10,720 Total assets 3,759 5,056 5,832 7,185 8,704 10,512 12,326 14,146 15,971 Total current liabilities 588 724 724 724 724 724 724 724 724 Long-term debt 1,195 1,278 1,278 1,278 1,278 1,278 1,278 1,278 1,278 Total liabilities 2,045 1,756 1,905 2,156 2,438 2,770 3,104 3,438 3,774 Preferred securities 0 0 0 0 0 0 0 0 0 Shareholders' equity 1,714 2,577 3,203 4,304 5,543 7,018 8,498 9,983 11,473 Total liabilities & equity 3,759 5,056 5,832 7,185 8,704 10,512 12,326 14,146 15,971 Net debt 1,195 1,165 1,418 1,061 463 -422 -1,314 -2,212 -3,116 Net debt/Total capital 41% 31% 31% 20% 8% -6% -18% -28% -37%


Summary operational and financial data


50

Afren plc Growth and value



17 November 2008

Oil and gas Africa

Report date: 17 November 2008 Rating BUY Target price (comm), BPN 91.00 Target price (pref), BPN n/a Current price (comm), BPN 39.50 Current price (pref), BPN n/a MktCap, $mn 273.28 EV, $mn 488.43 Reuters AFR.L Bloomberg AFR LN Common shares outstanding, mn 443.3 Change from 52 week high: -78.9% Date of 52 week high: 28 October 08 Change from 52 week low: 12.14% Date of 52 week low 15 May 2008 Web: www.afren.com Free float in $mn 250.86 Major shareholder with shareholding N/A Average daily traded volume in $mn 1.8 Share price performance over the last 1 month -21.11% 3 months -62.62% 12 months -56.39%

� We are initiating coverage of Afren with a BUY rating and BPN91/share target price. Our target price is equal to our DCF-derived NAV estimate of BPN91/share that includes value for producing assets CI-11 and Okoro Setu, appraisal and development assets CI-01 and Eremor, risked recoverable resources at Ebok and Ogedeh and the Lion gas plant. Our target price implies 2009 and 2010 P/CF multiples of 3.1x and 2.2x respectively. Our total NAV estimate for Afren is BPN128/share after including best estimate risked contingent plus prospective resources. Afren is currently trading with 130% upside potential to our target price.

� Attractive combination of: 1) low valuation 2) unique positioning to continue to exploit low risk development opportunities in Nigeria, 3) production ramp-up at Okoro Setu to 21 kbpd, 4) 2H08 expected to be the first interim results with positive operating earnings and cash flow, 5) near-term high impact exploration potential in Ghana, 6) access to a different sources of financing with the Sojitz strategic alliance and $269mn of cash as at 30 June 2008 and 7) longer-term potential for Nigerian gas monetisation.

� Asset consolidation opportunities. With various sources of financing, we believe Afren will have the opportunity to continue to consolidate African oil and gas assets. This is particularly true in the Niger Delta where we expect the majors to continue to divest non-core and sub-scale assets to indigenous companies, and throughout Africa where we believe there will be significant opportunities to acquire exploration and development assets at discounted prices in the near term.


Revenue EBITDA EPS, $ CFPS, $ EV/

EBITDA P/E P/CF Net debt / Capital

Production, mmbpd

Oil weight Plowback Dividend

yield 2007 0.00 -30.14 -0.17 -0.06 N/M N/A N/M 33% 0 100% 64 0.0% 2008E 197.48 114.62 0.11 0.10 4.26 5.69 22.0 38% 11 100% 529 0.0% 2009E 602.82 434.44 0.28 0.46 1.12 2.24 1.34 32% 23 100% 200 0.0% 2010E 743.53 553.72 0.45 0.65 0.88 1.38 0.95 18% 25 100% 200 0.0%

` Figure 1: Price performance – 52 weeks Figure 2: Sector stock performance – 3 months

01,0002,0003,0004,0005,0006,000

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Source: MSCI, Bloomberg Source: RTS, Bloomberg

November 2008 Afren plc Renaissance Capital

52

We are initiating coverage of Afren plc (AFR) with a BUY rating and BPN91/share target price. Our target price is equal to our core DCF-derived NAV estimate of BPN91/share, that includes value for producing assets CI-11 and Okoro Setu, and appraisal and development assets CI-01 and Eremor, as well as the Lion gas plant. Our total NAV estimate for Afren is BPN128/share after including potential risked recoverable resources and best estimate risked contingent plus prospective resources. Afren is currently trading with 130.4% upside to our target price.

Our target price of BPN91/share equates to 3.1x 2009 and 2.2x 2010 P/CF, 1.9x 2009 and 1.5x 2010 EV/EBITDA, 5.2x 2009 and 3.2x 2010 P/E, ;42,200 per daily flowing barrel (bpd) and $10.56/2P bbl (excluding natural gas).

Afren plc is a UK-based exploration and production company with assets located in West Africa and an enterprise value of $488.43mn. The company has producing assets at Okoro in the shallow water Niger Delta and in Cote d’Ivoire at Block CI-11 and the Lion gas plant. The company has significant additional development assets in Nigeria, Cote d’Ivoire and appraisal assets in Nigeria. Exploration assets include those in the Joint Development Zone in Sao Tome & Principe JDZ, Gabon, Congo, Angola and Ghana as well as Nigerian gas exploration and appraisal assets. Please see below for the map and table that illustrate the company’s current asset base.

Figure 3: Afren asset base

NIGERIA

CONGO

SAO TOME & PRINCIPE

GHAN

COTE D’IVOIRE

GABON

Production & Development

Exploration & Appraisal


Investment summary

53

Renaissance Capital Afren plc November 2008

Afren’s strategy is to continue to grow through the acquisition of exploration and development assets in Africa and partnerships with indigenous companies, governments and national oil companies. Afren has a clear track record of accessing resources since its inception in 2004 and we continue to believe that there is significant ongoing potential for value creation through the acquisition of appraisal and development assets, particularly in the Niger Delta. We expect the company to negotiate further partnerships with indigenous Nigerian companies that will continue to receive preferential access to assets as the majors divest non-core and subscale licences in the region, similar to the secondary development in the North Sea and Gulf of Mexico. We note that while many of the assets in the Niger Delta are at a stage of maturity or are sub-scale for the majors, there is also significant political pressure currently in Nigeria for further indigenisation of the oil and gas industry. Additionally, there are numerous indigenous companies operating assets where a technical partner can provide significant value.

We expect the 2009 production mix for the company to be derived from properties in the shallow water Niger Delta (87%) and offshore Cote d’Ivoire (13%).

We believe Afren currently offers an attractive combination of: 1) low valuation, 2) unique positioning to continue to exploit low risk development opportunities in the Niger Delta, 3) production ramp-up at Okoro Setu to 21 kbpd, 4) 2H08 expected to be the first interim results with positive operating earnings and cash flow, 5) near-term high impact exploration potential in Ghana, 6) the company has access to a differentiated source of financing with the Sojitz strategic alliance $269mn of cash as at 30 June 2008 and 7) longer-term potential for Nigerian gas monetisation. The company does have some refinancing risk in 2009 that could result in slower growth, however this is not our base case assumption and we believe it is more likely that the Sojitz alliance will allow the company to continue to grow.

Figure 4: Afren asset summary Country Acquired Working interest Operator Work programme Cote d'Ivoire Block CI-11 1Q08 48% Afren Production Block CI-01 1Q08 80% Afren Development Lion Gas Plant 1Q08 100% Afren Production Nigeria Okoro 2Q06 50% Amni Development Setu 2Q06 50% Amni Appraisal Ogedeh 3Q05 50% Bicta Appraisal Ofa 2Q07 33% IEL Appraisal Eremor 3Q07 50% Excel Development OPL 907 1Q08 41% GEC Exploration/Appraisal OPL 917 1Q08 42% GEC Exploration/Appraisal Ebok 1Q08 40% Oriental Appraisal Ghana Keta 4Q07 88% Afren Exploration Congo (Brazzaville) La Noumbi 2Q06 14% Maurel et Prom Exploration Nigeria - Sao Tome & Principe JDZ Block 1 1Q05 4% Chevron Exploration Gabon Iris Marin 2Q05 17% Sterling Energy Exploration Ibekelia 2Q05 20% Sterling Energy TEA



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The company is currently trading at 1.3x 2009 and 0.95x 2010 P/CF, 1.1x 2009 and 0.9x 2010 EV/EBITDA, 2.2x 2009 and 1.4x 2010 P/E, 24,400 per daily flowing barrel and $6.11/2P bbl (excluding natural gas), on our estimates. This is compared with global E&P peers, which are trading at 4.2x 2009E and 3.76x 2010E P/CF, 3.51x 2009E and 3.12x 2010E EV/EBIDA, 7.80x 2009E and 5.49x 2010E P/E, $60,336 per daily flowing barrel and $13.41/2P boe.

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Please see the table below for near-term catalysts for Afren.

Figure 5: Afren near-term catalysts Activity Expected timing Okoro Setu production ramp-up to 21 kbpd Ongoing Ebok Field Appraisal well 4Q08 Ebok Field potential first production 2Q10 Ghana Keta exploration drilling results 1Q09 Congo La Noumbi drilling results 2H09 Angola Block 16 exploration drilling results 1Q09 Block CI-11 workover 2H09 Define development and seek approvals for Block CI-01 2H09


First production and ramp-up at Okoro Setu Afren holds a 95% effective interest prior to payback and 50% thereafter in the Okoro Setu Project, located on OML 112 in the eastern portion of the shallow water Niger Delta 12 km offshore. Afren announced first oil production at Okoro Setu in June at 6 kbpd gross with exit 2008 production of around 20 kbpd of 27° API oil expected. Netherland Sewell and Associates International (NSAI) estimates that the Okoro and Setu fields have combined reserves of 32 mmboe. The map below illustrates the Okoro Setu development.

Figure 6: Okoro Setu location map

Source: Company data, IHS Energy

Afren signed a production sharing and technical services agreement with indigenous company Amni International Petroleum Development Company (operator) in June 2006 for the eastern part of block OML 112. Under the agreement, Afren is responsible for financing the development programme with cost recovery on

Near-term catalysts


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production that includes a capital uplift. The Okoro and Setu fields were originally awarded to Amni in 1993 as part of the indigenous licensing programme in Nigeria. The Okoro field was discovered in 1973 by Japan Petroleum, while the Setu field was discovered by Amni in 2002.

Acquisition of Devon Energy Cote d’Ivoire Afren acquired Devon Energy’s subsidiaries in Cote d’Ivoire on 6 Mar 2008 for adjusted consideration of $164mn. Transaction metrics were $54,667 per daily flowing barrel, 5.80/boe on a 2P basis before adjustments for the Lion Gas Plant. This is compared to historic M&A comparables in Africa of $72,161 per daily flowing barrel and $17.40 per bbl on a 2P basis. Please see the table below that illustrates historic transaction comparables for Africa.

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The Cote d’Ivoire assets are comprised of a 47.96% working interest (operator) of the producing Block CI-11 offshore, a direct 65% interest (operator) with rights over an additional 15% interest in the undeveloped Block CI-01 offshore and a 100% interest in the onshore Lion Gas Plant (LGP). Please see below for a map of Afren’s interests in Cote d’Ivoire.






EV/Daily production


Ltd Algeria 954.1 585.5 - 1.63 -


Guinea 2200.0 208.3 20,000 10.56 110,000




Sudan 500.0 - 10,000 - 50,000









Egypt 59.0 6.3 1,500 9.37 39,333





Algeria 299.8 - - - -


Prom Congo 1434.0 126.0 17,000 11.38 84,353





Gabon 1415.9 67.5 10,000 20.99 141,588


Egypt 269.3 23.2 5,325 11.60 50,579



Egypt 225.0 23.2 5,325 9.69 42,256




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Figure 8: Cote d'Ivoire: Block CI-11, CI-01, Lion Gas Plant


This acquisition has provided Afren with net daily entitlement production volumes of approximately 3 kboepd from upstream oil and gas production and NGL extraction. Current production is from the Lion (oil and gas) and Panthere (gas) fields on Block CI-11. This field has been producing since 1995 with the PSC expiring in 2019 and natural gas sold locally under two long-term contracts.

On the CI-01 Block there have been 14 exploration and appraisal wells drilled by Agip and Esso with three discoveries - Kudu (1964), Eland (1978) and Ibex (1985). The Ibex discovery is a potential oil development that would require a full offshore facility and 98 km pipeline with produced gas compressed and an 8 km pipeline to the Eland platform. The Kudu and Eland field gas development could be developed with minimal offshore facilities and a 72 km gas pipeline to the Lion gas plant.

The CI-11 Block is governed by a PSC contract with: 1) no royalties, 2) costs recovered from 63% of total production, 3) production oil sharing based on production ranges with current contractor share of 40%, 4) production gas sharing ranges, 5) income tax of 50% that is paid on behalf of the contractor out of the government share of production and 6) overriding royalty interest with 2.1% of contractors’ petroleum proceeds paid to Frank T. Barr and G. Willard Frank.

Net 2P reserves in Cote d’Ivoire are 28 mmboe as at 30 June 2007. Estimated 2P reserves on the CI-11 Block are 11.6 mmboe while the CI-01 Block has potential for development upside with 2P undeveloped reserves of 16.7 mmboe.

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Potential first production at Ebok in 2010 Afren established a farm-in agreement with indigenous company Oriental Energy Resources (operator) in Apr 2008 for the Ebok field, receiving a 40% participating interest. The Ebok field is located on OML 67 50 km offshore of south east Nigeria (135 feet water depth) and is a marginal field. Ebok was originally discovered by the ExxonMobil/NNPC JV in 1968 and is adjacent to a significant number of producing fields. The block is currently in the appraisal phase and estimated to have STOIIP of 77-167 mmboe based on well tests at Ebok-1 and Ebok-2. Recoverable resources could be in excess of 25 mmbbl based on analogous field recovery factors of 20-45%. There is also appraisal potential at Ebok West and exploration potential at Ebok North. The map below illustrates the Ebok Field.

Figure 9: Ebok Field location map

Source: Company data, Wood Mackenzie

Afren is currently drilling a two well appraisal programme at Ebok with potential for a field development plan to be submitted in 2Q09 and first production as early as 2Q10 if the appraisal wells are successful. This field could be developed with an FPSO and pipeline to adjacent facilities.

The Ebok field is subject to the fiscal terms of the marginal field programme.


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Eremor revised development plan Afren holds a 90% effective interest prior to payback and 50% working interest thereafter in the Eremor field located onshore in the western Niger Delta on OML 46. Eremor is designated a marginal field and was originally discovered by Shell in 1978 (Eremor-1). This field is a development opportunity for Afren with potential peak production of 4-5 kbpd from two wells. The company intends to recomplete the Eremor-1 well with potential for 2 kbpd with a second horizontal well to follow if the recompletion is successful. The map below shows the Eremor field.

The new field development plan at Eremor uses a barge mounted production system to process the Eremor crude and then transport the treated crude to the Brass Creek manifold.

NSAI estimates 2.9 mmbbl of proved reserves (1P), 4.1 mmbbl of proven plus probable reserves and 10 mmbbl of proven plus probable plus possible reserves (3P).

Afren signed a financing and technical services agreement with indigenous company Excel Exploration & Production (operator) at the Eremor Field. Afren is responsible for financing phase 1 of the development plan with cost recovery from 90% of net field revenues and an uplift in capital.

Figure 10: Eremor location map (print likely poor quality)


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Potential cluster development at Ogedeh (OML 90) Afren holds an effective interest of 91.25% interest prior to payback and 50% working interest thereafter in the Ogedeh field (OML 90) located in the shallow water portion of the western Niger Delta. This field is designated as a marginal field and was originally discovered by Chevron in 1993 with the Ogedeh-1 well, however, the well was not tested. If successful, there could be potential for 4-5 kbpd from two wells from this development. The map below illustrates the location of Ogedeh.

Figure 11: Ogedeh location map


A cluster development is likely for this asset with options currently being discussed with owners of the Ajapa and Akepo marginal fields in OML 90.

Afren signed a financing and production sharing and technical services agreement with Bicta Energy in 2006. The terms of the agreement require Afren to finance development costs with cost recovery including capital uplift on production.


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Exploration upside potential offshore Ghana The major near-term exploration target the company is drilling is the Cuda prospect on the Keta Block (Afren 88%) offshore Ghana with company estimates for the prospect of mean unrisked resources of 325 mmbbl (P10, 642 mmbbl). The well is scheduled to begin drilling in November with the Transocean Deepwater Discovery. This well is targeting upper cretaceous deepwater sandstone reservoirs and is a similar play-type to the Jubilee and Odum discoveries. Jubilee was the largest oil discovery in 2007 and is expected to hold P90-P50-P10 reserves of 500-1000-1,800 mmbbl. Afren is currently negotiating a farm-down to reduce the company’s exposure to the exploration well and any potential subsequent work programme. Please see below for maps of the Keta block and Cuda prospect.

Figure 12: Keta block location map

Source: Company data, IHS Energy

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In the Congo the licence operator has scheduled two wells in 1H09 on the La Noumbi licence in 1H09 (Afren 14%).

Drilling on JDZ 1 is expected to occur after exploration wells have been drilled on Blocks 2, 3 and 4. The rig has been delayed until 2H09 to drill the first JDZ exploration wells so JDZ 1 drilling is unlikely to occur until 2010.

Figure 13: Ghana Keta block prospects



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In Jan 2008 Afren signed a cooperation agreement with E.ON Ruhrgas and African LNG to develop and monetise natural gas for domestic (Nigeria) and export purposes. This is consistent with the Nigerian government’s Natural Gas Master Plan (NGMP).

In Mar 2008, Afren announced the signing of production sharing contracts (PSCs) for two licences, OPL 907 and 917 in the Anambra Basin, located onshore north of the Niger Delta. Natural gas was discovered on OPL 907 by Shell/BP in 1956 with the Akukwa-1 and Akukwa-2 wells. The Akukwa-2 well found 500 ft of net gas pay and produced dry gas on the test.

The Igbariam gas and oil discovery on OPL 917 was discovered by Shell/BP in 1971 with the Igbariam-1 well that reported a 196 ft net gas column and 30 ft condensate/oil column but was not tested. The discovery is estimated to have gas in place of 300 bcf and oil in place up to 80 mmbbl. The Anambra Basin is considered to have potential gas resources in excess of 5 tcf. The map below shows OPL 907 and OPL 917.

Afren is currently finalising an environmental impact assessment (EIA) programme ahead of seismic acquisition on OPL 907 and OPL 917 expected in 1H09.

Gas monetisation

Figure 14: Afren gas monetisation: OPLs 907 & 917

Source: Company data, HIS Energy

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Afren entered into a joint venture agreement with indigenous company Global Energy Company Ltd in Mar 2008 and signed PSCs for OPL 917 and OPL 907. Afren has a 41% interest in OPL 907 and a 42% interest in OPL 917, and will act as operator of both assets. The JV agreement between Afren and GEC defines the commercial terms under which Afren will participate with GEC in the exploration and development of the two licences. Afren has a combined 50% interest in the JV, with GEC holding the remaining 50%.

Afren also recently entered into a memorandum of understanding with Electricite de France (EDF) and Gasol to examine establishing a gas aggregation joint venture to identify and develop onshore and offshore stranded gas assets in West Africa. It is expected that Afren and EDF will share participation in the upstream component of the development while EDF and Gasol will share participation in gas collection, processing, liquefaction and monetisation.

Strategic Alliance with Sojitz allows for further growth On 9 Oct 2008 Afren announced a strategic alliance with Sojitz to pursue acquisition opportunities in Africa. The alliance will run for a period of three years or until Sojitz has invested a total of $500mn in joint acquisitions. Sojitz will provide financial support to the alliance for securing material joint acquisitions, including securing funding and credit support from Japanese governmental funds. Sojitz has also invested $45mn in loan notes that become convertible bonds at the time of entering into or announcing joint acquisitions.

Less likely M&A target We would not rule out an acquisition of Afren, however, we believe that it is unlikely given that its key advantage is the management team’s ability to access resources. Additionally, the size of the assets within the company’s portfolio also makes an acquisition unlikely. We note that potential exploration success in Ghana could generate interest among some of the independents, however the company is currently farming-down this interest. Addax Petroleum could be a suitor given the overlap in core operational areas particularly in Nigeria. We also note that the scale of the company’s assets do not make them attractive to a national oil company.

We note that currently 13.4% of the outstanding shares of the company are not in public hands.


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Please see the table below for the capital structure of Afren.

Figure 15: Afren plc capital structure Share structure Amount Basic shares 445 Stock options 12 Fully diluted shares outstanding 491 Sources of capital Amount ($mn) Long-term debt 464 Cash & cash equivalents 314 Shareholders' equity 320


Balance sheet, capex, hedging and future funding needs Afren had cash of $269mn as at 30 June 2008 with capex for 2H08 estimated at $230mn. In 2009 capex is estimated at approximately $200mn.

As a condition of reserve-based lending at Okoro Setu, Afren currently has swaps in place for approximately 17% of production from 2008 to 2010 inclusive. The swaps are at prices of $60/bbl, $55/bbl and $50/bbl from 2008-2010 respectively. The company also has call options with strike prices of $65.40/bbl, $60/bbl and $55/bbl from 2008-2010 respectively, allowing Afren to participate in pricing upside above these levels.

In Cote d’Ivoire, Afren has 1.5 mmbbl of oil hedged until the end of 2012 at $85/bbl.

Afren does not pay a dividend.

Reserves and resources Based on company, NSAI, Devon and Ryder Scott estimates, Afren has reserves and contingent resources (2P) of 80 net mmboe. The company estimates net unrisked prospective resources of 635 mmboe. Please see the chart below that illustrates reserves.

Figure 16: Afren Reserves and contingent resources (2P), mmboe

Okoro Setu, 23

Ebok, 23

CI-01, 17Ogedeh, 3

Eremor, 2

CI-11, 12


Capital structure

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Our target price is equal to our core DCF-derived NAV estimate of 91p/share, which includes value for producing assets CI-11 and Okoro Setu, and appraisal and development assets CI-01 and Eremor, as well as the Lion gas plant. Our total NAV estimate for Afren is BPN128/share after including potential risked recoverable resources and best estimate risked contingent plus prospective resources.

Our target price of BPN91/share equates to 3.1x 2009 and 2.2x 2010 P/CF, 1.9x 2009 and 1.5x 2010 EV/EBITDA, 5.2x 2009 and 3.2x 2010 P/E, $42,200 per daily flowing barrel (bpd) and $10.56/2P bbl (excluding natural gas), on our estimates.

The company is currently trading at 1.3x 2009 and 0.95x 2010 P/CF, 1.1x 2009 and 0.9x 2010 EV/EBITDA, 2.2x 2009 and 1.4x 2010 P/E, $24,400 per daily flowing barrel and $6.11/2P bbl (excluding natural gas), on our estimates. This is compared with global E&P peers, which are trading at 4.2x 2009E and 3,76x 2010E P/CF, 3,51x 2009E and 3,12x 2010E EV/EBIDA, 7,80x 2009E and 5,49x 2010E P/E, $60,336 per daily flowing barrel and $13.41/2P boe.

Valuation

Figure 17: Afren net asset valuation summary

Current production NAV, $mn NAV, GBPmn

Per share BPN

% of value share

Okoro Setu (Nigeria shallow water) 322 184 41.52 24% CI - 11 (offshore Cote D'Ivoire) 188 107 24.18 14% Production & Development NAV (2P) 322 291 65.70 37% Appraisal & development Eremor (onshore Niger Delta) 104 59 13.35 8% CI - 01 (offshore Cote D'Ivoire) 123 70 15.82 9% Risked Appraisal & Development NAV (2P) 226 129 29.17 17% Potential risked recoverable resources - appraisal & development Ebok (offshore Nigeria) 173 98 22.23 13% Ogedeh (offshore Niger Delta) 8 4 0.97 1% Potential Recoverable Resources 180 103 23.20 13% Best estimate risked contingent plus prospective resources Keta (offshore Ghana) 66 38 14.92 8% La Noumbi (onshore Congo) 31 18 7.01 4% Iris Marin (offshore Gabon) 27 15 6.10 3% JDZ Block 1 (Sao Tome Principe / Nigeria) 38 22 8.59 5% Best estimate risked prospective resources NAV 162 92 36.61 21% Midstream assets Lion Gas Plant Cote D'Ivoire 95 54 21.46 12% Midstream asset value 95 54 21.46 12% Total 986 562 176.14 100% Liabilities Long-term debt 374 213 84.58 66% Less cash 159 91 35.96 28% Net debt 215 123 48.62 -38% Current net asset value 770 439 127.52



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Major risks for Afren include exploration, appraisal and development risk; risk from governmental or business corruption; and uncertainty regarding interpretation and application of foreign laws and regulations, and gas flaring legislation. The timing of potential gas monetisation in Nigeria is highly dependent on political developments. In the current environment, financing and refinancing risk is also a potential issue for the company and could slow development.

Risks inherent in the global oil and gas business include volatility of oil and natural gas pricing, currency risk, cost inflation for materials and services, geological risk, operating hazards, access to supplies and equipment, access to drilling rigs and experienced trades, geopolitical risk and unforeseen weather conditions that can affect drilling programmes.

Other risks include potential changes to existing royalty regimes, regulatory environments, political regimes and environmental considerations.

Key risks

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Afren was founded in 2004 and was admitted to AIM in Mar 2005 with an initial market capitalisation of GBP25.9mn. The company signed an agreement for participation in the development in the Ogedeh field offshore Nigeria in Aug 2005, acquired 12.86% interests in the Themis Marin and Iris Marin blocks offshore Gabon in 2005, and completed the acquisition of a 4.45% interest in Block 1 in the Joint Development Zone in 2005. The company also raised an additional GBP7.5mn in July 2005 and GBP11mn in Dec 2005.

In 2006, Afren signed an agreement for the development of the Okoro and Setu fields in OML 112 offshore Nigeria and completed appraisal drilling on the Okoro Field. The company also acquired Heritage Congo Limited that provided a 14% interest in the La Noumbi licence onshore Republic of Congo. The Obo-1 discovery well on JDZ Block 1 was also announced with 150 ft of net hydrocarbon pay in multiple reservoirs. The company also appointed Dr Rilwanu Lukman as non-Executive Chairman, established an international advisory board and completed a $75mn convertible bond issue.

In 2007 Afren secured a $230mn debt facility for the Okoro Setu Project and received approval for the Okoro Setu Project Development Plan. The company also negotiated a farm-in agreement with Independent Energy for participation in the Ofa Field and signed an agreement for participation in the Eremor field in July 2007. The company also raised equity of $65mn and closed an unsecured loan for $50mn. Acquisitions in 2007 included Devon Energy’s exploration interests in Ghana. The

Company background

Figure 18: Afren event chart – company history

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14 Mar 2005: Trading begins on AIMunder ticker AFRE

19 Jul 2005: Afren PLC announces acquisition of tw o licence interests in Gabon

30 May 2006: Hydrocarbon discovery confirmed at Obo-1 w ell, block 1 of the Nigeria Sao Tome & Principe Joint Development Zone

7 Jun 2006: Announces acquisition of Heritage Congo Limited for $28mn in cash and 2mn Afren w arrants

22 Nov 2006: Heads of Agreement signed to acquire 5% stake in Angola block & completed acquisition of Heritage Congo Limited

8 May 2007: Enters into a Farm-In Agreement w ith Independent Energy for participation in the Ofa Field in Northern Niger Delta

15 Jun 2007: Raises $65mn via share placement

3 Mar 2008: Afren signs Production Sharing Contracts for tw o licences in gas rich Anambra Basin in Nigeria

25 Sep 2008: Completes acquisition of Devon Energy Corp's interests in Cote d'Ivoire for a consideration of $164mn

10 Jun 2008: Announces First Oil from the Okoro Setu Project

3 Apr 2008: Proposes raising GBP118.75mn by issuing 95mn shares at 125p/share

24 Mar 2006: Confirmsdrilling began at the Obo-1 w ell, Block 1 of the Nigeria Sao Tome & Principe Joint Development Zone

18 Jul 2007: Enters into an agreement w ith Excel to jointly develop Eremor f ield in OML 46, located offshore Nigeria

01 Aug 2008: Afren confirms ICM-1 w ell, drilled in the Iris Magin permit, plugged and abandoned

27 Feb 2007: Board appoints Osman Shahenshah, co-founder and CFO, as CEO replacing Brian O'Cathain w ho resigned due to personal reasons

29 Sep 2008: Receives approval on assignment and development of Ebok f ield, located offshore Nigeria, and gets confirmation on forw ard drilling programme

Source: Company data, Bloomberg


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first exploration well on La Noumbi was also completed in Oct 2007 with the well plugged and abandoned.

In 2008 Afren signed PSCs for OPL 907 and OPL 917 offshore Nigeria with Global Energy Company and signed a cooperation agreement with E.ON Ruhrgas AG and African LNG Holdings for natural gas monetisation. The company also acquired Devon Energy’s interests in Cote d’Ivoire for $205mn in Mar 2008 and farmed in to the Ebok Field offshore Nigeria through an agreement with Oriental Energy Resources in April 2008. The company raised $236mn in equity in 2008. First organic oil production for Afren was achieved at Okoro Setu in June. The company also entered into a strategic alliance with Sojitz Corporation to pursue acquisition opportunities in Oct 2008.

Board of directors and senior management profiles Board of directors

Dr Rilwanu Lukman, KBE, Legion d'Honneur, chairman.

Lukman is an internationally known and respected figure in the oil and gas industry. Some of his key appointments have included: secretary general of OPEC (six years), president of OPEC (nine sessions), Nigerian minister of petroleum resources, special adviser to the Nigerian president for oil and gas, Nigerian minister of foreign affairs, Nigerian minister of mines, and founder and chairman of the African Petroleum Producers Association. Lukman is currently the honorary advisor on energy and strategic matters to the president of Nigeria.

Lukman is key to Afren to develop and implement its asset acquisition strategy. He holds a BSc from the Royal College of Mines, Imperial College (London), and diplomas, from prestigious institutions including the University of Leoben (Austria), McGill University (Montreal), University of Bologna (Italy), Ahmadu Bello University and the University of Maiduguri in Nigeria.

Osman Shahenshah, chief executive

Shahenshah was part of the management team that founded Afren and has over 20 years experience of oil and gas finance. His international career began with Credit Suisse First Boston and has included senior positions in the oil and gas finance groups of the International Finance Corporation (private sector arm of the World Bank), and the investment banking divisions of Dresdner Kleinwort Wasserstein and Mediocredito Centrale.

Shahenshah has been actively involved in the African oil and gas sector for more than 15 years, working with companies such as Shell, Chevron, Total, ENI and the NNPC. He holds a PhD from the University of Pennsylvania, a master’s degree from Columbia University and a bachelor’s degree from Brown University.

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Egbert Imomoh, executive chairman, Afren Nigeria

Imomoh came from the Shell Group of companies with whom he gained 36 years of experience in Nigeria, the UK and the Netherlands. Recently, he served as deputy managing director of Shell Petroleum Development Company (Nigeria) (SPDC), one of the Shell Group's largest operating companies, which is responsible for operating a joint venture that produces approximately 1 mmbpd.

Trained in mechanical and petroleum engineering, Imomoh held a wide variety of senior positions throughout the Shell Group, from chief petroleum engineer in SPDC, technical and planning manager to deputy MD of SPDC. He is member of the Society of Petroleum Engineers and has served on the SPE board as regional director for Africa.

Shahid Ullah, chief operating officer

Ullah has held senior management positions at Western Atlas and Baker Hughes, where he was responsible for managing petroleum equities and assets and in particular brings extensive technical and commercial knowledge of the African petroleum industry. Ullah holds a degree in petroleum engineering from the University of Texas and received executive development training at Oxford University and the London Business School. He is a member of the engineering advisory board at the University of Texas.

Constantine Ogunbiyi, executive director

Prior to his recent appointment as executive director, Ogunbiyi has been an associate director, special assistant to the chairman, general counsel for the group and a director of Afren's Nigerian wholly-owned subsidiary. Ogunbiyi assisted in the establishment of Afren in late 2004. He has over 10 years’ experience of private equity, acquisition, structured, trade and project finance, and public and private partnerships in the African energy and infrastructure sectors in particular.

Prior to joining Afren, he was the deputy head of Cadwalader, Wickersham & Taft LLP's Africa practice. Before this, Ogunbiyi spent four and a half years with Herbert Smith's international finance and banking department. He has also served as a strategic adviser to the New Partnership for Africa's Development (NEPAD) Business Group and the Southern African Development Community's (SADC) Banking Association's PPP unit.

Guy Pas, non-executive director

Pas is an international executive with a background in senior financial and investment management roles relating to African natural resources.

Following an early career as a commodity and trade finance officer at Chase Manhattan Bank, Pas was a founding partner of the Addax and Oryx Group, a group of international petroleum marketing and producing companies operating in Africa. He has participated in the development of several listed mining companies focused on Africa.


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Pas also manages Synergy Resources Fund, an unlisted fund investing in mineral resources, and Vector XXI Finance, a Geneva-based investment advisory company. Pas holds a cum laude degree in applied economics from Antwerp University.

Peter Bingham, non-executive director

Bingham is a senior financial executive with over 40 years’ experience in international financial markets, primarily at Barclays. Bingham held directorships at the London branch level, in the group's merchant banking division and at BZW (now Barclays Capital), where he set up the credit risk management team. Bingham ultimately became head of banking at BZW and served as a member of Barclays’ central Group Credit Committee.

John St. John, non-executive director

John St John was previously strategic financial advisor to the Afren board, having been appointed in Nov 2006. He was formerly global head of equity capital markets at Dresdner Kleinwort, Commerzbank and Lehman Brothers and European head of equity capital markets at Citigroup, formerly Salomon Brothers. He has acted as an advisor on over $100bn of equity and equity-linked issuance in all major markets worldwide. He currently serves as chairman of equity capital markets at Nomura International plc.

Afren international advisory board Bert Cooper, special advisor to the board

Cooper has been active in the African natural resources sector for over 25 years. During the 1980s he devised and led an initiative to restructure what at the time was Liberia's biggest industrial project – an iron ore mining company with capital investment of over $600mn. Cooper also formed Liberia's mining parastatal, whose management, marketing and financing requirements were contracted to Cooper's companies. Cooper – a West African national – was a principal member of the team that founded Afren.

Ennio Sganzerla

Sganzerla was until recently senior vice president (E&P) at ENI, having joined the group in 1971. Since 1997, he has been responsible for the North Sea, America, Australasia and Russia. Previously, he was managing director of ENI's sizeable North Sea operations.

Over the course of his wide-ranging career at ENI, he was instrumental in establishing and building ENI's presence in Congo, and played an active role in increasing ENI's position in Nigeria, Gabon and Egypt as regional VP for Africa. Sganzerla was also active in leading the group's M&A activities, including the acquisition of Lasmo plc, British Borneo and others.

Brian Ward

Ward was formerly regional chief executive for Shell E&P Africa with responsibility for Shell's upstream African operations and relationships with host governments.

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Prior to managing Shell's operations in Africa, Ward's career included a number of senior positions within the Shell organisation, including managing director of Petroleum Development Oman, managing director of Shell E&P (NAM) in Holland, and deputy managing director and production director for Shell Expro UK.

Patrick Cherlet, director of operations

Cherlet oversees Afren's oil and gas operations and commercial valuations. He specialises in the organisation of global oil and gas projects, taking projects from entry to exploration and development. He also specialises in the commercial valuation of oil and gas assets and projects. Previously, he held management positions at Western Geophysical, Western Atlas, Baker Hughes, Randall & Dewey and Jefferies International. Cherlet received an MS from Stanford University and an MS from Ghent University in Belgium.

Iain Wright, technical director

Wright leads Afren's technical team and is responsible for all geoscience and reservoir engineering activities associated with Afren’s ongoing exploration, development and production assets together with new business technical assessments to enhance the company's portfolio. With over 25 years working in the industry, he has extensive international geosciences experience and has served in both development and exploration geology roles. Previously, he was managing director at Jefferies. He also worked with Randall & Dewey, Baker Hughes, Qatar Petroleum, Conoco (UK) Ltd and Anadrill Schlumberger. Wright received a BSc (Hons) from the City of London Polytechnic and is a certified petroleum geologist (CPG) with the AAPG, and a fellow with the Geological Society, the SPE and PESGB.

Nick Johnson, head of exploration and new ventures

Johnson is a geologist with over 25 years’ experience in oil and gas exploration and production. He is currently head of exploration and new ventures at Afren a role he took up in Sep 2005, soon after the listing on the London Stock Exchange. He has full technical responsibility for the development and management of Afren's portfolio which has grown rapidly since Mar 2005. He began his oil industry career in 1981 as an exploration geologist with BP, where he worked on a variety of global supervisory and technical roles. He joined OMV in 1991, working in both London and Vienna and ultimately became head of exploration and reservoir, responsible for the technical quality and development of OMV's global portfolio

Johnson graduated with a degree in geology in 1976 from Bristol University and a PhD from University College London in 1980.

Jeremy Whitlock, group financial controller

Whitlock is a qualified accountant with 18 years’ experience in the oil industry. He spent 13 years with Enterprise Oil in a variety of roles across the finance department, including several years as financial planning manager and international and corporate accounting manager. Prior to joining Afren he was planning manager at Nexen (UK) Ltd.


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Galib Virani, head of acquisitions and investor relations

Galib Virani has a background in finance and M&A. Prior to joining Afren in 2006 to work in his current role, he worked on a variety of mergers and acquisitions and equity capital market transactions, predominantly in the oil and gas sector, as part of the corporate finance and advisory group of Dresdner Kleinwort Wasserstein. At Afren, Virani has played a key role in the company's financing and contributed to the overall growth of the company's portfolio of assets. Virani is a fellow of the Securities Institute, and has a master’s degree in finance and investment (with distinction) and a MPhil in emerging market finance.

Biola Ajayi, geology and geophysics manager

Ajayi has over 20 years’ experience as a geologist and geophysicist. He spent the majority of his career with Shell and Schlumberger in Nigeria, in various capacities including as regional and operations geologist, head of geological operations, and senior consulting geoscientist. Ajayi is a Nigerian national.

Faiz Imam, Manager, special projects

Imam has over 10 years of experience in the oil industry. He has worked in a variety of roles including production engineering, facilities engineering and government relations. He started his career with Texaco in Nigeria as an offshore production engineer and moved through to developing projects which handled associated gas production and then onto deepwater project development. While at Afren, Imam has contributed significantly to the company's business development initiatives in Nigeria. Imam was part of the team that worked on the billion barrel Agbami field. He holds a M Eng in chemical and biochemical engineering from University College London.

Sade Ogundeji, financial controller, Afren Nigeria

Ogundeji has over 11 years experience in auditing, banking and accounting. She was previously financial controller at Trust Bank of Africa Limited and XL Management Services Limited in Nigeria. Ogundeji is a Nigerian national.

Shirin Johri, company secretary

Prior to joining Afren, Johri worked with Cadwalader, Wickersham and Taft LLP's Africa practice. Johri has extensive experience advising on acquisitions and disposals, joint ventures, infrastructure projects and private equity investment. Johri holds a LLM from the Cornell Law School, New York, LLB (Hons) from Delhi University, India and a bachelor’s degree from Delhi University and has also been called to the New York Bar.

Heritage Oil Lake Albert Basin drives near-term M&A



17 November 2008

Oil and gas Africa

Report date: 17 November 2008 Rating BUY Target price (comm), BPN 290.00 Target price (pref), $ n/a Current price (comm), BPN 179.50 Current price (pref), BPN n/a MktCap, $mn 715.56 EV, $mn 787.34 Reuters HOIL:L Bloomberg HOIL LN Common shares outstanding, mn 255.0 Change from 52 week high: -51.69% Date of 52 week high: 2 July 2008 Change from 52 week low: 74.4% Date of 52 week low 10 Oct 2008 Web: www.heritageoilltd.com Free float in $mn 474.42 Major shareholder with shareholding

A. Buckingham 33.7%

Average daily traded volume in $mn 2.3 Share price performance over the last 1 month -19.17% 3 months -50.36% 12 months n/a

� We initiate coverage of Heritage Oil with a BUY rating and a BPN290/share target price. Our target price is based on our DCF-derived NAV estimate for Heritage’s production, development and appraisal assets of BPN290/share, which mainly comprises the values for Block 1 and Block 3A in Uganda at Lake Albert, as well as proved plus probable (2P) reserves for producing assets in Russia and Oman. Our total NAV rises to BPN365.59/share after including risked value for best-estimate risked prospective resources in Kurdistan. Heritage Oil is currently trading at 51% of our total company NAV.

� Attractive combination of: 1) compelling valuation; 2) significant non-producing asset value with potential to declare commerciality in Uganda by year-end; 3) further high impact exploration in Uganda with Heritage expecting to drill four wells in 4Q08 and the first Kurdistan well to be drilled in December; 4) first production from the West Bukha field in Oman; 5) being the most likely M&A candidate in our coverage universe with an undeveloped world-class discovery at Lake Albert and an enterprise value of only $856mn; 6) potential for divestiture of assets in Russia and Oman; 7) a strong balance sheet with $113mn in cash.

� Most likely M&A candidate. We believe that Heritage Oil is the most likely near-term M&A candidate in our Africa E&P coverage universe with an undeveloped billion barrel-plus potential world-class discovery at Lake Albert Basin and an enterprise value of only $856mn. We believe that the Lake Albert discovery combined with the Kurdistan exploration assets would be attractive to a number of potential buyers.

Figure 1: Performance since listing Figure 2: Sector stock performance – 3 months

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2007 3.71 0.8 -0.35 -0.01 N/A N/M N/M 12% 130 75. N/M 0.00% 2008E 5.99 0.2 -0.14 -0.16 N/A N/M N/M 40% 852 105 N/M 0.00% 2009E 56.62 42.7 0.01 0.03 20.04 169.54 39.09 53% 3,300 60 770% 0.00% 2010E 78.21 52.6 0.03 0.07 16.28 36.05 17.30 65% 5,044 121 682% 0.00%


November 2008 Heritage Oil Renaissance Capital

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We initiate coverage of Heritage Oil with a BUY rating and BPN290/share target price. Our target price is a DCF-derived NAV estimate for Heritage’s production, development and appraisal assets, which mainly comprises the values for Block 1 and Block 3A in Uganda at Lake Albert, as well as proved plus probable (2P) reserves for producing assets in Russia and Oman. Our total NAV rises to BPN365/share after including risked value for best-estimate risked prospective resources in Kurdistan.

Heritage Oil is an independent exploration and production company with an enterprise value of $856mn. The company’s assets consist of production and development assets in Russia and Oman, exploration and development assets in Uganda, and exploration properties in the Democratic Republic of the Congo (DRC), Kurdistan Region of Iraq, Tanzania, Malta, Mali and Pakistan.

Production for Heritage Oil is currently derived from properties in Russia and Oman. As of the last reserve report of 30 Sep 2007, reserves consisted of total 2P net entitlement reserves of 62.1 mmboe, with additional mean-risked working-interest prospective resources at Block 3A and Block 1 in Uganda of 392 mmboe post government back-in rights (462 mmboe prior to back-in rights).

Heritage Oil offers an attractive combination of: 1) compelling valuation; 2) significant non-producing asset value with potential to declare commerciality in Uganda by year-end; 3) further high impact exploration in Uganda with Heritage expecting to drill four wells in 4Q08 and the first Kurdistan well to be drilled in December 2008; 4) first production from the West Bukha field in Oman; 5) being the most likely M&A candidate in our coverage universe with an undeveloped world-class discovery at Lake Albert and an enterprise value of only $856mn; 6) potential for divestiture of assets in Russia and Oman; 7) a strong balance sheet with $113mn in cash.

We believe that Heritage Oil is the most likely near-term M&A candidate in our Africa E&P coverage universe with an undeveloped billion barrel-plus potential world-class discovery at Lake Albert Basin.

The company is currently trading at 51% of our estimated NAV for the company’s production, development and appraisal assets and at $1.00/potential resource bbl (excluding natural gas).

Investment summary

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Renaissance Capital Heritage Oil November 2008

Figure 3: Heritage Oil near-term catalysts Activity Expected timing West Bukha Oman first production 4Q08 Spud first exploration well in Kurdistan on the Miran Block 4Q08 Declaration of commerciality at Lake Albert As early as 4Q08 Buffalo and Giraffe exploration wells (Uganda Block 1) 4Q08/1Q09 Kingfisher-3 appraisal well (Uganda Block 3A) Currently drilling, results expected 1Q09 Potential further drilling on Block 1 Uganda 2009 Tanzania 2D seismic 2009 Pelican-1 well (Uganda Block 3A) 2H09 Tanzania exploration well 2H09

Source: Heritage Oil, Renaissance Capital

Albert Basin – proving up a billion barrel-plus discovery In the Lake Albert Rift Basin, Heritage holds interests in Uganda of 50% of Block 1 (Heritage Operator, Tullow Oil, 50%), and 50% of Block 3A (Tullow Oil, 50%). The company has also signed a production sharing agreement (PSA) in the DRC for a 39.5% non-operated interest in Block 1 (Tullow Oil, 48.5%; COHYDRO, 12%) and Block 2 (Tullow Oil, 48.5%; COHYDRO 12%) that are contiguous to the Uganda Blocks. These blocks require a presidential decree and the validity of the award of these licences is currently being disputed by the Congolese oil ministry.

Figure 4: Heritage Lake Albert


The Lake Albert Rift Basin, located in the Western Rift Valley of Uganda, was originally discovered in 2005 with the Mputa and Waraga wells. Heritage drilled the Kingfisher-1 in March 2007, drilled on Block 3A in Uganda. This well tested at 13,893 bpd from four intervals.

Near-term catalysts


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Subsequently, Heritage Oil has drilled the successful Kingfisher-2 well on block 3A with a cumulative flow rate of 14,364 bpd from three reservoirs that was constrained by equipment. The Kingfisher-3 appraisal well was spudded in September with results expected by the company in 1Q09. Please see Figure 5, which illustrates the prospects, discoveries and gross contingent and prospective resources on Block 3A.

Figure 5: Block 3A gross contingent and prospective resources, mmboe Prospect P90 P50 P10 Mean Kingfisher 17 118 494 N/A Kingfisher North 4 32 97 37 Pelican 38 193 769 270 Crane Upper 68 372 1338 486 Crane Deep 28 177 1012 330

Source: RPS Energy, Company data

A full-scale commercial development in the Lake Albert region is contingent on proving up required resources of approximately 400 mmbbl to allow for pipeline construction from Uganda to the coast of Kenya (Mombasa) economic. Given the exploration success to date, we believe that there is a high probability that the resources will be sufficient to justify a pipeline with the potential to prove up reserves sufficient for commercial development by year-end. The first production from a larger scale development could be as early as 2012 -2014 with capacity for flow rates of greater than 140 kbpd on a gross production basis at start-up. Current expectations for pipeline capacity are in the range of 500k bpd. Please see the map in Figure 6 which illustrates the proposed pipeline route.

Figure 6: Proposed pipeline route


Drilling on Block 1 in Uganda commenced in September with the successful Warthog exploration well with a gross hydrocarbon-bearing interval of approximately 150 metres, with 46 metres of net hydrocarbon pay. The company expects the Buffalo well to be spud in November, followed by the Giraffe prospect. Please see

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the map and table in Figure 7, which illustrate the prospects, discoveries and gross contingent and prospective resources on Block 3A.

Figure 7: Block 3A


Figure 8: Block 1 gross prospective resources, mmboe Prospect P90 P50 P10 Mean Buffalo 111 344 826 420 Crocodile 16 31 57 35 Giraffe 35 76 161 89 Hartebeest 8 24 64 31

Source: RPS Energy

Tullow owns 100% of Block 2 in Uganda, located, contiguous to Block 1 and Block 3A. The Kasamene-1 discovery, located on Block 2, 2.5 km south of Block 1 is believed to be on trend with the identified drilling prospects on Block 1 and encountered over 31 metres of net oil pay.

Tullow has encountered oil in all the wells drilled in the Butiaba region in the northern part of Block 2. The company has recently completed drilling the Kigogole-1 prospect on Block 2 that encountered two zones with net pay of 10 metres. This well encountered oil just below 400 metres, the shallowest oil section in Uganda to date.

High impact drilling in the Kurdistan Region of Iraq Heritage Oil expects its first exploration well in Kurdistan to be spudded in December on the Miran Block with the company recently securing a rig to drill the well from Great Wall Drilling Company. Heritage expects the well to be drilled to over 3,000 metres and to target three principal reservoirs.


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The Miran Block is 1,015 km2, is on trend with the Kirkuk oil field and is 30 km south east of Addax Petroleum/Genel Enerji’s Taq Taq discovery. Heritage currently holds a 100% interest in the block prior to government back-in rights of 25%. Independent consultants, RPS Energy, have provided indicative estimates based on the structure, size and evaluations of fields in the region of low-mid-high STOIIP of 900-1950-3500 MMstb. Heritage recently acquired 330 km of 2D seismic on the block. The company also has an agreement with the KRG to build a 20k bpd refinery. Please see the map in Figure 9 of the Miran Block.

Figure 9: Miran Block


We note that the federal government of Baghdad and the Kurdistan Regional Government (KRG) recently established a committee to determine the federal oil and gas law that includes Prime Minister Nechirvan Barzani of the KRG and Federal Iraqi Prime Minister Nouri Al-Maliki.

Russia, Zapadno Chumpasskoye Heritage owns a 95% interest in the Zapadno Chumpasskoye licence through the company’s 95% ownership stake in Russian company ChumpassNefteDobycha Limited. The licence is located in Western Siberia and first production commenced in May 2007. Production was approximately 372 bpd in 1H08 with current production approximately 550 bpd of 39° API oil. As at 30 Sep 2007 the company had 2P

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reserves of 60 mmboe of and 3P reserves of 161.4 mmboe for the licence as estimated by RPS Energy. The map in Figure 10 illustrates the location of this licence.

Figure 10: Zapadno Chumpasskoye


In 2007 Heritage established a jointly owned company with TISE Holding Company, TISE-Heritage Neftegas, to appraise and acquire oil and gas assets in Russia and internationally. Other shareholders of TISE Holding Company include Concord, Zarubejneft, Zarubejneftegas (a Gazprom subsidiary), Technopromexport and Zarubejstroymontaj.

In our view, to justify continuing operations in Russia, Heritage must either scale up their presence in the country or divest their holding in the region. Our DCF-based NAV estimates for the asset indicate that the company’s 95% ownership stake in ChumpassNefteDobycha could be sold for around $285mn (NPV 10, $80/bbl long term). RPS Energy estimates 2P NPV (10%) of $226.6mn and 3P NPV (10%) estimates of $762.2. Please Figure 11 which illustrates recent historic transaction comparables for Russia.


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Block 8 Offshore Oman - West Bukha Field expected onstream 4Q08 Heritage owns a 10% interest in Block 8 offshore Oman. The block is operated by RAK Petroleum (40% interest), with the remaining interest held by LG International. Please see the map in Figure 12 which illustrates Block 8’s location.

Figure 11: Russian historic M&A transactions

Announced date Buyers Sellers


Proved+Probable (2P)

reserves total mn boe @6:1

Daily boe/day production EV/2P

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(boe)

28-Oct-08 Vitol Group; Rosco SA Arawak Energy Ltd 100 37 7145 2.69 13,966 26-Aug-08 ONGC Videsh Ltd; Oil &

Natural Gas Corp Ltd Imperial Energy Corporation PLC

2219 920 7000 2.41 317,014

22-Apr-08 Undisclosed private company Urals Energy Public Company Limited

94 22 4.29

18-Feb-08 West Siberian Resources Ltd Alliance Group 1302 123 10104 10.58 128,847 26-Dec-07 Gazprom Rosneft 3660 913 138426 4.01 26,440 28-Nov-07 Ashmore Group Taas - Yuriakh

Neftegazofobycha 175 72 11962 2.41 14,630

28-Nov-07 Urals Energy Public Company Limited

Taas – Yuriakh Neftegazofobycha; Finfund Limited

70 29 4785 2.41 14,630

28-Nov-07 Urals Energy Public Company Limited

Taas - Yuriakh Neftegazofobycha

590 244 40215 2.42 14,671

24-Jul-07 JKX Oil & Gas plc Yuzhgazenergie LLC 50 36 1.37 12-Jul-07 Rosneft Russian government; YUKOS 229 223 1.03 10-May-07 Rosneft YUKOS; Russian government 6414 1882 205945 3.41 31,142 3-May-07 Rosneft YUKOS; Russian government 6825 3169 276988 2.15 24,640 26-Apr-07 North West Oil Group Undisclosed 80 10 2879 8.24 27,783 4-Apr-07 Enel SpA; Eni SpA Russian government;

YUKOS; Gazprom neft 3648 180000 20,269

4-Apr-07 Enel SpA; Eni SpA YUKOS; Russian government 2130 5000 0.43 27-Mar-07 Rosneft YUKOS; Russian government 8796 186545 47,153 24-Jan-07 LUKOIL Geoilbent 300 217 8942 1.38 33,548 11-Jan-07 BP plc; TNK-BP Occidental Petroleum Corp 485 22600 21,460 21-Dec-06 Gazprom Mitsui & Company Ltd; Royal

Dutch Shell plc; Mitsubishi Corporation

7450 40000 186,250

18-Dec-06 StatoilHydro ASA Norsk Hydro ASA 32192 560401 57,445 3-Nov-06 West Siberian Resources Ltd CJSC Nortoil 115 103 1.12 26-Jun-06 Gazprom Novatek OAO 2949 99661 29,592 20-Jun-06 China Petroleum & Chemical

Corporation BP plc; TNK-BP; Udmurtneft 3500 922 123344 3.80 28,376

29-May-06 Lundin Petroleum AB Valkyries Petroleum Corp 689 22 4750 30.80 145,099 15-May-06 LUKOIL Marathon Oil Corporation 853 209 26600 4.08 32,068 18-Apr-06 Urals Energy Public

Company Limited Undisclosed 148 109 1000 1.35 148,000

10-Apr-06 BP plc; TNK-BP Russian government; Irkutsk Regional Administration; East Siberian Gas Company

79 23 3.39

6-Feb-06 Repsol YPF SA West Siberian Resources Ltd 90 18 2030 5.11 44,331 25-Jan-06 LUKOIL Primorieneftegaz OAO 261 4838 0.05 ------------------------------------------------ Median ------------------------------------------------ 590 123 24600 2.42 30,367 ------------------------------------------------Average-------------------------- 2948 832 89151 4.30 63,971

Source: Herold, Renaissance Capital estimates

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Figure 12: Block 8, offshore Oman


The west Bukha field development is progressing on schedule with the first production of 42° API oil expected by Heritage during 4Q08. As at 30 Sep 2007, RPS estimated 2P reserves from the Bukha and West Bukha fields were 5.3 mmboe on a 2P basis and 10.1 mmboe on a 3P basis.

Given financing requirements for the company’s other core developments, particularly at Lake Albert, we believe that the company’s holdings in Oman could be also sold. Based on our DCF-NAV analysis, we estimate that this asset could be sold for about $44mn (NPV 10, $80/bbl long term). RPS Energy estimates 2P NPV (10%) of $31.3mn and 3P NPV (10%) estimates of $60.2mn.

Most likely M&A candidate in our coverage universe We believe that Heritage Oil is the most likely M&A candidate in our coverage universe. The company has an undeveloped potential billion barrel-plus world class


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discovery in Lake Albert and a total company enterprise value of only $856mn. The potential scale of the Lake Albert discovery combined with exploration assets in the Kurdistan region of Iraq is likely to be very attractive to superindependents, mid-sized European integrateds, well as some of the supermajors.

We note that 35% of the currently outstanding shares are held by management and directors.

In the event that Heritage is acquired, we believe it could be sold for approximately $1.62bn-plus or BPN365/share based on our current total DCF NAV valuation for the company. The table in Figure 13 shows recent African historic M&A comparables. With further drilling success and clarity regarding the development plan there could be further potential upside to our M&A takeout valuation for the company.

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Early-stage exploration assets Heritage owns a 75% working interest in two blocks in Mali with acquisition of 2D seismic planned in the next year. This is wildcat exploration with five wells drilled in the country to date although there have been oil and gas shows either in or close to the company’s acreage.






EV/Daily production


Ltd Algeria 954.1 585.5 - 1.63 -


Guinea 2200.0 208.3 20,000 10.56 110,000




Sudan 500.0 - 10,000 - 50,000

3/5/2008 Afren plc Devon Energy Corporation Cote d'Ivoire

205.0 28.3 5,000 7.24 41,000









Egypt 59.0 6.3 1,500 9.37 39,333





Algeria 299.8 - - - -


Prom Congo 1434.0 126.0 17,000 11.38 84,353





Gabon 1415.9 67.5 10,000 20.99 141,588


Egypt 269.3 23.2 5,325 11.60 50,579



Egypt 225.0 23.2 5,325 9.69 42,256




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Heritage is also participating in four blocks in Tanzania; the Kisangire, Lukuliro, Kimbiji and Latham licences with at least one exploration well planned for 2H09.

In Pakistan, Heritage holds a 60% interest in the Sanjawi Block located in the Baluchistan province in the vicinity the Sui and Pirkoh gas fields. We also note that there are oil seeps to the south of the licence. The company also farmed into the Zamzama North Block (54% interest) that is immediately north of the Zamzama gas/condensate field.

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Please see the table in Figure 13 for Heritage Oil’s capital structure.

Figure 14: Heritage Oil capital structure Share structure Amount Basic shares and exchangeable shares 254,957,482 Options 24,532,010 Convertible 33,617,020 Diluted shares outstanding 313,106,512 Sources of capital Amount, $mn Debt 157 Cash & cash equivalents 113 Shareholders' equity 142


Capital structure


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We value Heritage Oil at BPN290 based on our DCF-derived NAV estimate for production, development and appraisal assets, which are comprised mainly of value for Block 1 and Block 3A in Uganda at Lake Albert, as well as proved plus probable (2P) reserves for producing assets in Russia and Oman. Our total NAV rises to BPN352/share after including risked value for best-estimate risked prospective resources in Kurdistan.

Figure 15: HOIL - net asset valuation summary

Production & development NAV, $mn

NAV, GBPmn

Per share, BPN

% of value share

Russia - Zapadno Chumpasskoye (2P) 285 158 61.86 16% Oman - Block 8 (2P) 44 24 9.60 2% Production & development NAV 329 182 71.46 18% Appraisal & development Uganda - Lake Albert 1,209 669 262.31 66% Appraisal & development NAV 1,209 669 262.31 66% Best estimate risked prospective resources Kuridstan – Miran Block 269 149 58.26 15% Best estimate risked prospective resources NAV 269 149 58.26 15% Other exploration acreage at book value DRC 1 1 0.32 0% Malta 8 4 1.68 0% Tanzania 3 1 0.57 0% Pakistan 1 1 0.32 0% Mali 1 0 0.13 0% Book value of other exploration acreage 14 8 3.01 1% Total 1,821 1,007 395.05 100% Liabilities Long-term debt 156 86 33.85 9% Less cash 16 9 3.49 1% Net debt 140 77 30.36 8% Current net asset value 1,681 930 364.69


Valuation

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Major risks for Heritage Oil include receipt of the presidential decree for blocks in the DRC, Congo Tutsi rebel activity in the DRC that could reach the Lake Albert region, the outcome of negotiations between the KRG and the federal government of Iraq, as well as governmental or business corruption and uncertainty regarding interpretation and application of foreign laws, regulations, permits, approvals, authorisations, consents and licences. A transportation solution for the Lake Albert discovery is also a key risk for the company. Further, Heritage is subject to funding risk as it will require additional capital to develop its asset portfolio.

Risks inherent in the global oil and gas business include volatility of oil and natural gas pricing, currency risk, cost inflation for materials and services, geological risk, operating hazards, access to supplies and equipment, access to drilling rigs and experienced trades, geopolitical risk and unforeseen weather conditions that can affect drilling programmes. Other risks include potential changes to existing royalty regimes, regulatory environments, political regimes and environmental considerations.

Key risks


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Heritage Oil was incorporated in the Bahamas in 1992. The company originally held exploration interests in offshore Angola, mainly a PSA on Block 4 in the Lower Congo Basin and through ROWAL, a joint venture company with Ranger, an interest in the Kiabo oil field. In 1996 the agreement with ROWAL was amended with Heritage receiving a 5% net-profit interest in the Kiame development and a 2% net-profit interest in the balance of Block 4. In 1996, Heritage acquired a 10% interest in Block 8 offshore of Oman. In 1997, the company was awarded a 50% interest in the Kouilou exploration licence and the Kouakouala A, B, C and D licences onshore Congo. In 1997, Heritage was awarded a 100% interest in Block 3 in Uganda and drilled three test wells at the Turaco drill site. In 1998 the Kiame oil field commenced production (terminated in 2002). In 1999, Heritage Oil listed on the Toronto Stock Exchange. In 1999, Maurel et Prom farmed into the Kouilou and Kouakouala A, B,C and D licences in the Congo. In 2001, the company sold a 50% interest in Uganda Block 3 licence to Energy Africa. Also in 2001 the M’Boundi field was discovered in the Kouilou permit and the company sold a 30% working interest in the permit to Maurel et Prom for proceeds of $35mn plus a 5% overriding royalty. The royalty was sold to Maurel et Prom for $30.4mn in 2004. The company was also awarded a 50% working interest in Blocks 1 and 3A in Uganda in 2004. In 2005, Heritage acquired a 95% interest in the Zapadno Chumpasskoye field in Russia and was appointed as operator, with the company establishing the TISE Holding Company the following year. Major events in 2006 included the award of Blocks I and II adjacent to the Uganda Blocks in the DRC and the sale of Heritage Congo to Afren for $21mn plus 1.5mn of warrants in Afren. First production from the Zapadno Chumpasskoye field began in May of 2007. The first exploration success also occurred in the Albert Basin in 2007 with the drilling of the Kingfisher-1 well. Heritage also entered Kurdistan in 2007 executing a PSA with the Kurdistan Regional Government on the Miran Block. The company commenced trading on the London Stock Exchange and completed a reorganisation on 31 Mar 2008.

Company background

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Board of directors and senior management profiles Michael Hibberd, chairman and non-executive director

Michael Hibberd has extensive international energy project planning and capital markets experience. He has been chairman and president of MJH Services Inc, a private corporate finance advisory company, since 1995, prior to which he spent 12 years with ScotiaMcLeod in corporate finance and held the position of director and senior vice-president, corporate finance. Hibberd has served and continues to serve on the boards of a number of private and public oil and gas companies, including companies listed on the TSX, Amex and TSXV. Hibberd joined the group in March 2006.

Tony Buckingham, chief executive officer

Tony Buckingham is the founder of the group. Buckingham commenced his involvement in the oil industry as a North Sea diver and subsequently became a concession negotiator acting for several companies including Ranger Oil Limited and Premier Oil plc. He was previously a security adviser to various governments.

Figure 16: Heritage Oil event chart – company history

3-Apr-08: Delists its ordinary shares and lists exchangeable shares on TSX

18-Sep-08: Heritage confirms that it is in preliminary discussions with a third party regarding a possible disposal of certain assets, which could include a sale of the Company

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2 Apr 2008: Lists Exchangeable Shares on the LSE under the symbol HOIL

11 Apr 2008: Signs agreement with Petrodel to farm-in two exploration licences in Tanzania

29 Apr 2008: Heritage Oil spuds Kingfisher -2 exploration well in Uganda

21 Apr 2008: Signs agreement with Dominion Oil & Gas Ltd. to farm-in two further exploration licences in Tanzania

3 Sep 2008: Announces successful tests of all three reservoir intervals in the Kingfisher-2 well in Uganda

15 Sep 2008: Receives Tanzanian Government's approval to farm-in four exploration licenses

18 Sep 2008: Heritage confirms that it is in preliminary discussions with a third party regarding a possible disposal of certain assets, which could include a sale of the Company 21 Oct 2008: Announces discovery

of oil in Warthog-1 exploration well in Block 1 in Uganda



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Paul Atherton, chief financial officer

Paul Atherton is a chartered accountant, having qualified with Deloitte & Touche, and holds a degree in geology from Imperial College, London. He has a corporate finance background with specific experience in the international mining and resource sectors. He joined the group in 2000 and was elected to the board in 2005.

General Sir Michael Wilkes, non-executive director

General Sir Michael Wilkes KCB, CBE, retired from the army in 1995 as adjutant general and Middle East adviser to the government. As adjutant general, Michael was the most senior administrative officer within the army and a member of the army board. During his distinguished career, he saw active service across the world while also commanding at every level from platoon to field army, including commanding 22 SAS and serving as the director of special forces. Michael is non-executive chairman of Cyberview Technology Ltd and a non-executive director of the Stanley Gibbons Group, both AIM listed. In addition he holds non executive positions in a number of private companies including Britam Defence and Trico Ltd and also chairs the advisory board of PegasusBridge, a homeland security company. He joined the group on admission in Mar 2008.

John McLeod, non-executive director

John McLeod is a professional engineer with over 36 years of varied resources extraction experience. He is the president of McLeod Petroleum Consulting Limited, the president, CEO and a director of California Oil and Gas Corporation and has held senior management positions and served on various boards including at Constellation Oil & Gas Ltd, Arakis Energy Company (as president and CEO); Pengrowth Gas Company (as VP, operations), Rally Energy Corp, CanArgo Energy Inc. and Canoro Resources. Currently, McLeod serves as a director of Paris Energy Inc, Consolidated Beacon Resources Ltd, Tuscany Energy Ltd, Diaz Resources Ltd and Keeper Resources Inc. He joined the group in 1998.

Gregory Turnbull, non-executive director

Gregory Turnbull is the regional managing partner of the Calgary office of the law firm of McCarthy Tetrault LLP. Turnbull has extensive knowledge of corporate governance issues and has acted for many boards of directors and special committees in that regard. He started his career with the law firm of MacKimmie Matthews in 1979. From 1987 to 2001, he was a partner with Gowlings LLP (formerly Code Hunter LLP). In 2001 and 2002, he was a partner with the law firm of Donahue LLP. Turnbull has been a partner of McCarthy Tetrault LLP since July 2002. He joined the group in 1997.

Salim Hassan Macki

Mr. Macki, a petroleum engineer who has spent most of his working life in the oil industry, was a Member of the State Council, Former Ambassador, Government of Oman and has been a Director of Oman Oil (a wholly-owned Government company) since 1996.

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Brian Smith, VP exploration

Brian Smith has 29 years’ experience in the oil industry. He initially worked as an exploration geologist for Exxon in the North Sea and Gulf of Mexico. Later he joined Enterprise Oil where he managed various exploration projects in the Far East and Eastern Europe/FSU. He joined Heritage as vice president, exploration in 1997.

Armen Sahakian, VP business development

Armen Sahakian has a post graduate degree in geology from Harvard University. He has more than 30 years’ experience in the oil industry and has held senior management positions in business development and international petroleum negotiations. The companies and institutions he has worked for include Conoco, Hispanoil, Partex-CPS, OMV and the World Bank, where he served as petroleum advisor on the oil and gas division's financed petroleum projects.

Stephen Kobak, VP production Russia and CIS

Stephen Kobak, a qualified engineer, has 27 years’ experience in oil and gas production operations, reservoir studies and asset development. The companies he has worked for include ESSO, Shell International and Khanty Mansiysk Oil Corporation in Western Siberia where he held senior management positions guiding technical and operations activities. He has extensive international experience working in Russia, the Far East, Middle East and Canada. Kobak joined Heritage in 2007.

James Baban, general manager, Kurdistan

James Baban has over 30 years’ experience in the upstream oil and gas industry. He is a chartered engineer and a fellow of The Energy Institute in the United Kingdom and has previously worked for Petro-Canada, Burlington Resources, Veba Oil, BP & BG. Baban has extensive skills in the development and management of international offshore and onshore projects, having worked in the Middle East, Far East and North Africa. Baban joined Heritage in 2005.


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Summary financials

Oando Plc Integrated growth with an indigenous advantage



17 November 2008

Oil and gas Nigeria

Report date: 17 November 2008Rating BUYTarget price (comm), NGN 200Target price (pref), NGN n/aCurrent price (comm), NGN 125.28Current price (pref), NGN n/aMktCap, $mn 960.71EV, $mn 1597.71Reuters UNIP.LGBloomberg OANDO NL EquityCommon shares outstanding, mn 989.7 Change from 52 week high: -46.83%Date of 52 week high: 03-Oct-08Change from 52 week low: 95.14%Date of 52 week low 26-Oct-07Web: www.oandoplc.comFree float in $mn 631.19Major shareholder with shareholding 34.3%Average daily traded volume in $mn 1.22Share price performance over the last 1 month -22.61% 3 months -11.59% 12 months %0.566

� We initiate coverage of Oando Plc with a BUY rating and NGN200 target price. Our target price is set at our DCF-derived NAV estimate of NGN200 share that includes value for the refining and marketing division, gas and power, proved plus probable (2P) reserves for the producing Abo Central field on OML 125, and the energy services division. Oando is currently trading with 60% upside to our target price and on 2009 multiples of 6.8x P/CF, 6.9x EV/EBITDA and 9.4x P/E, a significant discount to its peers in the Nigerian petroleum marketing sector. Oando’s implied 2008 dividend yield is 6%.

� Strong growth prospects. Oando is well positioned with: 1) preferential access to upstream resources and services contracts as an indigenous company, 2) production growth in the upstream and strong sustainable revenue growth in gas & power and energy services, 3) plans to monetise a portion of the retail marketing business, 4) high grading of the business mix with growth in higher-margin segments, and 5) the potential to benefit from the privatisation of the Nigeria National Petroleum Corporation (NNPC) and the Nigerian Gas Master Plan (NGMP).

� Indigenous advantage. With its recent expansion into the upstream and energy services, Oando has the opportunity to benefit from preferential access to resources and upstream energy contracts due to its indigenous status. In the near term, we believe Oando is well positioned to expand its presence in the higher margin upstream, services, and gas and power distribution businesses, and has the potential to monetise a portion of the value of the retail marketing business.


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Revenue EBITDA EPS ($)

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Cap Capex Yield

2007 1,504 76 0.07 n/a 21.0 15.3 n/a 45% 112 6% 2008E 3,711 186 0.09 0.13 8.6 11.4 7.9 59% 315 6% 2009E 3,907 233 0.11 0.16 6.9 9.4 6.8 62% 171 8% 2010E 4,068 311 0.18 0.22 5.1 6.0 4.9 58% 136 11%


November 2008 Oando plc Renaissance Capital

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We initiate coverage of Oando Plc with a BUY rating and NGN200 target price. We set our target price at our DCF-derived NAV estimate of NGN200 share, which includes value for refining and marketing, gas and power, proved plus probable (2P) reserves for the producing Abo Central Field on OML 125, and the energy services division.

Oando is a Lagos, Nigeria-based integrated company with an enterprise value of $1,598mn. The company owns the largest retail petroleum products distribution network in Nigeria with over 500 retail outlets and is the 23rd largest company by market cap listed on the NSE. Historically, the major operations of the company have been focused on petroleum marketing, supply and trading in Nigeria, accounting for 100% of operating profit in 1H08. The Oando gas and power division focuses on natural gas distribution to industrial and commercial consumers. It is expected to contribute to group profit in 4Q08 as a result of pricing increases as well as significant capacity growth that is expected to be in place this year.

Oando recently entered the upstream oil and gas business and owns a number of exploration, development and appraisal assets onshore and in shallow water offshore Nigeria. Oando expects to close the acquisition of the company’s first producing asset, OML 125, in 4Q08, with an estimated 3 kbpd of production net to the company in 2009 and an effective date for the acquisition of 1 July 2008. The company has also recently announced first production with a successful appraisal well on OML 56 that flowed at up to 4.6 kbpd.

Oando also has plans to build a greenfield refinery in Nigeria and should benefit from significant growth in the power business within Nigeria as the NGMP is implemented. We note that Nigeria continues to have shockingly low levels of electricity generation, with only around 10% of rural households and 40% of Nigeria’s total population of 140mn having access to electricity.

Our target price of NGN200 per share equates to, 10.9x 2009 and 7.8x 2010 P/CF, 9.3x 2009 and 7.0x 2010 EV/EBITDA, and 15.0x 2009 and 9.6x 2010 P/E. This is relative to the Nigerian petroleum marketing sector that currently trades at 17.68x 2009 EV/EBITDA, and 21.1x 2009 P/E.

We expect the company to have significant growth in EPS with full-year earnings contributions for 2009 and 2010 from 3 kbpd of production at OML 125, further upstream production, as well as the services business with three rigs coming into service in late 2008 and growth in the gas and power segment.

Oando is well positioned for growth with: 1) preferential access to upstream resources and services contracts as an indigenous company, 2) production growth in the upstream and strong sustainable revenue growth in gas and power, and energy services, 3) plans to carve out a portion of the retail marketing business, 4) high-grading of the business mix with growth in the higher margin upstream, services and gas and power segments, and 5) potential to benefit from the privatisation of NNPC and the NGMP.

The major risk to Oando’s growth profile, in our view, is access to financing in the current market that will be key to growing the company’s upstream and services businesses. However, the domestic Nigerian banks continue to be extremely well capitalised and able to lend, after raising $11bn of capital in 2007. As a result, if Oando is not able to access financing in the international market, we believe it is

Investment summary

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Renaissance Capital Oando plc November 2008

likely there will be significant debt capacity available in Nigeria. For example, in Oct 2007, MTN, the largest mobile communications operator in Nigeria, received a $2bn loan from Standard Bank in Nigeria. The syndicated facility was originally expected to be $1.2bn but was increased to $2bn after being oversubscribed.

We believe Oando is uniquely positioned as an indigenous company to benefit from preferential access to upstream resources, particularly as the federal government continues to pursue the indigenisation of oil and gas assets. The services business should prosper due to local content initiatives and low levels of competition from indigenous companies. The specifics of the privatisation of NNPC and restructuring of the oil and gas industry in Nigeria that could occur over the next 12-24 months remain unclear. However, restructuring of these entities may provide additional opportunities for Oando to gain preferential access to resources.

As shown in the table below, Oando is trading at a significant discount to peer multiples. We also note that its Nigerian petroleum marketing peers’ growth prospects are significantly weaker as many of these companies continue to concentrate on expansion of their retail marketing businesses where margins for the industry as a whole are decreasing as a result of increasing competition and costs.

Figure 3: Nigeria, NGN Ticker EV/EBITDA, x P/E, x EPS Dividend yield, % Company NSE Bloomberg Price MktCap,

'000NGN 2007 2008E 2009E 2007 2008E 2009E 2007 2008E 2009E 2007 2008E 2009E African Petroleum AP APET NL 294.0 231,888,142.6 27.38 11.21 8.69 40.67 26.84 22.29 7.23 10.95 13.19 2.38 3.40 4.42 Chevron CHEVRON CHEVRON NL 390.1 99,070,949.3 29.04 23.25 20.76 50.56 38.54 33.72 7.71 10.12 11.57 1.92 2.52 2.88 Conoil CONOIL CONOIL NL 104.9 72,760,879.5 12.58 15.09 8.30 28.09 13.71 13.31 3.73 7.65 7.88 2.62 5.37 5.53 Eterna ETERNAOIL ETERNAOI NL 31.1 15,550,000.0 -228.06 202.01 125.86 270.42 251.41 240.88 0.12 0.12 0.13 0.00 0.00 0.00 Mobil MOBIL MOBIL NL 348.6 83,807,146.7 54.78 50.18 45.65 74.09 34.01 26.16 4.71 10.25 13.32 1.35 2.94 3.82

Oando OANDO OANDO NL 190.0 171,955,591.9 21.02 8.60 6.87 15.29 11.44 21.15 8.18 7.68 8.98 3.18 4.27 4.99 Total TOTAL TOTAL NL 241.6 82,014,894.9 19.72 15.78 13.37 25.19 18.43 16.03 9.59 13.11 15.07 2.65 3.62 4.16

Source: Bloomberg, Renaissance Capital estimates


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Please see the table below for near-term catalysts for Oando.

Nigerian petroleum marketing sector The petroleum marketing business comprises the purchase and distribution of petroleum products to retail and commercial customers.

Traditionally, Oando has been mainly involved in petroleum marketing, supply and trading, with 100% of its operating profit in 1H08 derived from the marketing and supply division.

Regulation, structure and products

The Nigerian petroleum marketing sector is regulated by the Petroleum Products Pricing Regulatory Agency (PPPRA), which is responsible for determining the pricing, supply and distribution of petroleum products in Nigeria.

The major oil products distributed within the country are termed “white products” and consist of premium motor spirit (PMS) otherwise known as gasoline/petrol; automotive gas oil (AGO) or diesel; household kerosene (HHK or DPK) used for cooking and lamp fuel and as jet fuel; and aviation turbine kerosene (ATK) or aviation fuel. Other products include low pour fuel oil (LPFO), liquefied petroleum gas (LPG) or cooking fuel, and lubricants. Pricing of PMS and HKK is government regulated and subsidised.

Based on figures from the 2007 NNPC Annual Statistical Bulletin, total product distribution by major and independent petroleum products marketing companies totalled 11.4bn litres in 2007. As shown in the chart below, PMS accounted for the largest percentage of distributed product at 8.9bn litres, followed by AGO with 1.4bn and DPK with 535.0mn. Total ATK consumption in 2007 was 343.5mn.

The table below illustrates petroleum product consumption in Nigeria.

Near-term catalysts

Figure 4: Oando plc near-term catalysts Activity Expected timing Sale of a minority interest in the marketing business As per market conditions

Increased power prices in the Gas & Power Division Contribution in 4Q08 financials Closing of the OML 125 and 134 acquisitions 4Q08 (effective date July 1, 2008)

Rigs in service Late 2008 Further rig acquisitions Ongoing

Further upstream acquisitions Ongoing Natural Gas Master Plan Ongoing Power sector privatisation medium-term


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Companies operating in the Nigerian petroleum marketing sector can be divided into three distinct groups: 1) major marketing companies, 2) independent petroleum marketers organised under the Independent Petroleum Marketers Association of Nigeria (IPMAN) and 3) NNPC Retail. As shown in the table below, the major marketing companies have the largest product market share, followed by the independent petroleum marketers and then NNPC Retail.

Product pricing and the Petroleum Support Fund (PSF)

The prices of PMS (gasoline/petrol) and DPK (kerosene) are regulated and subsidised with current recommended prices of NGN70 per litre for PMS and NGN50 per litre for DPK. Although there have been persistent concerns about possible retail price increases, the NNPC has provided continued assurance that pricing will remain at current levels. We believe it would be politically untenable for the government to materially raise product prices and that the administration likely views excess profits from upstream royalties as providing funding for the Petroleum Support Fund (PSF).

The PSF was created to stabilise product prices and reduce fuel shortages, beginning on 1 Jan 2006. The PSF is financed by the government and theoretically through accruals realised in periods of ‘over recovery’ when the PPPRA-recommended price is higher than the market determined price.

Figure 6: Petroleum products market share by marketer type

NNPC retail, 3.7%Independent marketers, 27.4%

Major marketers, 68.9%

Source: NNPC

Figure 5: Product consumption in Nigeria, ‘000 litres Product 2006 2007 Change % change Total change 11,625,138.8 11,402,415.5 -222,723.4 -1.953% PMS 8,306,985.0 8,859,802.0 552,817.0 6.240% ATK 284,222.0 343,473.4 59,251.4 17.251% Others 2,675.0 5,443.5 2,768.5 50.859% Special products 231.8 412.0 180.2 43.729% Greases 3,217.0 1,265.0 -1,952.0 -154.302% Brake fluids 2,805.0 35.3 -2,769.8 -7857.447% LPG 23,042.0 6,202.7 -16,839.3 -271.483% Chemicals 33,290.0 16,212.8 -17,077.2 -105.332% Lubricants 113,151.0 92,493.4 -20,657.6 -22.334% LPFO 171,389.0 132,714.1 -38,674.9 -29.142% Bitumen/Asphalt 107,991.0 24,306.8 -83,684.2 -344.283% AGO 1,649,749.0 1,384,956.4 -264,792.6 -19.119% DPK 926,391.0 535,098.1 -391,292.9 -73.125% Sub total 11,625,139.0 11,402,405.5 -222,733.6 -1.953%

Source: NNPC


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For regulated products, the PSF pays petroleum marketers a subsidy when the landing cost of the product is above the approved PPPRA ex-depot price. In this case the difference between the landing cost minus the retail price plus a regulated distribution margin is paid to the petroleum marketer. In theory, if the landing cost plus regulated distribution margin is lower than the regulated retail selling price, petroleum marketers are required to pay into the PSF. Please see below for the PPPRA product pricing templates for PMS and DPK.

Figure 7: PMS pricing template Item $ per tonne NGN per litre C+F 779.370 68.435 Tonne/Liter 1,341 Lightering expenses (SVH) 28.480 2.501 $/NGN 117.75 NPA 10.000 0.878 Financing (SVH) 12.310 1.081 Jetty depot thru-put charge 3.420 0.300 Landing cost 833.580 73.195 Distribution margins (Depot level) Storage charge 34.170 3.000 Pipeline 22.780 2.000 Bridging fund + MTA 45.000 3.951 Admin charge 1.710 0.150 Sub-total 1 103.660 9.102

Distribution margins (Retail level) Retailers 52.400 4.601 Transporters 31.330 2.751 Dealers 19.930 1.750 Sub-total 2 103.660 9.102 Grand total 1,040.900 91.399 Total on website 1,018.120 89.399 Ex Depot 693.72 60.914 (Under)Over recovery -19.399 (Under)Over recovery (based on "proper" grand total) -21.399 Retail price 797.197 70

Source: PPPRA

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We note that when the PSF was originally introduced in 2006 there were long delays to the receipt of payments causing difficulties in working capital management for petroleum marketers. However, this problem has now been rectified.

Petroleum Equalisation Fund (management) board

The Petroleum Equalisation Fund (management) board (PEF) was established in 1973 to equalise the costs of transporting petroleum products from depots to sales outlets to ensure uniform product pricing throughout the country. The Petroleum Equalisation Scheme uses a transport differential zone (TDZ) model where marketers with outlets closer to depots contribute to the fund while marketers with outlets further away receive payments from the fund. White products PMS, AGO and DPK are covered under the scheme.

There are currently 12 depots in Nigeria and therefore 12 depot districts that are then subdivided into TDZ and organised as progressive bands of 50 km radius with the depot as the centre point.

The PEF also administers the Bridging scheme that is designed to minimise the scarcity of petroleum products in those areas of the country experiencing shortages. Bridging refers specifically to trucking petroleum products over a distance of at least 450 km. Bridging is only used in the case when there is a pipeline break or when the refinery that regularly supplies the depot experiencing scarcity is shut down for maintenance. Under this scheme major marketers pay the net amount due to the bridging fund, whereas the independent marketers pay at the lifting point and then submit claims subsequently.

Figure 8: DPK pricing template Item $ per tonne NGN per litre C+F 946.89 90.48 Tonne/Liter 1,232 Lightering expenses (SVH) 26.16 2.50 $/NGN 117.73 NPA 10 0.96 Financing (SVH) 23.65 2.26 Jetty depot thru-put charge 3.14 0.30 Landing cost 1,009.84 96.50 Distribution margins (Depot level) Storage charge 31.4 3.00 Pipeline 20.93 2.00 Bridging fund + MTA 41.34 3.95 Admin charge 1.57 0.15 Sub-total 1 95.24 9.10

Distribution margins (Retail level) Retailers 48.14 4.60 Transporters 28.78 2.75 Dealers 18.31 1.75 Sub-total 2 95.23 9.10 Grand total 1,200.31 114.70 Total on website 1,179.38 112.70 Ex depot 428.02 40.90 (Under)Over recovery (62.70) (Under)Over recovery (based on "proper" grand total) (64.70) Retail price 523.23 50

Source: PPPRA


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Sourcing petroleum products and vertical integration

Petroleum products are sourced by Nigerian petroleum marketers from the NNPC and through third-party importation of petroleum products. Despite producing approximately 2 mmbpd and nameplate refining capacity of 445 kbpd in Nigeria, there is very little product refined in the country. In 2007, only 52 kbpd of oil production was refined in Nigeria, based on figures from the NNPC 2007 Annual Statistical Bulletin. Imported product was approximately 140 kbpd in 2007.

The Pipeline and Products Marketing Company (PPMC), a subsidiary of the NNPC, distributes refined product within Nigeria and imports refined products to meet domestic demand. Access to supply from the PPMC and international sources is key to profitability and volume growth in the petroleum marketing sector.

We also note that the independent marketers have been given priority access to AGO (diesel). As a result, the major petroleum marketers must source the greater majority of diesel product internationally.

Oando petroleum marketing – focus on cost control Oando is the largest petroleum marketing retailer in Nigeria, with over 500 retail outlets in the country. Oando markets PMS (petrol), AGO (auto gas oil), DPK (household kerosene), ATK (aviation turbine kerosene), low pour fuel oil (LPFO), lubricating oils and greases, insecticides, bitumen, chemicals, liquefied petroleum gas (LPG, also known as cooking gas) and Oando insecticide. White products PMS, AGO and DPK comprise the largest portion of Oando’s distributed volumes, with the split of white product volumes year-to-date 76%, 19% and 5% respectively. While pricing for PMS and DPK is regulated and subsidised, pricing for AGO is unregulated and therefore can offer significantly higher potential margins given the dependence of industrial and residential consumers on on-site diesel generators.

Gross profit margins are currently 13.2% YtD with net margins approximately 4.02%. Please see the chart below that illustrates Oando’s market share of distributed petroleum products.

Figure 9: Oando Petroleum products market share (2007)

Mobil, 5.6%

Oando, 20.3% Tex aco, 9.1%Total, 16.1%

NNPC retail, 3.7%

Conoil, 7.6%AP, 10.2%Independent

marketers, 27.4%


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Oando continues to concentrate on cost reductions in the petroleum marketing business. In 2006 it implemented the Branch Project transition in 2006 that resulted in a 10% reduction of operating costs and in 2007 and 2008 modernised its supply chain management using Oracle Enterprise Resource Tool (ERP) software. Oando also established Oando Terminal and Logistics limited to manage the supply chain of the trading, marketing and energy services businesses, and this has resulted in significant cost reductions. The company is also a leader in managing product mix and distribution in the retail business in Nigeria. Net profit margins have increased in 2008 to 4.02% YtD from 2.88% in 2007.

Outside of the retail marketing network, other key petroleum marketing assets owned by Oando include: 1) three aviation fuel depots in Lagos, Abuja and Kano, 2) seven LPG plants, 3) a grease plant in Kaduna, 4) two bitumen plants in Apapa and Port Harcourt with a combined capacity of 12,000mnt, 5) two lubricant blending plants in Kaduna and Apapa with combined capacity of 100,000mnt pa and 6) six petroleum depots in Apapa with 204mn litres of combined capacity.

Oando’s marketing business also operates in Togo, Ghana, Benin and Liberia.

Divesting up to 49% of Oando Marketing Limited

The Oando Group is currently pursuing the divestment of up to 49% of Oando Marketing Limited in the form of a publicly traded carve-out entity listed in Nigeria contingent on suitable market conditions. Funds raised will be redirected to higher-margin businesses such as Oando exploration and production and Oando gas and power. We believe a 49% stake in Oando Marketing could be sold for up to $250-300mn. We understand the sale of this business has been underwritten in the local market by a syndicate of Nigerian banks.

Oando Supply & Trading

The JV’s business activities are comprised of export and import of petroleum products and the trading of refined and unrefined petroleum products to refiners, marketing companies worldwide and other trading companies. Within Nigeria, Oando Supply & Trading trades cargoes with the Products and Pipelines Marketing Company (PPMC), the major oil marketers in Nigeria and the independent marketers. The division also provides tanker-chartering services with primary routes within West Africa and Nigerian coastal waters, Central African coastal waters and the Mediterranean.

Oando Supply & Trading actively makes markets in financial and physical products in oil trading, with contracts ranging from spot to term.

Revenues in the trading business have continued to rise over the past three years with Oando the indigenous trading company of choice for a number of petroleum marketing companies including NNPC.


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Oando Gas & Power to benefit from the NGMP and power sector privatisation The gas and power subsidiary supplies natural gas to industrial, residential and commercial customers. The division is comprised of Gaslink Nigeria Limited, Gaslink Ghana, Gaslink Togo, Gaslink Benin, East Horizon Gas Company Limited and Gas Networks Services Limited.

Gaslink Nigeria Limited operates under a 20-year gas sale and purchase agreement with the Nigeria Gas Company to distribute natural gas to industrial residential and commercial consumers.

Gaslink Nigeria operates a 99.4 km pipeline network from the Nigerian Gas Company (NGC) City Gate to cover Ikeja and other industrial areas around the city of Lagos, the largest city in Nigeria with a population of 14mn people. The current distribution network has capacity to deliver 70 mmcf per month. The expansion of the Lagos third phase gas pipeline project is expected to be completed and at full capacity in 1Q09. Gaslink Nigeria also provides services to natural gas consumers such as project management, front-end engineering and design, pipeline construction and consultancy services.

The East Horizon Gas Company (EHGC) will supply natural gas to the United Cement Company of Nigeria Limited (UNICEM) located in Calabar, Cross Rivers State. UNICEM is a joint venture between Flour Mills Nigeria, Orascom Industries and Holcim International to build a $350mn cement plant with production capacity of 2.5mnt pa. The federal government and NNPC have given approval for the gas supply project on a build operate and transfer (BOT) basis with the Nigerian Gas Company. Oando is planning to build a gas supply line from the Obigbo-ALSCON pipeline at Ukanafun to the plant at Mfamosing. The 18-inch diameter pipeline will be 124 km long, built in land, swamp and water and construction is expected to be completed in 4Q08. The pipeline will supply 22 mmcf per day initially, increasing to 50 mmcf per day in the third year of operation.

The company is also developing a 12 MW plant to power the Lagos Water Corporation’s major water works that is expected to be onstream in 3Q09. This will be the company’s first private power station.

The NGMP was announced in May 2008 with the aim of fully exploiting the natural gas resources in the country, estimated at 182 tcf, in pursuit of the federal government’s 10% GDP growth aspirations. The plan includes an integrated infrastructure strategy to support domestic, regional and export LNG markets. The gas and power business has potential for significant growth, as there are currently no operational gas-fired power stations in Nigeria and there is potential to grow to 15 GW of capacity by 2012 based on NNPC estimates. This level of capacity generation is extremely unlikely to be built in this timeframe, however clearly there is a significant opportunity to capitalise on the development of the Nigerian power grid once the appropriate framework is created to monetise upstream natural gas resources. We continue to expect significant economic growth in Nigeria of 8% non-oil GDP pa.

There is significant scope for Oando to grow the gas and power business given the power sector liberalisation that is ongoing in Nigeria. The Nigerian electricity supply sector is currently dominated by the state-owned Power Holding Company of

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Nigeria (PHCN) that is expected to be privatised under the Electric Power Sector Reform Act (EPSRA).

Oando has also incorporated subsidiaries in Ghana, Togo and Benin to take advantage of gas distribution opportunities surrounding the West African Gas Pipeline (WAGP).

Oando E&P– acquisition of OML 125 provides producing asset, expect further upstream acquisitions

Oando originally announced the purchase of a 49.81% stake in OML 125 and OML 134 from Royal Dutch Shell on 25 Feb for $625mn. Agip (ENI), owner of a 51.19% interest in the licences then exercised pre-emption rights to match Oando’s offer. Subsequently, Agip sold a 15% interest in the licences to Oando and an additional 15% interest in the licences to private company Allied Energy Resources.

In Sep 2008, the Nigerian senate recommended Oando be awarded the full 49.81% interest in OML 125 and OML 134, ruling that Oando’s original agreement with Shell was binding and that ministerial consent was not given for the pre-emption agreement between Shell and AGIP. Additionally, the Senate stated that the use of pre-emption rights in joint operating agreements (JOA) against Nigerians and companies controlled by Nigerians should be abolished. It is uncertain as to what percentage stake Oando will ultimately be granted at this stage, however we do not believe that the government will revoke AGIP’s pre-emption right given the implications for continued international investment in the Nigerian oil and gas industry. Our financial forecasts reflect Oando holding a 15% stake in OML 125 and OML 134 from 1 July 2008, the effective date of the transaction.

OML 125 is located in the deepwater offshore northwest Nigeria and is expected to produce approximately 20 kbpd gross in 2009 from the Abo Central development, or 3 kbpd net to Oando. Based on figures from Wood Mackenzie, OML 125 contained remaining recoverable reserves of 41 mmbbl of oil at Abo Central as at 1 Jan 2008. Abo North, also located on OML 125 but for which there is currently no development plan, is estimated to contain remaining recoverable reserves of 40 mmbbl. The Abo North Field could be developed as a satellite to Abo Central, however its economics are likely to be marginal given current drilling costs and subsea contracts. Additionally, this is unlikely to rank highly in ENI’s (operator) potential development portfolio.

Please see the map below for the location of OML 125.


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Transaction metrics for the acquisition equate to $63,000 per daily flowing barrel and $31 per barrel of recoverable reserves from the Abo Central development on OML 125. We believe that Oando has paid full value for this acquisition.

Oando has also recently announced a positive appraisal well at OML 56 with flow rates of up to 4.6 kbpd.

We expect Oando to continue to pursue further upstream acquisitions in Nigeria. Please see the table below that illustrates Oando’s current upstream asset position.

Oando owns interests in a number of additional non-producing licences in Nigeria as shown in the table below.

Figure 10: Location of OML 125


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Please see the board of directors and senior managers section below for profiles of senior management in the Oando exploration and production division.

Oando Energy Services – local content policies will provide continued benefits

Oando Energy Services provides oilfield services to upstream companies operating in Nigeria including rigs, drilling fluids, drill bits and oil well cement services. The Nigerian government has set a local content target of 70% for the oil and gas industry to be achieved by 2010.

The company owns three swamp rigs (inland barges), the Searex 6 and Searex 12 as well as the Constitution, that operate in the Niger Delta.

The Searex rigs were purchased for $150mn and will be managed in partnership with Frazimex (indigenous company), with technical assistance provided by Transocean. Both the Searex rigs have a water depth rating of 25 ft and drilling depth of 25,000 ft. The Searex 6 and Searex 12 are expected to be contracted out at day rates in the range of $85,000 when they begin service in late 2008. Swamp rigs are in significant demand in the Niger Delta with the majors forced to purchase rigs in recent years.

Oando intends to aggressively increase the number of land and swamp rigs the company owns with $100-120mn of capital spending earmarked for rigs in 2009 and a total of $500mn to be spent on rig acquisitions by 2012.

Current Energy Services clients include Addax, Chevron, Nigerian Agip Oil Company, Mart Resources, Shell Nigerian Exploration and Production Company (SNEPCO), Pan Ocean, TOTAL, Emerald and ExxonMobil. Oando also has a technical support agreement with Halliburton for mud services.

Indigenous advantage means Oando is unlikely to be acquired

We believe Oando is unlikely to be acquired for four main reasons: 1) the enterprise value of the company is similar to domestic competitors in the petroleum marketing space, 2) international integrateds are trading at lower multiples and are not interested in the marketing and services business that comprise a significant portion of Oando forecast revenues, 3) the government would likely block an acquisition by an international company given indigenisation efforts and local content initiatives,

Figure 11: Oando E&P assets License Area, '000 km2 Interest, % Operator Gross production Gross 2P oil reserves Status Location OML 125 1,220 15 / 49.81* Agip 20 kbpd 41 mmbbls** Production Deepwater Niger Delta OML 134 1,187 15 / 49.81* Agip Non-producing 20 mmbbls*** Appraisal Deepwater Niger Delta Akepo Marginal Field OML 90 26 30 Sogenal Non-producing 15.3 mmbbls Appraisal Shallow Offshore,

Delta State, Niger Delta Obodeti/Obodugwa Marginal Field OML 56 68.5 45% Energia Non-producing 25 mmbbls Appraisal Onshore Delta State, Niger Delta

OPL 236 1,650 52.25 Oando Non-producing 480 mmbbls Exploration & Appraisal Onshore Akwa Ibom State, Niger Delta

OPL 278 91.86 60 Oando Non-producing 75 mmbls Exploration & Appraisal Swamp and shallow offshore, Bayelsa State, Niger Delta

OPL 282 699 Participating LCV interest NAOC (Agip) Non-producing TBA by NAOC Exploration Onshore Bayelsa State, Niger Delta

* Senate has recommended Oando receive 49.81%. ** Wood Mackenzie estimates for Abo Central only *** Wood Mackenzie technical recoverable reserves. Technical recoverable natural gas reserves of 300 bcf



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and 4) an international company acquiring Oando would likely lose preferential access to resources and assets and local content qualifications in Nigeria, thus destroying value. Additionally, management owns 34.27% of Oando and said it is not interested in selling the company.

Oando refining

Oando is currently evaluating the development of a greenfield refinery in the Lekki Export Processing Zone (EPZ) with capacity of 360 kbpd and has commenced front end engineering and design that it expects to complete in 1Q09. We would not expect Oando to break ground for construction of a refinery for another three years. Oando is also considering an acquisition of a significant stake in a medium-sized refinery in West Africa.

While Nigeria currently has four refineries (Port Harcourt I & II, Warri and Kaduna) with combined nameplate capacity of 445 kbpd, the refineries remain underutilised, operating at approximately 10% of capacity in 2007. While the government has attempted to privatise refineries in the past, this remains a sensitive political issue. Oando participated in more than two privatisation attempts by the government of refining assets that were unsuccessful.

Clearly there is a significant opportunity for first-mover refiners in Nigeria to benefit from significant refining margins, however it is difficult to have any visibility on the potential timing of this development.

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Please see the table below for the capital structure of Oando as at the end of 2Q08.

Balance sheet, capital expenditures, hedging and future funding needs Oando estimates 2008 capex at $163mn and up to $360mn in 2009, although approximately $120mn of this amount is discretionary spend on the acquisition of further rigs.

We expect the company to be able to fund its current expected capex programme with operating cash flow of $107.3m expected in 2009 and proceeds of $250mn expected from the sale of up to 49% of the marketing business.

Capital structure

Figure 12: Oando capital structure as at 30 June 2008 Share structure Amount Basic shares 904,884,652 Sources of capital Amount, $mn Long-term debt 748

Cash & cash equivalents 525 Shareholders' equity 376



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We value Oando Plc using a DCF-derived NAV methodology that includes value for refining and marketing, Gas & Power, recoverable reserves for producing assets on OML 125, and the energy services division.

Our target price of NGN200 per share equates to, 10.9x 2009 and 7.8x 2010 P/CF, 9.3x 2009 and 7.0x 2010 EV/EBITDA, and 15.0x 2009 and 9.6x 2010 P/E. This is relative to the Nigerian petroleum marketing sector that currently trades at 17.68x 2009 EV/EBITDA, and 21.1x 2009 P/E.

Valuation

Figure 13: Oando - net asset valuation summary NAV, NAV, Per % of value Upstream current production and development $mn NGNmn share, NGN share

OML 125 & OML 134 188 22050 24.37 9% Production & development asset value 188 22050 24.37 9%

Other upstream interests

Other upstream interests at book value 36 4212 4.65 2% Other upstream asset value 36 4212 4.65 2%

Refining & marketing

Refining & marketing 1263 147827 163.36 57% Refining & marketing asset value 1263 147827 163.36 57%

Gas & power

Gas & power 627 73413 81.13 28% Gas & power asset value 627 73413 81.13 28%

Services

Services 204 11000 12.16 4% Services asset value 204 11000 12.16 4%

Total 2320 271384 285.67 100%

Liabilities

Long-term debt 730 85412 94.39 -46% Less cash 93 10852 11.99 6% Net debt 637 74560 82.40 -41% Current net asset value 1682 196824 203.28


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Major risks for Oando include civil unrest in Nigeria that could and has impacted the supply of and demand for petroleum products in the marketing division; potential removal of petroleum subsidies or delays to or non-payment of petroleum product subsidies from the government; governmental or business corruption; and uncertainty regarding interpretation and application of foreign laws and regulations and expropriation of assets.

Additional risks include militant activity that could impact production volumes and the value of rigs operating in the Niger Delta; cargo losses; government rulings regarding gas sales; gas supply reliability and volatility of oil and gas prices that can create significant risk in the company’s supply and trading operations; and financing risk is also apparent in the current environment.

Risks inherent in the global oil and gas business include volatility of oil and natural gas pricing, currency risk, cost inflation of materials and services, geological risk, operating hazards, access to supplies and equipment, access to drilling rigs and experienced trades, geopolitical risk, and unforeseen weather conditions that can affect drilling programmes.

Other risks include potential changes to existing royalty regime, regulatory environments, political regimes and environmental considerations.

Key risks


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Please see the historical event chart for Oando below.

In 1956 the company commenced operations as a petroleum marketing company operating as ESSO West Africa Incorporated, a subsidiary of Exxon. In 1976, the company was nationalised and rebranded Unipetrol Nigeria Ltd. On 1 Mar 1991, Unipetrol became a public company and 60% of the company was sold to the public. In 1994, Ocean and Oil Services Ltd was formed to supply and trade oil products in Nigeria, and Ocean and Oil Ltd was formed to supply and trade oil products globally. In 1999, the company acquired 40% of the equity in Gaslink Nigeria Ltd and then increased this stake to 51% in 2001.

In 2000 the company was fully privatised following the sale of the federal government’s remaining 40% shareholding in the company. Under the privatisation process, 30% of the company was sold to core investors Ocean and Oil Investments Ltd and the remaining 10% to the Nigerian public. In Dec 2002, Oando merged with Agip Nigeria Plc following its acquisition of 60% of Agip Petroli’s stake of Agip Nigeria Plc in Aug 2002. The company name was changed to Oando in Dec 2003. Oando Energy Services was incorporated in 2005.

Company background

Figure 14: Oando plc event chart — company history

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25 Feb 2008: Oando acquires 49.8% stake from Shell in two oil blocks in Nigeria, OML 125 and OML 134

7 Aug 2008: Announces appointment of Omamofe Boy o and Lara Banjoko as CEO and COO of Oando Marketing

20 Nov 2007: Oando announces plans to partner w ith Lagos State Government on various energy projects to be implemented over the nex t four years at an estimated cost of $2.5bn

10 Aug 2007: Oando Marketing launches first-ever Back Loading operation in Nigeria

6 June 2007: Announces acquisition of minority interest in certain subsidiaries and reorganisation of marketing business

7 Feb 2008: Oando Energy Serv ices acquires two swamp rigs for upstream operations in the Niger-Delta area

25 Nov 2005: Oando commences trading on the JSE under the ticker OAO

22 Dec 2004: Kamar Bakrin appointed COO

7 May 2004: Unipetrol Ghana Limited changes its name to Oando in Ghana

6 Aug 2004: Receives approval from shareholders to raise NGN5bn from the capital market

30 Apr 2006: Oando announces appointment Kamar Bakrin as MD/CEO of Oando Energy Serv ices and Dimeji Edwards as MD/CEO of Oando Supply and Trading

17 Apr 2008: Oando signs PSC and GMoU over OPL236 in Nigeria



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Board of directors and senior management profiles Major General M. Magoro (retired) PSC OFR Galadiman Zuru, chairman

Major General Magoro has held several positions in the Nigerian government including federal commissioner of transport during the military administration in 1978. In 1984/85 he served as minister of internal affairs. He was also a member of the supreme military council. He served in the highest capacity in each of the National Shipping Line, the Nigerian Railways and Nigerian Ports Authority. After his retirement in 1995, he took to public service and thereafter became chairman of Ocean and Oil Services Ltd. He is also a director of several other companies and a member of the PDP board of trustees.

Jubril Adewale Tinubu, group chief executive

Tinubu assumed the position of Group CEO in Jan 2005 after the consolidation of Oando’s affiliate and subsidiary companies into the Oando Group. Prior to this, Tinubu was MD/CEO of Oando Plc, a position he assumed in July 2001 after serving as the company’s executive director for finance and administration. Upon graduation, Tinubu started his career with the family's law firm, K.O. Tinubu & Co where he worked on corporate and petroleum law assignments. In 1994, he became one of the founding partners of the Ocean and Oil Group. While at Ocean and Oil, Wale was responsible for the strategic expansion of the business.

Tinubu has a bachelor’s degree in law from the University of Liverpool, and a master’s degree in law from the London School of Economics where he specialised in international finance and shipping. He is also a member of the Nigerian Bar Association.

He is the chairman of Gaslink Nigeria Ltd, Oando Supply & Trading, Oando Power, Oando Energy Services, Oando Exploration and Production, Ocean and Oil Holdings Ltd, Oando Ghana, Oando Togo, Oando Sierra Leone, Tilca Nigeria Ltd and Trojan Estates Ltd. He is a member of the 7th Governing Council for Lagos State University and the Institute of Directors of Nigeria and was selected as a Young Global Leader (Business) for 2007 by the World Economic Forum.

Omamofe Boyo, deputy group CEO

Boyo assumed his position in July 2001 having previously been executive director of marketing for Oando Plc. He is also MD/CEO of Oando Supply & Trading.

In 1991, he started his career with F.R.A Williams and Co, a prominent law firm in Nigeria where he worked for four years. While at F.R.A Williams and Co., Boyo specialised in the shipping and oil services industries and worked on various joint venture deals between NNPC and major international oil companies. He was also a member of the team that represented the refineries in the NNPC judicial enquiry. In 1994, he joined the Ocean and Oil Group where he developed and managed the operations department.

Boyo has a bachelor’s degree in law from Kings College, University of London, England. He is also a member of the Nigerian Bar Association. He serves on the board of Gaslink Nigeria Ltd., Oando Plc Togo, Oando Plc Ghana, West African Refinery Company (WARCO) Sierra Leone, Stallion Properties and Ocean and Oil Services.


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Bolaji Osunsanya, MD/CEO, Oando Gas & Power

Osunsanya joined Unipetrol Nig Plc in Aug 2001 as head of lubes and specialties where he was responsible for product coordination and later sales of lubricants, bitumen, chemicals, LPG and aviation fuels. In July 2004, he became chief marketing officer and had responsibility for national commercial sales. Before joining Oando Plc, he was executive director, marketing in Access Bank Nigeria Ltd. He also spent several years in Guaranty Trust Bank where he rose to the position of assistant general manager/head of local corporate group of institutional banking. In his role as Managing Director of Oando Gas & Power, Osunsanya will oversee the company’s pipeline expansion programme, the independent power plant project as well as other projects in the West African sub-region. A. Akinrele (SAN), non-executive director.

Ademola Akinrele is a partner at F.O. Akinrele & Co. and joined the Oando board in July 2002. He has a law degree from University College, London. He is a member of the Nigerian Bar Association, a Senior Advocate of Nigeria and a Fellow of the UK Chartered Institute of Arbitrators. Akinrele has written various law books including The Summary Judgment, The Domestic Forum of a University, Foreign Exchange Legislation in Nigeria and Can Nigeria Grant Judgment in Foreign Currency.

Prince Felix Ndamati Atako, non-executive director

Prince Felix Ndamati Atako is CEO of Fendant Nigeria Ltd. Prince Atako joined the Oando Plc board in Mar 2000. He also serves on the boards of M.W.S. Atako & Sons Ltd., Rivers Gulf Fisheries Ltd and Pan African Bank Ltd. He is also a member of the Nigerian Stock Exchange and Port Harcourt Golf Club. He has a bachelor’s degree in business administration and a master's degree in business administration, finance and investment from Baruch College, City University of New York.

Navaid Burney, non-executive director

Burney is the managing director of Emerging Capital Partners (ECP), a leading Africa-focused private equity fund manager. Burney joined ECP in Sep 2000 from First Merchant Bank of Zimbabwe where he had been general manager of investment banking since 1997. From 1993 to 1997, he was senior investment officer with the International Finance Corporation (IFC) where he focused on mining finance, completed transactions and provided advisory services in Chile, Venezuela, Peru, Sierra Leone, Zimbabwe and Gabon. Prior to joining the IFC, Burney was an associate manager with Union Carbide Corporation’s treasury department and had international banking experience from assignments in New York, Paris and Abu Dhabi. Burney serves on the boards of Starcomms Plc, Notore Ltd, Ocean & Oil Investments Ltd, Touch the Wild (Pty) Ltd and De Rust Olive Estates (Pty) Ltd, among others. Burney holds a BS in international economics from Georgetown University and an MBA in finance and accounting from the University of California at Berkeley.

His Royal Majesty M.A Gbadebo, non-executive director

HRM Gbadebo is the Alake (King) of Egba Land in Nigeria. HRM Gbadebo joined the board of Oando Plc in Apr 2006. Prior to his coronation as the Alake of Egbaland in 2005, HRM had a successful career in the Nigerian army culminating in his


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appointment as a principal staff officer, Supreme Headquarters from Jan 1984 - Sep 1985. He holds a BA and a post graduate diploma from the premier university in Nigeria: University of Ibadan. He was also awarded military honours such as the National Service Medal the Defence Service Medal and the Forces Service Star Medal. He has served on the boards of several companies including Ocean and Oil Services Ltd and Global Haulage Resources Ltd.

Oboden Ibru, non-executive director

Ibru is executive director, Oceanic Bank International (Nigeria) Limited, a position he has held since Apr 2004. Oboden holds a bachelor’s degree in finance and a BSc in decision sciences, both from the University of San Francisco. He also has an MBA from the International Graduate School of Management (IESE) Navarra, Spain. He is a member of the Chartered Institute of Bankers of Nigeria and the Nigerian Economic Summit Group. He also serves on the board of several institutions/organisations, including Elf Oil Nigeria Limited (prior to the merger with Total), Aerocontractors Company of Nigeria Limited, Money Market Association of Nigeria and Minet Insurance Brokers.

Alhaji Hamid Mahmud, non-executive director

Mahmud joined the board of Oando in Nov 2000. Mahmud established his own law firm, Hamid Mahmud and Co. in 1984. He has served as a member of the board of Gongola State Broadcasting Corporation where he was appointed a member of the Gongola State Executive Council and later elected a senator. He has a bachelor’s degree in law from the Ahmadu Bello University Zaria. He is also a member of the Nigerian Bar Association.

Paul Okoloko, Director

Okoloko served as MD/CEO of Oando Energy Services. He completed his bachelor’s degree in economics from the University of Benin, Nigeria in 1986. As founding member of the Ocean and Oil Group, he became MD/CEO of Ocean and Oil Services Ltd in 2001. I. Osakwe, non-executive director

Osakwe is a qualified chartered accountant for England and Wales. Osakwe joined the board of Oando in Mar 2000. He serves on the board of Thomas Wyatt Nig. Ltd and FedEx (Red Star Express) Ltd. He was also chairman of UBA Trustees Ltd from 1994 to 1996. Osakwe has bachelor’s and master’s degrees in chemistry from Oxford University.

Oredeji Delano, group company secretary and compliance officer

Prior to joining Oando, Delano worked at Chief Rotimi Williams Chambers until 1995, rising to senior counsel. From there, she worked as head of chambers at Akin Delano Legal Practitioners until Feb 1997. She then joined George Etomi & Partners as head of the litigation and telecommunications department, Lagos. Delano holds a law degree from Lansdowne College, London in 1985. She completed her law degree at the Nigerian Law School in 1986.


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Oando exploration and production management profiles Babatunde Ogunnaike, MD/CEO Oando Exploration and Production

Ogunnaike joined Shell Petroleum Development Company (SPDC) in 1978 as a wellsite petroleum engineer. He later became head of business planning and economics and in 1993 was appointed senior economics engineer with Shell Expro in London. He returned to SPDC in 1996 as head of production planning, programming and information services and served variously in the corporate planning, petroleum engineering and technical services departments before his appointment as commercial operations manager in 2005. He was appointed general manager, joint venture management in 2006, a position he held till May 2008.

Eamon Labode Akinosho, chief operating officer/executive director, upstream

Akinosho has more than 20 years’ E&P experience including eight years at Anadarko Petroleum where he worked variously as production engineer, reservoir engineer and head of production for Andarko’s Algerian field (Hassi Berkine North Field) overseeing a rise in production to 300,000 bpd and five years at BP/Amoco UK where he worked variously as operations engineer and well operations engineer in charge of all the southern North Sea wells. He has also acted as a technical consultant for Sahara Energy Field Company, an indigenous Nigerian company. Labode holds an MSc in petroleum engineering from Imperial College, University of London, as well as an MSc in offshore engineering from Robert Gordon University, Aberdeen. He also holds a diploma in business administration from Edinburgh Business School, Heriot Watt University.

Billi Folahan, senior executive

Folahan has extensive experience in the upstream sector of the oil and gas industry, including a decade and a half with Chevron where he worked as an exploration geologist and as a lead wellsite geologist. He also worked for Sadiq and Cavendish Petroleum where his duties included the evaluation of potential exploration opportunities for investment, the evaluation of E&P acreage and liaison with government agencies on various upstream matters. Folahan holds an MSc in geology which he obtained from the Tenessee Technological University and an MSc in rock mechanics from Tennessee State University.

�

Mart Resources Deep value in marginal field pure play



17 November 2008

Oil and gas Africa

Report date: 17 November 2008Rating HOLDTarget price (comm), CAD 0.350Target price (pref), CAD n/aCurrent price (comm), CAD 0.065Current price (pref), CAD n/aMktCap, $mn 20.2EV, $mn 52.0Reuters LKOH.MMBloomberg LKOH RM EquityCommon shares outstanding, mn 367.7Change from 52 week high: -92.41%Date of 52 week high: 15/05/2008Change from 52 week low: 9.09%Date of 52 week low 24/10/2008Web: www.martresources.comFree float in $mn 20.2Major shareholder with shareholding

n/a

Average daily traded volume in $mn 0.02Share price performance over the last 1 month -33.33% 3 months -75.00% 12 months -88.68%

� We initiate coverage of Mart Resources with a HOLD rating and a CAD0.35/share target price. Our target price is based on our DCF valuation, which produced an asset-plus-rigs NAV estimate of CAD0.35/share. This includes proved plus probable (2P) reserves for producing assets at Umusadege and the value of the company’s rigs at book value. Our total company NAV is CAD0.96/share, which includes additional risked value for probable and possible reserves at Qua Ibo and Umusadege, and risked prospective resources at Ke. Mart Resources is currently trading at 7% of our NAV and at a significant multiple discount to its African and global E&P peers at 0.9 times P/CF, 1.16 EV/EBITDA and $2.02/bbl of 2P reserves, on our estimates.

� Mart offers: 1) Deep value trading at less than 10% of our NAV estimate and at 0.9 our estimate of 2009 cash flow; 2) potential for 2009 production growth of 50% with further success at Umusadege; 3) potential for a local financing advantage given the current liquidity in the Nigerian banking system although financing remains a key risk for the company’s growth plans; and 4) potential M&A or take-private potential with the company trading at a significant discount to NAV and as an attractive asset package for entry into Nigeria.

� M&A/privatisation likely required to realise value. While our analysis indicates that the company is considerably undervalued, we believe that it is likely that Mart would have to be acquired or privatised for investors to realise value in the near term. Based on our estimates, we forecast that Mart will be earnings and cash flow positive in 2H08 and 2009, based on our $70/bbl Brent price forecast.

Figure 1: Price performance – 52 weeks Figure 2: Sector stock performance

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2007 0.00 -10.42 -0.10 -0.06 N/M N/M N/M 3% N/A 100% N/A 0% 2008E 69.81 26.92 -0.04 0.00 2.30 N/M 13.06 20% 2.44 159% N/A 0% 2009E 104.94 53.42 0.03 0.07 1.16 2.14 0.87 27% 3.50 159% 100 0% 2010E 91.68 51.53 0.04 0.07 1.20 1.61 0.87 27% 2.53 120% 100 0%


November 2008 Mart Resources Renaissance Capital

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We initiate coverage of Mart Resources with a HOLD rating and a CAD0.35/share target price. Our target price is based on our DCF valuation, which produced an asset-plus-rigs NAV estimate of CAD0.35/share. This includes proved plus probable (2P) reserves for producing assets at Umusadege and the value of the company’s rigs at book value. Our total company NAV is CAD0.96/share, which includes additional risked value for probable and possible reserves at Qua Ibo and Umusadege, and risked prospective resources at Ke.

Our target price equates to 4.7x 2009 and 4.7x 2010 P/CF, 3.1x 2009 and 3.3x 2010 EV/EBITDA, 11.5x 2009 and 8.64x 2010 P/E, $60,126 per daily 2009 flowing barrel and $5.45/2P bbl (excluding natural gas), on our estimates.

Mart Resources is a Calgary-based exploration and production company with Nigerian offices in Lagos and Port Harcourt and an enterprise value of CAD52mn. Upstream, the company is focused on developing proven undeveloped assets in the marginal fields of the Niger Delta through partnerships and agreements with indigenous companies. All of the company’s upstream assets are located in Nigeria with Mart’s first production in Apr 2008 at Umusadege (OML 56) and ongoing further development potential on the block, appraisal and development assets at Qua Ibo (OML 13) and exploration at Ke (OML 55). Longer term, the company may pursue acquisitions of properties throughout West Africa as well as larger producing and undeveloped properties in Nigeria. Mart also owns and operates two onshore drilling rigs. The map below illustrates the location of Mart Resources’ upstream interests in Nigeria.

Investment summary

Figure 3: Mart Resources licence areas


Renaissance Capital Mart Resources November 2008

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Production for the company is currently solely derived from the Umusadege Field and is 100% oil weighted. As of the last reserve report prepared by Chapman Petroleum Engineering (31 Dec 2007), reserves consisted of total net proved reserves of 1.351 mmbbl, all attributed to the Umusadege Field, proved plus probable (2P) reserves of 25.8 mmbbl and proved plus probable plus possible reserves (3P) of 50.0 mmbbl. All of Mart’s reserves are light and medium oil.

Mart offers a combination of: 1) deep value trading at less than 10% of our NAV estimate and at less than 1.0x our estimate of 2009 cash flow; 2) potential for 2009 production growth of 50% with further success at Umusadege; 3) potential for a local financing advantage given the current liquidity in the Nigerian banking system although financing remains a key risk for the company’s growth plans; and 4) potential M&A or take-private potential with the company trading at a significant discount to NAV and as an attractive asset package for entry into Nigeria.

While our analysis indicates that the company is considerably undervalued, we believe that it is likely that Mart would have to be acquired or privatised for investors to realise value in the near term. Based on our estimates, we forecast that Mart will be earnings and cash flow positive in 2H08 and 2009, based on our $70/bbl Brent price forecast.

The major risk for Mart Resources and the company’s growth profile, in our view, is access to financing in the current market. However, the domestic Nigerian banks continue to be well capitalised and able to lend after raising $11bn of capital in 2007. As a result we believe Mart is likely to have access to local financing in Nigeria and already has a local debt facility with Bank PhB plc that is secured by Mart’s 101 drilling rig.

On our estimates, the company is currently trading at 0.87 2009 and 0.87 2010 P/CF, 1.16x 2009 and 1.20x 2010 EV/EBITDA, 2.14x 2009 and 1.61x 2010 P/E, $22,444 per daily flowing barrel and $2.02/2P bbl (excluding natural gas). This is compared with global E&P peers, which are trading at 4.2x 2009E and 3,76x 2010E P/CF, 3,51x 2009E and 3,12x 2010E EV/EBIDA, 7,80x 2009E and 5,49x 2010E P/E, $60,336 per daily flowing barrel and $13.41/2P boe.


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First production and potential ramp up at Umusadege Production at Umusadege commenced in Apr 2008 from the Umu-1 well (re-entry) producing from the XIIa and XIIb zones at 7,861 and 7,936 ft respectively. The Umu-3 well (re-entry) was brought on-stream in July this year with total volumes from the block now above 2.8 kbpd. The Umusadege Field is located on OML 56 in the North Central Niger Delta with net proved reserves to Mart as at 31 Dec 2007 of 1,351 mmbbl, proved plus probable reserves (2P) of 8,807 mmbbl and total 3P reserves of 20,915 mmbbl. Please see the map in Figure 5 for the location of the Umusadege Field.

Drilling of the Umu-5 twin well located 500 feet from the Umu-1 well commenced in July 2008. This well is targeting production from the additional oil reservoirs of the 11 hydrocarbon zones identified by the Umu-1 well logs above the XIIa and XIIb zones. The well has experienced delays as a result of significant sand caving that has created mechanical problems and drilling equipment issues. Mart expects this to

Near-term catalysts

Figure 5: Mart Resources - Umusadege Field


Figure 4: Mart Resources near-term catalysts Activity Expected timing Continuing production ramp-up and drilling at Umusadege Ongoing Drilling results at Qua Ibo 4Q08/1Q09

Secure further financing from local Nigerian banks 4Q8/1Q09 Commence drilling at Ke 1Q09

Potential farm-outs at Qua ibo and Ke Ongoing Source: Company data, Renaissance Capital estimates

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delay drilling by three weeks. The company intends to drill additional development wells on the block following Umu-5.

Early production facilities with capacity of up to 10 kbpd have been installed on the Umusadege Field with crude from the field being transported via pipeline to AGIP’s Brass River Terminal.

Mart signed finance and production sharing agreements with indigenous companies Midwestern (operator) and Suntrust in April and May of 2006. Under these agreements the company is entitled to receive a share of oil production prior to and post payout. Mart funds all capital costs in exchange for a share of production on a sliding scale, beginning with an accelerated repayment of costs that moves to a stepped-down schedule after the recovery of capital costs.

The Umusadege Field was originally discovered with the Umu-1 well by Elf in 1974, subsequent to which two appraisal wells were drilled. The field contains 16 oil-bearing reservoirs of 6,500-9,500 ft with blended API quality of 30-35°.

We note that the Umusadege-4 development well, drilled in 2006 to a depth of 8,818 ft, encountered thin net oil pay of 15 ft and was suspended for possible use as a sidetrack. The net pay encountered in the well is believed to represent the edge of a potentially significantly thicker pay zone to the south-east based on 3D seismic interpretation.

Probable and possible upside at Qua Ibo There is currently no production at Qua Ibo, although as at 31 Dec 2007 the field had probable reserves of 16,980 mmbbl and probable and possible reserves of 29,073 mmbbl. Please see the map in Figure 6 for the location of the Qua Ibo Field.


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Mart and Network Exploration and Production, an indigenous company, have recently resolved a contractual dispute regarding Mart’s rights in the Qua Ibo Field and it began drilling the Qua Ibo-3 well on the block in September. This well is an appraisal well to assess the D5 oil reservoir between the Qua Ibo-1 and Qua Ibo-2 wells and Mart expects it to be drilled to 9,900 ft (7,400 ft vertical depth). Mart has communicated that it expected the well to be completed in October and will be followed with a test if successful.

If successful, we expect that an early production facility and 1.5 km pipeline to the ExxonMobil Qua Ibo terminal could be installed. A field development plan and environmental impact assessment have been approved for the field.

This field could produce up to 4 kbpd in 2009, net to Mart, with net peak production of approximately 7 kbpd.

Mart entered into a finance and technical-services agreement with Network Exploration and Production in Mar 2005. Under the terms of the contract, Mart provides the capital for the development of the two main reservoirs in the field in return for a share of production from those reservoirs. Further capital required for the development of other reservoirs on the field will be provided jointly by Mart and Network. Mart will receive its share of production on a sliding scale, beginning with an accelerated repayment of costs contributed to the project and moving to a stepped-down schedule based on the aggregate production volume after the recovery of capital costs.

The Qua Ibo field and Qua Ibo-1 were originally discovered by Shell in 1960. The Qua Ibo-2 appraisal well was drilled in 1971. There has been no production from the

Figure 6: Mart Resources - Qua Ibo


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field yet. There are two main oil reservoir zones on the field, the upper C-4 reservoir at 3,500 ft and the lower D-5 reservoir at 7,500 ft. There is potential for an additional shallow reservoir.

Exploration prospectivity at Ke The Ke Marginal Field is located on OML 55 in the southern portion of the Niger Delta approximately 18 km west of Shell’s Bonny oil terminal. There are currently no reserves at Ke; however, an independent report by Chapman indicates unrisked best-estimate prospective resources of 42.4 mmbbl net to Mart and the arithmetic average (low-best-high) of net prospective resources on a risked basis of 13.1 mmbbl. Chapman has assessed the chance of success at Ke at 30%. Please see the map in Figure 7 for the location of the Ke field.

The work plan for Ke includes the reprocessing of 3D seismic followed by drilling of the Ke-South well in 1Q09, which is located south of the original Ke-1 discovery well on the block. Drilling site preparation has commenced, with drilling operations anticipated to begin in 1Q09 subject to the completion of site preparation and the receipt of approvals. If successful, the company would export via its pipeline to Shell’s infrastructure 20 km north as early as 2010. There is potential for Mart to farm-out a portion of the company’s interest in Ke.

Mart entered into a finance and technical-services agreement with indigenous company Del-Sigma Petroleum (operator) in Apr 2006 at Ke. Under the terms of the agreement, Mart funds all capital costs in exchange for an allocation of hydrocarbons discovered and produced from the field. Mart will receive its share of production on a sliding scale, beginning with an accelerated repayment of costs

Figure 7: Mart Resources - Ke Field



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contributed to the project and moving to a stepped-down schedule based on aggregate production volume after the recovery of capital costs.

The Ke field was originally discovered by Chevron in 1965 along with the Ke-1 well that encountered light oil (36-44° API) in three sandstone reservoirs between 9,300 and 10,500 ft. There was no test and no appraisal wells were drilled. There is extensive 3D seismic on the field.

NRG Drilling Mart Resources owns two drilling rigs that are currently operating in Nigeria through its wholly owned NRG Drilling subsidiaries.

NRG -101 is a Cooper 550 horsepower, hydraulic double mast (112 feet), truck-mounted rig with a crown hookload of 240,000 pounds. The rig is equipped with a 16 foot, back-on substructure to accommodate the 17 ½ inch rotary table and a 13 7/8 inch, 5000 psig BOP system. There are two triplex mud pumps; an Oilwell A600-PT and a Dreco 10T (combined rate capacity of 1000 gpm). The rig carries 12,000 ft of 3 ½ inch drill pipe and 6 ½ inch drill collars.

NRG-201 is a Big Country 1500 horsepower, electric drive rig fitted on a Brewster 24 ft, self-elevating, box-type substructure with a new 700,000 pound, 27 ½ inch National rotary table. It is equipped with a rebuilt Continental OINE 1500 horsepower draw works powered by two GE752 electric motors capable of developing 1,000,000 pounds of hookload. The rig also has a rebuilt Lee C Moore 142 ft mast with track guides to install a top drive unit in the future.

The rigs have a combined book value of $32mn.

Potential acquisition or take-private candidate Given the deep discount to NAV, the company’s enterprise value of only CAD53mn and the fact that these assets would provide a foothold in Nigeria, makes Mart an attractive M&A target. We also believe that if prolonged depressed valuation levels persist, the company is a take-private candidate.

We note that currently approximately 2% of the outstanding shares of the company is held by management and directors.

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Please see Figure 8 for Mart Resources’ capital structure.

Balance sheet, capital expenditures, and future funding needs We estimate capital expenditures for 2009 of up to $60mn, although this number is contingent on financing. The company is likely to be forced to reduce capital spending plans for 2009 based on our operating cash flow estimate of CAD25mn for next year.

Reserves and resources As of the last reserve report prepared by Chapman Petroleum Engineering, dated 31 Dec 2007, reserves consisted of total net proved reserves of 1.351 mmbbl all attributed to the Umusadege Field, proved plus probable (2P) reserves of 25.8 mmbbl with proved plus probable plus possible reserves (3P) of 50.0 mmbbl. All of Mart’s reserves are light and medium oil.

Capital structure

Figure 8: Mart Resources capital structure as at 30 June - Ke Field Share structure Amount Basic shares 335,473,201 Stock options 34,286,459 Fully diluted shares outstanding 369,759,660 Sources of capital Amount, $mn Long-term debt 19.78 Cash & cash equivalents 1.59 Shareholders' equity 83.72



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Our DCF-derived producing-assets-plus-rigs NAV estimate of CAD0.35/share, includes proved plus probable (2P) reserves for producing assets at Umusadege and the value of the company’s rigs at book. Our total company NAV is CAD0.96/share, which includes additional risked value for probable and possible reserves at Qua Ibo and Umusadege, and risked prospective resources at Ke.

Our target price equates to 4.7x 2009 and 4.7x 2010 P/CF, 3.1x 2009 and 3.3x 2010 EV/EBITDA, 11.5x 2009 and 8.64x 2010 P/E, 60,126 per daily 2009 flowing barrel and $5.45/2P bbl (excluding natural gas), on our estimates.

Valuation

Figure 9: Mart Resources asset valuation summary NAV, Per NAV, Per % of value Current production (proved plus probable reserves) $mn share CADmn share share

Umusadege 105 0.28 135.19 0.37 34% Production & development NAV (2P) 105 0.28 135.19 0.37 34%

Appraisal drilling (probable reserves)

Qua Ibo risked at 30% 69 0.19 88.40 0.24 22% Risked appraisal (P2) 69 0.19 88.40 0.24 22%

Possible reserves

Umusadege P3 risked at 50% 43 0.12 55.51 0.15 14% Qua Ibo P3 risked at 30% 18 0.05 23.18 0.06 6%

Risked P3 60.99 0.16 78.70 0.21 6%

Best estimate risked prospective resources Ke 45 0.12 58.32 0.16 15%

Best estimate risked prospective resources NAV 45 0.12 58.32 0.16 15%

NRG drilling Rigs and equipment at book value 32 0.09 41.47 0.11 10%

32 0.09 41.47 0.11 10%

Total 251 0.84 323.39 1.09 48%

Liabilities Long-term debt 20 0.06 26.36 0.07 -7%

Less cash -17 0 -22 0 -6% Net debt 38 0.10 48.83 0.13 -14% Current net asset value 213 0.74 274.56 0.96 100%


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Major risks for Mart Resources include availability of financing, as well as governmental or business corruption, uncertainty regarding the interpretation and application of foreign laws and regulations, and continuing unrest in the Niger Delta.

Risks inherent in the global oil and gas business include volatility of oil and natural gas pricing, currency risk, cost inflation for materials and services, geological risk, operating hazards, access to supplies and equipment, access to drilling rigs and experienced trades, geopolitical risk and unforeseen weather conditions that can affect drilling programmes. Other risks include potential changes to existing royalty regimes, regulatory environments, political regimes and environmental considerations.

Key risks


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Mart Resources Inc. was incorporated in Alberta, Canada on 7 Nov 1994. In April-May of 2006, Mart entered into formal agreements with Midwestern Oil and Gas Ltd. (Midwestern) and Suntrust Oil Company Nigeria Limited (Suntrust), which granted Mart the right to participate in the development of the Umusadege Field (Umusadege). On 29 Mar 2005, Mart entered into a formal agreement with Network Exploration & Production Nigeria Limited (Network), which grants Mart the right to participate in the development of the Qua Ibo Field (Qua Ibo) and in Jan 2006, Mart entered into a formal agreement with Del-Sigma Petroleum Nigeria Limited (Del-Sigma), which grants Mart the right to participate in the development of the Ke Field. In Dec 2004 Mart closed a common share private placement for proceeds of CAD7.88mn and in Oct 2004 Mart signed a formal agreement with Excel Exploration & Production Company Limited to participate in the development of the Eremor Oil Field in Nigeria. In June 2005, Mart raised CAD9.5mn convertible note financing. In June 2005, the Eremor 1 test well flowed at 940, however, after further analysing the results of the well test and conducting a review of the development possibilities for the field, Mart decided that it did not wish to commit further capital to this project and consequently gave notice to Excel that it wished to resign from the formal agreement with Mart’s resignation from the Eremor Field in effect as at 31 Dec 2006. In Oct 2005 Mart announced the closing of a private placement common equity raise of CAD34mn, raised CAD23.5mn in May, 2006 and in Feb 2007 the company raised CAD8mn through a common share private placement. Mart’s rigs NRG 101 and NRG 201 commenced operations in the Niger Delta in 2006. In May 2007, Mart secured a $10mn debt facility from a Nigerian bank and on 18 Oct 2007 Mart completed a common share private placement for total proceeds of CAD42mn. In Apr 2008, Mart announced commencement of first oil production at the Ususadege field. On 15 May 2008, the company announced the resolution of the Qua Ibo Field dispute with its partner Network Exploration & Production with drilling activities commenced at Qua Ibo in Sep 2008.

Company background

Figure 10: MMT event chart—company history

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16 Jan 2006: Mart signs agreement w ith Del-Sigma Petroleum Limited to participate in the evaluation and development of the Ke Oil

4 Sep 2007: Mart announces plans of a private placement of 80mn shares to raise CAD32mn

21 Apr 2008: Mart announces start of f irst oil production from Umusadege f ield

12 July 2005: Mart enters into an agreement w ith Midw estern Oil and Gas to participate in the development of the Umusadege Field

19 Dec 2006: Mart announces UMU-4 w ell spudded in the Umusadege oil f ield

13 Dec 2004: Mart signs an MoU w ith Netw ork Exploration and Production Nigeria Ltd. to participate in the evaluation and development of the Qua lbo Oil Field

21 Sep 2004: Mart signs a Heads of Agreement w ith Excel Exploration & Production Company to participate in the development of the Eremor Oil Field

28 July 2004: Mart signs Letter of Intent w ith EurAfric Energy to evaluate and participate in the exploitation of the Daw es Island Oil Field

9 May 2006: Closes the f irst private placement of 23.5mn shares at CAD1/share

26 Sep 2007: Size of private placement increases to 105mn shares

15 May 2008: Announces resolution of the dispute over Mart's contractual rights in the Qua lbo field, onshore Nigeria

15 May 2008: Mart announces start of drilling operations in the Qua Ibo f ield, onshore Nigeria


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Board of directors and senior management profiles Wade Cherwayko, chairman and director

Wade Cherwayko has negotiated, financed and developed numerous projects over the past decade in West and North Africa. These include two power plants in Nigeria and Benin, and he was responsible for acquiring, financing, exploring and developing onshore and offshore oil and gas assets for Abacan Resource Corporation, Centurion Energy and Yinka Folowiyo Petroleum Company Ltd. Previously he was a consultant for oil companies operating in Canada, the US and South America.

David Parker, president and director

David Parker has over 25 years of upstream oil and gas experience with BP, Ranger Oil Limited and Canadian Natural Resources Ltd. He has worked in a number of technical and commercial roles including exploration geology and geophysics, economic modelling for strategic forecasting, acquisitions and divestments and corporate planning and development. Parker is a fellow of the Geological Society of London and a member of AIPN, EAEG and PESGB.

William Cherwayko, director

William Cherwayko has over five decades of oil and gas exploration and production experience. Cherwayko was president of Centurion Energy, and was responsible for setting up that company's operations in Canada, Tunisia and Egypt. Previously he co-founded Abacan Resources Corporation, a company focused on exploring for oil and gas in West Africa. He was responsible for negotiating concessions and for drilling and production operations.

Robert J. Leslie, director

Robert Leslie received his Ph.D. in Marine Geology and Oceanography from the University of Southern California. He has worked as an exploration geologist in Canada, the US and internationally. During his carer, Leslie has served as vice president, exploration of Wainoco Oil Corporation (TSX, AMEX, NYSE) and president and CEO of Bluesky Oil & Gas Ltd (TSE, NASDAQ), Texas General Resources Inc (AMEX), Red Oak Resources Inc (TSX) and Mart Resources Inc (TSX.V). He has been a director of the corporation since Aug 1996.

Leroy Wolbaum, director

Leroy Wolbaum is an independent businessman who has been active in the oil and gas industry for over thirty years. He has owned two chemical service companies and has provided consulting services in Africa, China and South America. Wolbaum is a past board member of Centurion Energy and is a director of Anglo-Swiss Industries Inc. He has been a director of the corporation since 1997.

Walter Wakula, MBA, ICD.D, director

Walter Wakula has been president, CEO and chairman of Firesteel Resources Inc. (TSX-V: FVR) since 2007; director and chairman of Blacksteel Oil Sands Inc, director and chairman of Foothills Global Capital Group Inc since 2006 and


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chairman of Wayad Resources Ltd since 1991. Wakula has over 25 years’ experience as a senior executive and corporate director in the oil, gas, energy and banking industries. He holds a bachelor of commerce degree in accounting, an MBA in corporate finance and is a certified corporate director holding the Institute of Corporate Director's ICD.D designation.

Michael J. Perkins, director

Perkins has been a partner with Borden Ladner Gervais LLP, barristers and solicitors since July 2002. Perkins has over 27 years’ experience with respect to the practice of law in the areas of securities, mergers, acquisitions, corporate/commercial and debt financing. He also has extensive experience as a professional advisor to and/or an officer and director of 27 companies either listed or previously listed on the TSX Venture Exchange, the Toronto Stock Exchange or NASDAQ.

Michael B.A. Nobbs, director

Michael Nobbs has over 33 years’ experience as both a principal and corporate advisor in the areas of investment banking and corporate and project finance. Nobbs has participated in various forms of corporate transactions including debt and project finance, corporate mergers and acquisitions and equity fundraising. He is currently a director of a number of privately held and publicly listed companies and has considerable experience in corporate governance, finance, executive compensation and remuneration and audit committee matters.

Management team David Halpin, chief financial officer

David Halpin is a certified management accountant who has consulted for Mart Resources in financial, management, administrative and investor relations roles since the company's inception in 1995. Halpin was also cofounder, director and CFO of Ware Solutions Corporation and was responsible for taking that company public on the TSX-V and for later negotiating its successful sale. Prior to these positions, he provided his financial expertise to various Western Canadian companies operating in the resource and financial sectors.

Mark H. Woitas, vice president, finance

Mark Woitas is a chartered accountant with over 20 years’ senior financial management experience in the energy and transportation industries. Woitas brings significant financial reporting, strategic planning and corporate development experience to Mart. Most recently he was with Gibson Energy Ltd., a wholly owned subsidiary of Hunting PLC, where his efforts facilitated considerable growth in their crude oil marketing and terminal operations.

Jagjit Arora, country manager

Jagjit Arora is a certified engineer with almost 30 years’ international experience, most recently as country manager for General Electric in Nigeria.

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Zack Malone, general manager - NRG Drilling Nigeria

Zack Malone has worked for more than fourteen years in the oil and gas industry. He has gained his experience working for Nabors Canada, before joining NRG Drilling as the general manager.

David Adeoba, finance manager – Nigeria

An accountant and project manager, trained with KPMG, David Adeoba has 23 years’ experience with Agip, Consolidated Breweries, Trojan Estates, Tilca Nigeria and Bideco Construction; holding posts ranging from chief accountant to chief financial officer


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NAV sensitivity

Figure 11: Mart Resources NAV sensitivity table LT Brent oil price, $/bbl 40 45 50 55 60 65 70 75 80 85 90 95 100

15% 0.61 0.65 0.69 0.74 0.78 0.82 0.87 0.91 0.96 1.00 1.04 1.09 1.13 14% 0.62 0.66 0.71 0.76 0.80 0.85 0.89 0.94 0.98 1.03 1.07 1.12 1.16 13% 0.63 0.68 0.73 0.78 0.82 0.87 0.92 0.96 1.01 1.06 1.10 1.15 1.20 12% 0.65 0.70 0.75 0.80 0.84 0.89 0.94 0.99 1.04 1.09 1.14 1.19 1.24 11% 0.66 0.72 0.77 0.82 0.87 0.92 0.97 1.02 1.07 1.12 1.17 1.23 1.28 10% 0.68 0.73 0.79 0.84 0.89 0.95 1.00 1.05 1.11 1.16 1.21 1.27 1.32 9% 0.70 0.75 0.81 0.86 0.92 0.98 1.03 1.09 1.14 1.20 1.25 1.31 1.36 Di

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8% 0.72 0.78 0.83 0.89 0.95 1.01 1.06 1.12 1.18 1.24 1.30 1.35 1.41 Source: Renaissance Capital estimates

�

s

Sterling Energy Plc High impact exploration, US sale key



17 November 2008

Oil and gas Africa

Report date: 17 November 2008 Rating HOLDTarget price (comm), BPN 3.00Target price (pref), $ n/aCurrent price (comm), BPN 3.75Current price (pref), $ n/aMktCap, $mn 136.4EV, $mn 214.8Reuters SEY.LBloomberg SEY LN EquityCommon shares outstanding, mn 2,325.5Change from 52 week high: -75.00%Date of 52 week high: 13 November 2007Change from 52 week low: 87.50%Date of 52 week low 24 October 2008Web: www.sterlingenergyuk.comFree float in $mn 77.0Major shareholder with shareholding 29.5%Average daily traded volume in $mn Share price performance over the last 1 month 25.0% 3 months -50.0% 12 months -75.0%

� We are initiating coverage of Sterling Energy with a HOLD rating and BPN3/share target price. We set our target price at a discount to our DCF-derived production and development NAV estimate of BPN5, which includes value for producing assets in Mauritania and assumes the sale of the company’s US business for $180mn. Our total NAV rises to BPN10 after including risked value for high-impact exploration targets in Kurdistan and Madagascar and nominal value for additional exploration assets.

� Sterling’s near-term catalysts are: 1) the company will drill high-impact exploration prospects in Kurdistan and potentially in Madagascar in 2009, with unrisked best-estimate net prospective resources of 500 mmboe; 2) recently increased production levels at Chinguetti should make the company’s cash flow positive in 2009; and 3) the pending sale of its US business and the recently-signed farm-out agreements would allow the company to retire all outstanding debt and be left with a significant cash balance.

� The sale of the US business derisks the story. We are bullish on the near-term exploration prospects for Sterling, particularly at Sangaw North in Kurdistan, which the company recently farmed out to Addax Petroleum. However, in the current financing environment, we are cautiously optimistic on the company pending the sale of its US business. Sterling has a sales agreement in place for the sale of its US assets which is conditional on financing. This sale is key to de-leverage and derisk the Sterling story in order to move the company to a net cash position.


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2007 184.6 107.5 0.00 0.06 2.0 N/M N/A 27% 5.8 n/a 5.5 0.0% 2008E 114.5 82.4 -0.01 0.02 2.6 N/M N/A 21% 5.4 45 5.5 0.0% 2009E 36.4 29.0 -0.01 0.00 7.4 N/M N/A 22% 1.4 4 6.1 0.0% 2010E 22.8 18.5 -0.01 0.00 11.6 N/M N/A 25% 0.8 n/a 6.6 0.0%


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November 2008 Sterling Energy Renaissance Capital

Our target price of BPN3/share is set at a discount to our DCF-derived production and development NAV estimate of BPN5 which includes value for producing assets in Mauritania and assumes the sale of the company’s US business for $180mn. Our total NAV rises to BPN10 after including risked value for high-impact exploration targets in Kurdistan and Madagascar and nominal value for exploration interests in AGC (the Senegal/Guinea Bissau joint development zone), Cameroon and Gabon. Our NAV and operating financials assume the sale of the US business for $180mn by the end of 4Q08.

Sterling Energy is a London-based E&P company with an enterprise value of $214.8. The company’s assets comprise: 1) producing assets in the Gulf of Mexico that are in the process of being sold and Sterling expects to be divested of them in the near term, subject to financing based on the current sales agreement; 2) producing assets at Chinguetti in Mauritania; 3) high-impact exploration assets in Kurdistan and Madagascar with combined best-estimate net prospective resources of over 500 mmbbl and a high estimate of 1,900 mmbbl net for Sterling; and 4) exploration prospects in Gabon, Cameroon and AGC (Senegal / Guinea Bissau JDZ).

Historically, the company has pursued a three-pronged strategy for growth: 1) acquiring producing assets with appraisal and development potential; 2) acquiring low-cost exploration licences with substantial upside; and 3) opportunistic corporate acquisitions. In the current environment, Sterling is pursuing the sale of its US business for which it has negotiated a sales agreement, contingent on financing. Sterling has also pursued farm-outs with the recent signing of an agreement with Addax Petroleum at Sangaw North in Kurdistan. However, we note that the company still aims to drill four material wells per year going forward, and is pursuing additional licences in Egypt and Nigeria to potentially balance its exploration portfolio with additional lower-risk targets.

We estimate the company’s net cash position to be approximately +$50mn at YE08, assuming it sells its US assets in 4Q08. This cash balance, combined with cash flow from producing assets in Mauritania at Chinguetti and a further farm-out at Ampasindava in Madagascar would put the company in a relatively strong position, in our view. We note that Sterling recently raised GBP13.5mn ($21) in an equity placing, and after making a debt payment of $20.3mn at the end of October we estimate the company will have approximately $28mn in cash on hand, prior to the sale of the US business.

Sterling’s production is currently derived from: 1) properties in the US, which currently produce approximately 4.5 kboe per day (83%) and 2) Chinguetti, offshore Mauritania, which produces approximately 1 kbpd (16%). Sterling is 35% oil-weighted prior to the sale of the US business, and will be 100% oil-weighted after the sale. As of the last reserve report of 31 Dec 2007, reserves consisted of total 2P reserves of 21.3 mmboe (33% oil and 67% natural gas).

Investment summary

Figure 3: Sterling Energy near-term catalysts Activity Expected timing Execution of USA business sales agreement contingent on financing 4Q08/1Q09 Kurdistan seismic interpretation 4Q08/1Q09 Further farm-out of Ampasindava Block 4Q08/1Q09 Continued ramp-up of Chinguetti 4Q08 Sangaw North Kurdistan exploration well Mid-2009 Potential drilling of the Sifaka well offshore Madagascar Ampasindava Block 2H09


Renaissance Capital Sterling Energy November 2008

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Figure 4: Ramping up production at Chinguetti, bpd

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Contingent sales agreement for US assets Sterling Energy has reached an agreement for the sale of its US business, contingent on financing. The dataroom for the asset sale was originally opened in June 2008 and the company originally expected the transaction to close in 4Q08, although this could be delayed given the current financing environment. The sale of this business is key to de-leverage and derisk the Sterling story and would move the company to a significant net cash position, based on our estimates. The US business is comprises producing assets and low-risk development and exploration assets in the onshore Gulf of Mexico area and the shallow water of the Gulf of Mexico. Please see a map of Sterling’s US assets below.

Sterling expects its US assets to produce 27 mmcf per day of gas (76% natural gas) after the completion of hurricane repairs, with 1P reserves of 72.15 bcfe (12.03 mmboe), 2P reserves of 111 bcfe (18.5 mmboe) and 3P reserves of 181 bcfe (30.1 mmboe) as at 31 Dec 2007.

Historic transaction metrics indicate valuations of up to approximately $50,000/daily flowing barrel equivalent or $15.00/bbl of reserves in the Gulf of Mexico. In the interest of conservatism, we have assumed a sale price of $40,000 per daily flowing barrel equivalent implying a total valuation for the US business in the range of $180mn. Please see below for historic transaction comparables for the Gulf of Mexico.

Sterling Energy US sale

Figure 5: Sterling US


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Figure 6: Gulf of Mexico historic M&A transactions

Announced date Buyers Sellers

Total transaction value $mn

Proved+probable (2p)

reserves total mmboe @6:1

Daily boe/d

production Ev/2p

Ev/ daily

production (boe)

9-Jun-08 Undisclosed ATP Oil & Gas Corporation 82 1 528 85.50 155,308 30-Apr-08 Stone Energy Corporation Bois d'Arc Energy Inc 1750 77 19,121 22.73 91,525 22-Apr-08 BP plc; Devon Energy Corporation Anadarko Petroleum Corporation 100 125 - 0.80 - 8-Apr-08 Contango Oil & Gas Company Undisclosed (Various) 100 4 - 25.00 - 4-Mar-08 StatoilHydro ASA Anadarko Petroleum Corporation 2100 250 - 8.40 -

26-Feb-08 Dynamic Offshore Resources LLC Superior Energy Services 165 - 11,000 - 15,000 12-Feb-08 Cieco; Itochu Corp Callon Petroleum Company 188 28 - 6.62 - 1-Feb-08 Korea National Oil Corporation;

Samsung Corporation Taylor Energy Company 1000 - 13,600 - 73,529

4-Jan-08 Contango Oil & Gas Company Undisclosed (Various) 200 6 - 31.41 - 28-Dec-07 Mariner Energy Inc StatoilHydro ASA 243 13 9,700 19.06 25,052 24-Dec-07 W&T Offshore Inc Apache Corporation 116 - 779 - 148,909 22-Oct-07 Saratoga Resources Inc Harvest Oil and Gas LLC 113 22 - 5.13 - 11-Oct-07 Petsec Energy Ltd LLOG Exploration Company 110 6 4,500 18.23 24,444 16-Jul-07 IPR North America Holding Corp;

IPR Lay Creek LLC Santos Ltd 70 5 3,014 14.00 23,227

21-Jun-07 McMoRan Exploration Company Newfield Exploration Company 1100 - 45,000 - 24,444 1-May-07 BP plc Occidental Petroleum Corporation 550 - 8,000 - 68,750 30-Apr-07 Eni SpA Dominion Resources Inc 4730 252 74,000 18.77 63,919 24-Apr-07 Energy XXI Gulf Coast Inc;

Energy XXI (Bermuda) Limited; Undisclosed

Pogo Producing Company 420 26 7,400 16.32 56,689

2-Apr-07 Itochu Corp Range Resources Corporation 155 - 2,300 - 67,391 8-Mar-07 Callon Petroleum Company BP plc 190 44 - 4.30 -

18-Dec-06 StatoilHydro ASA Norsk Hydro ASA 32192 - 560,401 - 57,445 16-Nov-06 Tekoil & Gas Corporation Masters Resources LLC 53 - 850 - 61,765 12-Nov-06 Repsol YPF SA; BHP Billiton Ltd;

Hess Corporation Anadarko Petroleum Corporation 1330 118 - 11.32 -

8-Sep-06 SandRidge Energy Inc American Real Estate Partners LP; American Real Estate Holdings Ltd Partnership

1505 - 18,922 - 79,557

29-Aug-06 Phoenix Exploration Company LP Cabot Oil & Gas Corporation 340 23 8,667 15.11 39,231 28-Aug-06 Woodside Petroleum Ltd Energy Partners Ltd 1262 - 28,117 - 44,869 12-Jul-06 Repsol YPF SA BP plc 2145 140 30,333 15.32 70,714 23-Jun-06 Anadarko Petroleum Corporation Kerr-McGee Corporation 19623 2695 246,333 7.28 79,662 20-Jun-06 Stone Energy Corporation BP plc 191 - 4,167 - 45,720 16-Jun-06 Energy Partners Ltd Stone Energy Corporation 2107 - 34,639 - 60,815 25-May-06 Energy Partners Ltd Stone Energy Corporation 2086 - 32,391 - 64,401 16-May-06 First Reserve Corp;

Beryl Resources LP; Superior Energy Services

Noble Energy Incorporated 625 - 20,000 - 31,250

24-Apr-06 Plains Exploration & Production Co Stone Energy Corporation 2137 - 32,391 - 65,961 20-Apr-06 Mitsui & Company Ltd;

Mitsui Oil Exploration Co Ltd Pogo Producing Company 500 - 12,000 - 41,667

19-Apr-06 Stone Energy Corporation; A pache Corporation; Mariner Energy Inc; Undisclosed

BP plc 1300 - 26,600 - 48,872

7-Apr-06 Merit Energy Company The Houston Exploration Company 590 - 13,333 - 44,250 28-Feb-06 Norsk Hydro ASA;

Merit Energy Company; Nippon Oil Corporation

The Houston Exploration Company 220 - 7,500 - 29,333

23-Feb-06 Marubeni Corp Pioneer Natural Resources Company 1300 50 38,000 26.00 34,211 22-Feb-06 Energy XXI Gulf Coast Inc;

Energy XXI (Bermuda) Limited Marlin Texas LP; Marlin Texas GP LLC; Marlin Energy Offshore LLC; Marlin Energy LLC

421 - 10,800 - 38,991

6-Feb-06 Northstar GOM LLC; Northstar Interests LC Petrohawk Energy Corporation 53 - 1,667 - 31,500 23-Jan-06 Helix Energy Solutions Group Inc Remington Oil & Gas Corporation 1312 - 13,633 - 96,238 2-Jan-06 W&T Offshore Inc Kerr-McGee Corporation 1030 112 26,800 9.22 38,448

Median 525 36 13,467 15.22 52,781 Average 2043 200 40,191 18.03 57,150

Source: J.S.Herold

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Proceeds from the sale of the business will be used to pay off company debt and we estimate the company’s net cash position to be approximately +$50mn at YE08, assuming it sells the US assets in 4Q08, and will fund future exploration. If the sale of the US business is not completed, we expect Sterling to operate these assets for cash with progressive disposals.

The original strategy for the US business was to use the cash flow from the assets to fund exploration in Africa and the Middle East. However, given the combination of global market conditions and current capital requirements it will be too costly to fully exploit opportunities in the company’s US business. As such, Sterling is pursuing a divestiture of these assets. The company has also stated previously that it plans to undertake a share buyback when it becomes advisable to do so. However, in the current environment we believe this is unlikely to happen.

Mauritania – Ramping-up of production continuing at Chinguetti Sterling’s interests in Mauritania include production and appraisal assets that have a sliding-scale royalty based on oil prices combined with cash bonuses for each commercial discovery in PSC A and PSC B, which are located offshore. The company also has an economic interest in the Chinguetti Field as a result of Sterling financing the Mauritanian government’s 12% back-in. Sterling receives cost recovery and a share of profit oil under this arrangement. The Chinguetti Field is located on PSC B.

PSC A and PSC B are located offshore Mauritania in the Mauritania-Senegal-Gambia-Bissau-Conarky (MSGBC) basin. Please see below for a map of PSC A and PSC B.

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Chinguetti production volumes recently increased to 17 kbpd as at 17 Oct 2008, relative to 1H08 rates at 10 kbpd, with the completion of Phase 2 development work.

Chinguetti is the first oil development offshore Mauritania in a Miocene field discovered in 2001. The field came onstream in Feb 2006 at the targeted production rate of 75 kbpd. Subsequent to initial production, rates fell significantly to 10 kbpd and gross proved plus probable (2P) reserves are now estimated to be in the range of 50 mmbbl compared to original expectations in the range of 123 mmbbl. Petronas took over as operator of the field from Woodside in Dec 2007 and Phase 2B drilling has now been completed along with two further development wells and three well interventions (workovers).

There are also two potential oil discoveries that could be tied back to the Chinguetti Floating Production and Storage Offshore facility (FPSO): 1) the Tiof Miocene oil and gas field, discovered in 2003, with an estimated 500 mmbbl of stock tank oil initially in place (STOIIP) and potential for up to 50 mmbbl that can be developed in the first phase and 2) the Tevet Miocene oil field, discovered in 2004, with potential for up to 100 mmbbl of STOIIP, as estimated by Petronas. Timing is unclear on these tie-backs and is largely contingent on the success of the Phase 2B drilling programme on Chinguetti and the potential for a Phase 3 programme. The PSC agreements on A and B expire in mid-2009, although this will not impact the Chinguetti development or Sterling’s royalty agreement on PSC A or PSC B.

Figure 7: Sterling Energy interests in Mauritania


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Other discoveries on PSC A and PSC B include: 1) the Banda Miocene gas field discovered in 2002 with natural gas reserves estimated in the 1-2 tcf range and a significant oil leg and 2) the subeconomic Labeidna Miocene oil field discovery.

The sliding-scale royalty payment Sterling receives is linked to the oil price for every barrel produced net to a working interest of 3% in Area A, and 6% in Area B, subject to the government's back-in rights. Sterling also has the right to cash bonuses of $1mn for a greater than 50 mmboe discovery in Area A and $2mn in Area B. The royalty payment per barrel escalates with the oil price and inflation. Based on company guidance, for an average price of $70/bbl in 2009, the royalty would be $9.50/bbl. The company also receives cost recovery and profit oil based on a sliding scale under the Chinguetti funding deal with the Government of Mauritania.

Kurdistan offers huge upside in a prolific basin Sterling Energy operates the Sangaw North Block in the Zagros fold-thrust belt in the Kurdistan region of Iraq. The block is 50 km southeast of the Kirkuk field and on trend with the Taq Taq and the Chemchamal oil and gas condensate discoveries. The block covers an area of 492 km2 and multiple oil seeps have been observed.

Drilling on the block is planned for mid-2009 and Sterling has increased the seismic programme to 310 km, which is on target to be completed in November. Addax Petroleum has recently farmed-in to this block for a 33.33% interest (prior to the Kurdistan Regional Government’s [KRG’s] assignment of an interest to the Korea National Oil Corporation [KNOC]). Sterling retained a 66.67% interest prior to the assignment and a 53.33% interest following the assignment. Independent assessment by Resource Investment Strategy Consultants (RISC) indicates gross prospective best-estimate resources on the Sangaw North Block of 212 mmbbl and a high estimate of 787 mmbbl. Under the terms of the farm-out agreement, Addax will pay prior costs, and fund the cost of the seismic programme and the first well.

The PSC is structured so that the contractors fund all exploration and development expenditures. The contractor is entitled to cost recovery of capital expenditures and operating costs and to receive a designated share of oil production after the payment of royalties. Oil production is allocated into the following three categories: 1) royalty oil, 2) cost oil, and 3) profit oil. We note that the government has a further option to assign a 25% stake in the field to a government-nominated entity that would reduce Sterling’s interest to 40.00%.

Deepwater wildcatting in Madagascar Sterling holds a 30% carried interest in the Ambilobe (operator) and Ampasindava blocks offshore northwest Madagascar in the Indian Ocean that cover an area of 15,600 km2 and 9,860 km2, respectively. Exxon Mobil holds the remaining 70% interest in both blocks and is the operator at Ampasindava. Please see the map below that shows the location of these blocks.

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The Sifaka prospect on the Ampasindava block, located at a depth of 1,000-1,500 metres, is the company’s first target offshore Madagascar that is likely to be drilled. RISC has provided an independent assessment of gross (100%) best-estimate prospective resources for the Sifaka prospect of 1,155 mmbbl and a high estimate of 4,839 mmbbl. This equates to best estimate prospective resources net to Sterling of 347 mmbbl and high estimate prospective resources net to Sterling of 1452 mmbbl, based on the company’s current 30% interest. The Sifaka prospect is expected to be drilled in 2H09. This is the first deepwater well to be drilled offshore Madagascar.

On the Ampasindava block, a 2D seismic study has been shot, processed and interpreted with three large prospects mapped, including Sifaka. There is potential to spud the well in 2009 subject to rig availability and cost, with gross costs of drilling the Sifaka exploration well currently estimated to be approximately $180-200mn. The costs of the well are anticipated to exceed Sterling’s remaining carry. Therefore, it is likely that the company’s interest could be farmed-out to a further extent, potentially in the range of a 10% fully-carried interest.

Sterling acquired the two exploration licences in Madagascar in late 2004. The company signed a farm-out agreement with Exxon Mobil in May 2005 whereby Sterling receives a 30% carry on a work programme of up to $100mn. The total exploration term for each licence is eight years with a 25-year production licence to be granted in the event of a commercial discovery.

Figure 8: Sterling Energy interests in Madagascar


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Gabon Sterling holds a 32% interest in the Iris Marin PSC offshore in shallow water located in the Southern Gabon Sub-basin and is the current operator. The PSC area is adjacent to the Gamba and Ivinga producing oil fields and the Olowi field development and covers an area of 402 km2. Other interest holders in the block are Addax Petroleum (51.33%) and Afren (16.67%).

Sterling also holds a 40% operated interest in the Ibekelia Marin Technical Evaluation Agreement that is in advanced stages of discussion for conversion into a PSC. Ibekelia is contiguous with the Gamba, Olowi and Iris Marin and covers an area of 673 km2. Other holders of this block include Addax Petroleum (40%) and Afren (20%).

Please see the map below that illustrates Sterling’s interests in Gabon.

Recent drilling activity on Iris Marin includes the ICM-1 well on the Charlie prospect that was drilled in 2008 to 1,640 metres, encountering a water-bearing reservoir that was plugged and abandoned. The THAM-1 well drilled in Jan 2008 was drilled to 1,330 metres with limited hydrocarbon shows and was also plugged and abandoned.

Sterling recently farmed-out an 18% interest in Iris Marin to Addax Petroleum for $3.3mn and an 18% interest-equivalent carry on up to two wells. Operating rights are expected to be transferred to Addax Petroleum, subject to government approval.

Figure 9: Sterling interests in Gabon


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Other exploration opportunities Sterling also has interests in Cameroon, with the offshore Ntem Block (100% interest) that is under force majeure due to a border dispute between Cameroon and Equatorial Guinea. In 2004, Equatorial Guinea awarded a block that overlaps 15% of the Ntem Block. Sterling expects to farm-out large Cameroon prospects once the border dispute is resolved.

In the AGC (Senegal/Guinea Bissau JDZ), Sterling holds a 30% interest in the Dome Flore Block, which is located in the Casamance-Bissau Sub-Basin (Southern MSGBC Basin), with an area of 1,699 km2. Markmore is the operator with a 55% interest while L’Enterprise holds a 15% interest. Over 1bn bbl of heavy oil has been discovered on this block in shallow formations, with the majority of the exploration done between 1967 and 1971. There is potential for light oil, with previous wells encountering lighter oil in formations above and below the heavy discoveries. Although this licence expired in Jan 2008, a conditional extension has been granted. Sterling will be fully carried on the next well. This well will target two light oil reservoirs and will cut a core in the heavy oil accumulation.

Sterling is also pursuing licences in Egypt and Nigeria that could provide lower risk exploration targets for the company in order to balance its portfolio. Sterling still intends to drill four high-impact wells per year going forward.

Sterling’s future exploration success and high-impact exploration portfolio could drive M&A in the medium term We believe that over the medium term, depending on its exploration success, Sterling Energy could become a takeover target. In the near term, any M&A would likely be driven by financing constraints if the sale of the US business does not close, in our view. We believe that Addax Petroleum could be a natural buyer at some point in the future, given the companies’ asset overlap in Gabon and Kurdistan.

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Please see the table below for Sterling Energy’s capital structure. The company’s management and board of directors own approximately 4% of the company’s outstanding shares. Denis O’Brien holds 14.04% of the outstanding shares of the company.

Balance sheet, capital expenditures, hedging and future funding needs We estimate Sterling’s total capital expenditures for 2008 at approximately $45mn and limited capital expenditures in 2009, provided that the US business is sold and that a further farm-out at Ampasindava can be negotiated. Capital expenditures in 2009E may be higher depending on wells drilled in Gabon and potential acquisition of new licences that the company is pursuing in Egypt and Nigeria.

Sterling currently has borrowings of $123mn after a recent loan repayment of $20.3mn. The company’s current cash balance is approximately $28mn. The company expects to make future loan repayments of $7mn and $6mn in Feb and Aug 2009, respectively.

The company has Brent hedges in place for 2009 of 1 kbpd at $74.30/bbl and WTI hedges in place of 0.21 kbpd at $69.90-85.35/bbl. For natural gas, the company has hedges in place for 7,342mn British thermal units (btu) per day with collars of $7.00-8.65/mn btu and swaps at $8.00-9.22/mn btu.

Reserves and resources As of the last reserve report of 31 Dec 2007, Sterling’s reserves consisted of total 2P reserves of 21.3 mmboe (33% oil and 67% natural gas). Reserves from the US business were 18.5 mmboe, accounting for 87% of total reserves, with the remaining reserves for the company coming from the Chinguetti field in Mauritania.

Valuation Our target price is set at a discount to our DCF-derived production and development NAV estimate of BPN5, which includes value for producing assets in Mauritania and assumes the sale of the US business for $180mn. Our total NAV rises to BPN10 after including risked value for high-impact exploration targets in Kurdistan and Madagascar and nominal value for exploration interests in AGC (Senegal / Guinea Bissau JDZ), Cameroon and Gabon. On an unrisked basis, our NAV rises to

Capital structure

Figure 10: Sterling Energy capital structure Share structure Amount Basic shares 2,325,510,585 Sources of capital Amount, $mn Bank loan 123 Cash & cash equivalents 28 Shareholders' equity 210


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BPN9.60. Our NAV assumes the sale of the US business for proceeds of $180mn and also assumes a further farm-out of the Ampasindava Block to a 10% interest.

Figure 11: Net asset valuation summary NAV, Per NAV, Per % of value Production & development $mn share GBPmn share share

Mauratania (Chinguetti back-in and royalty) 83 0.04 50.79 p 2.18 218% Production & development NAV 83 0.04 50.79 p 2.18 218% Best estimate risked prospective resources Sangaw North (Kurdistan) 122 0.05 74.84 p 3.22 46% Ampasindava (Madagascar) 58 0.02 35.39 p 1.52 22% Best estimate risked prospective resources NAV 180 0.08 110.24 p 4.74 287% Total 263 0.11 161.02 p 6.92 100% Liabilities Debt 129 0.06 78.77 p 3.39 49% Less cash 230 0.10 141 p 6.06 88% Net debt -102 -0.04 -62.27 -p 2.68 28% Current net asset value 364 0.16 223.00 p 9.60


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Major risks for Sterling include financing risk, risk to executing the conditional sale of its US business, the timing of drilling in Madagascar with ExxonMobil as the operator of Ampasindava, governmental or business corruption in its countries of operation and uncertainty regarding the interpretation and application of foreign laws and regulations in those countries.

Risks inherent in the global oil and gas business include volatility of oil and natural gas pricing, currency risk, cost inflation for materials and services, geological risk, operating hazards, access to supplies and equipment, access to drilling rigs and experienced trades, geopolitical risk and unforeseen weather conditions that can impact drilling programmes. Other risks include potential changes to existing royalty regimes, regulatory environments, political regimes and environmental considerations.

Key risks

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Sterling Energy Plc was formed in Oct 2002 by the reversal of Sterling Energy Ltd into Lepco Plc, after which it was renamed Sterling Energy Plc. The company then listed on AIM, also in Oct 2002. In Dec 2003, the company acquired Fusion Oil & Gas Plc, a company with West African exploration assets for GBP40mn. In Feb 2004 the company acquired five producing gas fields offshore Texas in the Gulf of Mexico from Osprey for $40mn. In Nov 2004 the company placed GBP97mn worth of shares and entered the Chinguetti Funding Agreement for the Chinguetti oil field in Mauritania. It saw first production from the field in 2006. Also in 2004 the company acquired two large exploration licences in Madagascar. In May 2005 the company farmed out the Ambilobe and Ampasindava blocks offshore Madagascar to ExxonMobil. In Mar 2007 Sterling acquired Whittier Energy Corporation with assets onshore Texas, Louisiana, Mississippi and in the Permian Basin for $145mn. In Nov 2007, Sterling entered into a PSC agreement with the KRG for the Sangaw North PSC after signing a memorandum of understanding with the KRG in Feb 2006.

Board of directors and senior management profiles Dick Stabbins, non-executive chairman

Dick Stabbins is a geologist with more than 35 years of experience in the international energy industry, mainly in the independent sector. He has worked for the Saskatchewan (Canada) Department of Mineral Resources (1969-72), for Murphy Oil (1972-1975) and for Ranger Oil (1975-1981). He was exploration manager and subsequently exploration director of Goal Petroleum Plc from 1981 until 1996.

Company background

Figure 12: Sterling Energy event chart – company history

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29 Mar 2007: Sterling announces completion of its $145mn cash acquisition of Whittier Energy Corporation

19 Jan 2007: Sterling announces it has entered into a merger agreement to acquire Whittier Energy Corporation for $14518 Mar 2005: Sterling signs a farm-out deal with

Markmore Energy for the Dome Flore offshore petroleum licence held by Sterling

27 Feb 2006: Sterling announces crude oil production has begun from Chinguetti oilfield

15 May 2006: Announces lower production from Chinguetti oilfield, averaging 45mbopd for 1-10 May to 10 compared with 53mbopd for April and 66mbopd for March 21 Jul 2004: Sterling announces

award of 100% interest in two new exploration licences offshore Madagascar

30 Jan 2004: Sterling agrees to acquire five producing gas fields from Osprey Petroleum Partners

25 Sep 2003: Sterling announces an offer to acquire entire share capital of Fusion Oil & Gas plc for approximately GBP40mn

18 Oct 2002: LEPCO plc to be renamed Sterling Energy plc post acquisition of Sterling Energy Ltd. for GBP7.9mn

12 Nov 2007: Sterling announces it has Production Sharing Contract with Kurdistan Regional Government of Iraq for the Sangaw North exploration block

30 Sep 2008: Sterling proposes placement of 675mn new shares to raise GBP13.5mn

2 July 2008: Sterling announces sale of its entire stake in Forum Energy plc at a net consideration of GBP1.9mn

30 May 2008: Announces completion of its sale of a non-operated interest in a waterflood project in New Mexico for $5mn

14 Jan 2008: Sterling announces THAM-1 well has been plugged and abandoned

7 Apr 2008: Sterling starts sale process of its US oil & gas exploration and production business



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From July 2000, until its acquisition by Sterling Energy, he was a non-executive director of Fusion Oil & Gas Plc. Stabbins currently manages a private energy company, Montrose Industries Ltd, which has interests in a wide range of energy projects. He also has considerable private venture capital experience. He is a former chairman of the Petroleum Exploration Society of Great Britain (1990) and a council member of the Geological Society of London (2000-2003), whose Audit Committee he chairs. He also serves on their Investment and Remuneration Committees.

Harry Wilson, executive deputy chairman

Following graduation from a British Petroleum scholarship programme, Wilson joined BP and worked for 17 years in a variety of exploration and corporate finance roles. In 1987, he left BP to form Kirkland Resources, which was listed in London as Dragon Oil in 1993.

In 1997, Wilson was the principal founding partner of the Endeavour Oil & Gas Limited Partnership and, following the successful sale of Endeavour in 2000, was a founding partner and director of Sterling. Following the listing of Sterling on AIM in 2002, Wilson was appointed chief executive of the group.

Graeme Thomson, chief executive officer

Graeme Thompson has held a number of senior finance and management positions in quoted companies. In 1989, he co-led a management buy-in to AmBrit International plc, which was taken over in 1992. He then joined the Kirkland Group, which later became Dragon Oil plc, where he served as finance director and company secretary until April 1999.

A founder partner of Endeavour and Sterling, he has assisted unquoted and quoted companies, including Sterling LP and the company, with their corporate finance, accounting, commercial and strategic affairs. He was appointed as a non-executive of the company in July 2001, and as an executive in October 2002.

Andrew Grosse, exploration and technical director

Andrew joined Sterling in 2002, as the company’s exploration manager. He has extensive international exploration experience with operating oil companies in Africa, the Middle East and North America. Prior to joining Sterling, he was British-Borneo’s exploration manager for the Gulf of Mexico and then for International New Ventures where he was instrumental in securing an interest in the offshore Mauritanian acreage, which subsequently delivered the Chinguetti oil discovery and the Tiof oil discovery.

He began his career with Gulf Oil in Canada, and has also worked with BP Exploration and Ultramar Exploration. He was appointed as a director in Jan 2005.

Jon Cooper, financial director and company secretary

Jon Cooper joined Sterling as finance director in Feb 2008. He is an experienced finance professional with advisory experience in the oil and gas industry.

Cooper began his career with KPMG where he qualified as a chartered accountant, and in 1997 joined Dresdner Kleinwort Wasserstein as a director in the oil and gas

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corporate finance team. during this time he worked on mergers and acquisitions, public offerings and as strategic adviser to a wide range of companies including Gazprom, LUKOIL, OMV, PKN Orlen, Unocal, Petronas and Harvest Natural Resources. Prior to joining Sterling, Cooper spent two years working as finance director at Gulf Keystone Petroleum.

Peter Wilde, non-executive director

Peter Wilde graduated in law from the London School of Economics, and has spent most of his career managing and developing smaller companies, working in the oil sector for the last sixteen years. In 1989, he was appointed vice president of Aviva Petroleum Inc., the Dallas-based oil and gas independent, where his responsibilities included, in particular, corporate financial control and integration of acquisitions.

He has been a director of the company since its foundation in 1983, serving as a full time director from 1991 to 2001, firstly as chief operating officer and latterly as managing director. Since July 2001, he has served as non-executive director and is chairman of the audit committee.

Chris Callaway, non-executive director

Callaway joined the London Stock Exchange in 1973 and then, in 1983, he moved to Capel Cure Myers (subsequently ANZ Merchant Bank) in the role of corporate finance adviser, specialising in small- and medium-sized growth companies. He became a partner at Coopers & Lybrand in 1990 before joining Beeson Gregory in 1995.

Beeson Gregory was subsequently taken over by the Evolution Group in 2002 and, upon the merger, Callaway became joint head of corporate finance, retiring in Dec 2004. Since then, Callaway has been involved in the flotation of a number of companies of which he is both an investor and a director.

Dan Silverman, president, Sterling Energy US

Dan Silverman served as executive vice president and COO for Whittier Energy from 2003 until its acquisition by Sterling in 2007. He has 21 years of industry experience and is a former managing director of acquisitions and divestitures and director for Torch Energy Advisors and a former manager of acquisitions and divestitures for Apache Corp.

Silverman has also worked as a consultant for Regent Energy Corporation and as executive vice president of business development and COO of Petrominerals Corporation.

Certain matters are delegated to board committees, each with defined terms of reference, procedures, responsibilities and powers.

�

Tullow Oil Non-producing asset value


Initiation of coverage Equity research

17 November2008

Oil and gas Africa

Report date: 17 November 2008Rating HOLDTarget price (comm), BPN 600Target price (pref) n/aCurrent price (comm), $ 453.50Current price (pref) n/aMktCap, $mn 5,139.3EV, $mn 5,616.5Reuters TLW.LBloomberg TLW LNCommon shares outstanding, mn 724.8Change from 52 week high: -57.50%Date of 52 week high: 24/06/2008Change from 52 week low: 4.88%Date of 52 week low 28/10/2008Web: www.tullowoil.comFree float in $mn 4,916Major shareholder with shareholding

11.98%

Average daily traded volume in $mn 36.8Share price performance over the last 1 month -12.66% 3 months -39.34% 12 months -34.14%

� We initiate coverage of Tullow Oil with a HOLD rating and BPN600/share target price. Our target price is set at a discount to our DCF-derived NAV estimate of BPN711/share. Our NAV estimate includes proved plus probable (2P) reserves for producing assets; the value the Jubilee development, in Ghana, and Block 3A, in Uganda; and prospective resources, mainly deepwater Ghana and Block 1 and Block 2 in Uganda. Tullow is currently trading at 64% of our NAV and at a significant multiple premium to African and global E&P peers, due to significant non-producing asset value at 7.7x P/CF, 7.4x EV/EBITDA and $30.49/2P bbl.

� Tullow offers a combination of: 1) world-class developments at Jubilee and Lake Albert, in Uganda; 2) significant non-producing asset value, with potential to almost triple net production by 2013; 3) further potential high-impact exploration in Uganda, Ghana, Cote d’Ivoire and Mauritania; and 4) the likelihood of a significant near-term reduction of net debt with the closing of the M’boundi and Hewett divestitures. We identify the main risks to Tullow as execution risk at the Jubilee development, as the company’s first major operated deepwater asset; and the timing of first production at Lake Albert, particularly in a prolonged low oil price environment.

� Long-term production potential. Investors can afford to wait until the end of the decade with production relatively flat until Jubilee and Lake Albert almost triple forecast production over the 2010-2013 period.


Revenue EBITDA EPS (p)

CFPS (p) EV/EBITDA P/E P/CF Net Debt to

Capital Production Oil Weight Plowback Dividend

yield 2007 n/a n/a 35.64 66.95 3.38 12.72 6.77 0.40 73.1 69% 99% 0.4% 2008E 745.79 593.74 25.96 66.43 6.05 17.47 6.83 0.14 67.0 69% 130% 0.9% 2009E 651.14 488.06 21.67 59.21 7.36 20.93 7.66 0.28 61.8 75% 123% 0.9% 2010E 610.14 478.33 24.83 56.88 7.51 18.26 7.97 0.34 61 79% 70% 0.9%


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Renaissance Capital Tullow Oil November 2008

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We initiate coverage of Tullow Oil with a HOLD rating and BPN600/share target price. Our target price is set at a discount to our DCF-derived NAV estimate of BPN711/share. Our NAV includes proved plus probable (2P) reserves for producing assets; the value of developments at Jubilee, in Ghana, and Block 3A, in Uganda; and prospective resources – mainly deepwater Ghana and Block 1 and Block 2 in Uganda.

Our target price of BPN600/share equates to: 10.1x 2009E and 10.6x 2010E P/CF; 9.5x 2009E and 9.7x 2010E EV/EBITDA; and 27.7x 2009E and 24.2x 2010E P/E and $105,370 per daily 2009 flowing barrel and $39.50/2P bbl, excluding African natural gas reserves. Based on 2P plus contingent resources, our target price implies $6.65/bbl, excluding African natural gas.

Tullow Oil is a London-based E&P company with an enterprise value of GBP5,616mn. The business is organised into four core areas – Africa, Europe, South Asia and South America – with 109 licences in 23 countries. Africa is the company’s largest core area, accounting for more than 50% of its production and revenue, and more than 80% of reserves and resources.

Tullow’s production is currently derived from properties in Africa (65%), Europe (26%), and South Asia (9%). Total company production is 65% oil-weighted, with natural gas production in Europe and South Asia. As of the last reserves report (30 June 2008), Tullow had total proved plus probable (2P) reserves of 184.2 mmboe (68% oil, 32% natural gas), with 2P plus contingent resources of 536.3 mmboe (53% oil, 47% natural gas). Total 2P plus contingent African gas resources are 1,033.9 bcf.

Tullow’s producing assets in Africa include properties in Republic of Congo ([Brazzaville], although the company’s sole interest in the country [11% M’Boundi] was recently sold to Korean National Oil Company [KNOC]); Cote d’Ivoire; Equatorial Guinea; Gabon and Mauritania. In Europe, the company has producing assets in the North Sea (UK), and production in South Asia is centred in Bangladesh and Pakistan. Tullow has no producing assets in South America.

The company’s major development assets include the Jubilee discovery, offshore Ghana, and the Lake Albert discovery, in Uganda and Democratic Republic of Congo (DRC; although DRC development potential for Tullow remains subject to finalisation of the awards of Block I and Block 2). Tullow is exploring extensively throughout Africa, with major high-impact exploration targets in Ghana, Uganda, Cote d’Ivoire and Mauritania.

In our view, Tullow offers an attractive combination of: 1) world-class oil developments at Jubilee and Lake Albert, in Uganda; 2) significant non-producing asset value, with potential to almost triple net production by 2013; 3) further potential high-impact exploration in Uganda, Ghana and Cote d’Ivoire; and 4) the likelihood of a significant near-term reduction of net debt, with the closure of the M’boudi and Hewett divestitures. We identify the main risks to Tullow as execution risk at the Jubilee development, as the company’s first major operated deepwater asset; and the timing of first production at Lake Albert, particularly in a prolonged low oil price environment.

Investment summary

November 2008 Tullow Oil Renaissance Capital

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We believe Tullow has significant long-term upside potential as it moves forward with further exploration, appraisal and development of the Jubilee and Lake Albert discoveries.

On our estimates, the company is currently trading at 7.7 2009 and 8.0 2010 P/CF, 7.4 2009E and 7.5 2010 EV/EBITDA; 20.9x 2009E and 18.3x 2010E P/E, 81,330 per daily flowing barrel and $30.49/2P bbl (excluding Africa natural gas). This represents a premium to Tullow’s peers, given the company’s significant non-producing asset value. We estimate global E&P peers are trading at 4.2x 2009E and 3.76x 2010E P/CF, 3.51x 2009E and 3.12x 2010E EV/EBIDA, 7.80x 2009E and 5.49x 2010E P/E, $60,336 per daily flowing barrel and $13.41/2P boe.

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Figure 3: Tullow Oil near-term catalysts Activity Expected timing Pipeline commerciality threshold in Uganda 4Q08/1Q09 Closing of M'Boundi divestiture 4Q08 Closing of Hewett divestiture 4Q08 Ghana deepwater exploration and development drilling 4Q08/4Q09 Increased production in Cote d'Ivoire 2009 Cote d'Ivoire exploration drilling 2Q09 Uganda exploration drilling 4Q08/2009 Tanzania exploration drilling 1H09 Mauritania exploration drilling 4Q09


Production profile ramps up significantly post-2010 With production from the Jubilee field offshore Ghana and potential for significant volumes from Lake Albert in Uganda beyond 2010, we forecast that production could triple between 2010 and 2013. Figure 2 illustrates historical production, and our projected production forecasts, for Tullow.

As announced in the company’s half-year interim results on 27 Aug 2008, Tullow has cut its production guidance to 68-70 kboped for 2008, from the previous target of 70-74 kbpd, due to lower-than-expected production at its UK natural gas business. The company announced that total production is expected to average 67 kboepd for 2008 on 12 Nov 2008.

Jubilee offers 1bn bbl-plus potential offshore Ghana The Jubilee discovery is located on the West Cape Three Points (WCTP) and Deepwater Tano Blocks, offshore deepwater Ghana. Tullow holds a 49.95% operated interest in the Deepwater Tano Block (Anadarko 18%, Kosmos 18%, GNPC 10%, Sabre 4.05%) and a 22.9% interest in the WCTP Block (Kosmos 30.875%, Anadarko 30.875%, GNPC 10%, E.O. Group 3.5%, Sabre 1.854%). Tullow has been appointed unit operator of the Jubilee discovery, with unitisation discussions for the discovery ongoing. Tullow also holds a 31.5% interest in the

Near-term catalysts

Figure 4: Tullow Oil potential production profile, (kbpd)

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Mauritania Ghana Uganda PakistanBangladesh Equatorial Guinea Congo (Brazzav ille) Cote D'Iv oireGabon UK



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Shallow Water Tano Block. Figures 3 and 4 summarise Tullow’s interests offshore Ghana.

Figure 5: Tullow Oil - Ghana licences Licence Fields Area, km2 Tullow interest Operator Other partners Shallow Water Tano 983 31.50% Tullow GNPC, Sabre, InterOil, Al Thani Deepwater Tano Jubilee 1,108 49.95% Tullow Anadarko, Kosmos, GNPC, Sabre, West Cape Three Points Jubilee 1,957 22.90% Kosmos Anadarko, GNPC, E.O. Group, Sabre,

Source: Company data l

The Jubilee discovery was the largest oil discovery in 2007, with estimated P90-P50-P10 reserves of 500 mmbbl, 1,000 mmbbl, 1,800 mmbbl. The discovery also contains significant natural gas resources, estimated by Tullow at approximately 800 bcf.

The first phase of the Jubilee field development is expected to be sanctioned in late 2008, with a stretch first production targeted for 2H10, although, in our view this seems aggressive in the current environment. The first phase of development is expected to have capacity of 120 kbpd and 160 mmscfd of produced gas. There will be a total of 17 wells for production and injection (water). Tullow estimates total capex for phase one of the project at about $3.1bn, excluding leasing costs for an associated floating production and storage unit (FPSO). The first phase of the

Figure 6: Tullow Oil interests offshore Ghana


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development is aimed to commercialise gross reserves of 300-350 mmbbl with further phases expected based on drilling results to date.

Jubilee was originally discovered with the Mahogany-1 well, on the WCTP Block, in June 2007. The well was drilled in water depths of 1,320 metres and to a depth of 4,200 metres encountering a gross hydrocarbon column of 270 metres with 95 metres of net stacked pay in the Turonian turbidite.

The first well on the Deepwater Tano Block was the Hyedua-1 well, with results announced in Aug 2007. The Hyedua-1 well was drilled in 1,530 metres of water and to a total depths of 4,002 metres, encountering a gross reservoir interval of 202 metres, containing 41 metres of net hydrocarbon-bearing pay also in the Turonian turbidite. Logging and pressure-testing at the Hyedua well also indicated a strong likelihood that the wells were in communication, implying a single continuous trap extending over both blocks.

Results of the Odum-1 well, the second well on the WCTP were released in Feb 2008, with the well encountering a gross oil column of 60 metres and 22 metres of net pay in the Campanian age fan system.

The first appraisal well drilled at Jubilee was the Mahogany-2 well on the WCTP, with results released in May and June 2008. This well also indicated that Jubilee is a single continuous trap extending at least to the Hyedua-1 discovery well 11 km away on the Deepwater Tano Block. This well also did not encounter a gas cap that had been suggested by the Mahogany-1 well – a positive development that implies the field could extend further updip. There were two well tests performed on the Mahogany-2 well with the first test at a rate of 5.2 kbpd of 36º API oil and 5.3 mmcfpd of associated natural gas, from a single zone covering 17 metres. This test was limited by the available test equipment and facilities with a 40/64-inch choke. The second test flowed at a rate of 4.5 kbpd of 39º API oil and 5.1 mmscf/d of associated natural gas on a 36/64-inch choke. Tullow believes that with 5.5-inch tubing development wells at Jubilee should be able to flow at 20 kbpd.


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Figure 8: Jubilee discovery appraisal programme


Figure 7: Jubilee discovery blocks - Deepwater Tano and West Cape Three Points


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Further exploration wells at Jubilee include Tweneboa on Deepwater Tano, which is expected to be drilled in early 2009, followed by the Teak prospect on WCTP. The Blackford Dolphin is currently drilling at Jubilee with the Eirik Raude expected to arrive in Nov 2008, and the Aban Abraham and Atwood Hunter in early 2009.

Figure 9: Tullow Oil - Near-term Ghana drilling programme 2008 2009 RIG Sep Oct Nov Dec Jan Feb Mar Apr May June

Blackford Dolphin Mobilisation Hyedua-2 + DST M-1 DST 2 x Jubilee Eirik Raude Mobilisation Mahogany-3 Tweneboa Multiple Jubilee wells Aban Abraham Teak Atwood Hunter Mahogany-4 Onyina

Mobilisation Appraisal DST Development Exploration Source: Company data

Lake Albert Rift Basin reaching critical mass In the Lake Albert Rift Basin, Tullow holds interests in Uganda of 50% of Block 1 (Heritage Oil 50%), 100% operated interest of Block 2 and 50% of Block 3 (Heritage Oil 50%). The company has also signed a production-sharing agreement in the DRC for a 48.5% operated interest in Blocks 1 (Heritage Oil 39.5%, COHYDRO 12%) and Block 2 (Heritage Oil 39.5%, COHYDRO 12%) that are contiguous to the Uganda Blocks. These blocks require a presidential decree and the validity of the award of these licences is currently being disputed by the Congolese Oil Ministry. Figures 10 and 11 illustrate Tullow’s holdings in the Lake Albert region.

Figure 10: Tullow Oil - Uganda licences Licence Fields Area, km2 Tullow interest Operator Shallow Water Tano 4,285 50.00% Heritage Deepwater Tano 3,900 100.00% Tullow West Cape Three Points 1,991 50.00% Heritage



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The Lake Albert Rift Basin, located in the Western Rift Valley of Uganda, was originally discovered with the Mputa and Waraga wells drilled in 2005. The Kingfisher-1 well, was drilled in March 2007 on Block 3A in Uganda. This well tested at 13,893 bpd from four intervals.

Subsequently, Heritage Oil has drilled the successful Kingisher-2 well on block 3A with a cumulative flow rate of 14,364 bpd from three reservoirs, which was constrained by equipment. The Kingfisher-3 appraisal well was spudded in September, with results expected in 1Q09.

Project sanction for a 4 kbpd early production system (EPS) on Block 2 is expected by year-end. The EPS is currently awaiting finalisation of commercial terms and environmental approval (expected in 4Q08), with first production from the Albert Basin as early as late 2009. It is expected that product will initially be limited to 2 kbpd in 2009, with product despatched by road tanker and potential for power sales in 2010 with 50 MW of local power generation. The EPS is expected to serve local requirements in Uganda.

Longer term, a full-scale commercial development in the Lake Albert region is contingent on proving up required resources in the range of 400 mmbbl to make pipeline construction from Uganda to the coast of Kenya (Mombasa) economic. Given exploration success to date, we believe there is a high probability that

Figure 11: Tullow Oil Lake Albert Basin interests


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resources will be sufficient to justify a pipeline with potential to prove up reserves sufficient for commercial development by year-end. First production from a larger-scale development could be as early as 2012 -2014, with capacity for flow rates of 140 kbpd-plus on a gross production basis. We note that Tullow plans to sell approximately a 50% stake in its Ugandan holdings prior to development.

Drilling on Block 1 in Uganda commenced in September with the successful Warthog exploration well with a gross hydrocarbon-bearing interval of approximately 150 metres, with 46 metres of net hydrocarbon pay. The Buffalo well is expected to be spudded in mid-November, followed by the Giraffe prospect.

Tullow owns 100% of Block 2 in Uganda, located, contiguous to Block 1 and Block 3A. The Kasamene-1 discovery, located on Block 2, 2.5 km south of Block 1 is believed to be on trend with the identified drilling prospects on Block 1 and encountered over 31 metres of net oil pay. Including the Kasamene-1 discovery,

Tullow has encountered oil in all the wells drilled in the Butiaba region, in the northern part of Block 2. The company recently completed drilling the Kigogole-1 prospect on Block 2 that encountered two zones with net pay of 10 metres. This well encountered oil just below 400 metres, the shallowest oil section in Uganda to date.

$1bn of divestiture proceeds to high-grade valuation creation Tullow has reached sales agreements for its interests in the M’Boundi field, in the Republic of Congo, and the Hewett-Bacton assets, in the UK North Sea. Total cash consideration for the sales is GBP428mn with the UK sale expected to close in 2008 and the M’Boundi sale subject to government approval. Tullow expects after tax proceeds of GBP370mn.

As announced on 10 June 2008, Tullow has signed a memorandum of understanding with Eni for the sale of 51.69% of the offshore Hewett Unit fields and related infrastructure, including the onshore Bacton terminal. Transaction value for the sale is GBP210mn.


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Tullow announced the sale of its 11% interest in the M’Boundi field, located onshore Republic of Congo, to the Korea National Oil Company for $435mn on 31 Jan 2008. Gross production from this asset was 37 kbpd when the deal was announced, implying a valuation metric of $106,880/daily flowing barrel, compared to other recent transactions in the Congo at 85,711/daily flowing barrel.

In 2008, Tullow has also sold its 40% interest in the Ngosso licence, offshore Cameroon, to MOL, and non-core CMS assets to Venture Production for a

Figure 12: Recent North Sea M&A transactions

Announced date Buyers Sellers Deal

level Key

characteristic Total

transaction value $mn

Proved+probable (2p) reserves total mmboe @6:1

Daily boe/d production EV/2P

EV/Daily Production

(boe) 27-Oct-08 Wintershall AG Revus Energy ASA Corporate Shallow Water 856 26 6,039 32.57 141,737 27-Oct-08 Electricite de France; EdF

International SA ATP Oil & Gas Corporation;

ATP Oil & Gas (UK) Ltd Asset Shallow Water 421 23 9,834 18.63 42,838 23-Oct-08 Grupa Lotos SA Det Norske Oljeselskap ASA Asset Shallow Water 58 7 - 8.70 - 29-Sep-08 Salamander Energy PLC Serica Energy plc Corporate Conventional 213 14 - 15.38 - 3-Sep-08 Total SA Talisman Energy Incorporated Asset Shallow Water 480 16 3,760 30.28 127,671 9-Jul-08 Centrica plc Marathon Oil Corporation Asset Shallow Water 375 14 7,000 26.79 53,571 19-Jun-08 Endeavour International Corp Ithaca Energy Inc Corporate Shallow Water 306 26 - 11.94 - 10-Jun-08 XTO Energy Incorporated Hassie Hunt Exploration Co;

Hunt Petroleum Corporation Corporate Diversified 4191 - 43,633 - 96,060

2-Jun-08 DONG Energy A/S Svenska Petroleum Exploration AB Asset Shallow Water 130 13 1,950 10.00 66,667

20-May-08 Grupa Lotos SA Revus Energy ASA Asset Shallow Water 53 7 - 7.84 - 25-Apr-08 Norwegian Energy Company Talisman Energy Incorporated Asset Shallow Water 94 4 3,750 21.61 25,067 18-Mar-08 Silverstone Energy Ltd Granby Oil & Gas plc Corporate Shallow Water 57 2 - 23.18 - 15-Feb-08 Centrica plc Sojitz Corporation Asset Shallow Water 70 5 - 13.13 - 19-Dec-07 Petroliam Nasional Berhad Star Energy Group Plc Corporate Conventional 510 14 2,400 36.21 212,725 5-Dec-07 Revus Energy ASA Palace Exploration Company Asset Shallow Water 258 14 4,060 17.92 63,547 14-Nov-07 Petroliam Nasional Berhad Star Energy Group Plc Corporate Conventional 493 14 2,400 34.96 205,380 17-Sep-07 Centrica plc Newfield Exploration Company Asset Shallow Water 486 50 5,049 9.73 96,336 16-Aug-07 Oilexco North Sea Ltd; Oilexco

Incorporated Canadian Natural Resources

Ltd Asset Shallow Water 50 2 1,800 25.70 27,778 2-Aug-07 EON AG Royal Dutch Shell plc Asset Deepwater 893 108 - 8.29 - 19-Jul-07 ArcLight Capital Partners LLC;

3i Group Venture Production plc Corporate Shallow Water 534 44 8,356 12.17 63,856 14-May-07 Norwegian Energy Company Altinex ASA Corporate Conventional 1060 45 8,356 23.51 126,881 19-Mar-07 DONG Efterforskning og

Produktion A/S ConocoPhillips Asset Shallow Water 300 37 - 8.00 -

16-Mar-07 Bow Valley Petroleum (UK) Limited; Bow Valley Energy Ltd Exxon Mobil Corporation Asset Deepwater 67 13 - 5.16 -

2-Mar-07 Polskie Gornictwo Naftowe i Gazownictwo SA Exxon Mobil Corporation Asset Deepwater 360 57 - 6.34 -

6-Feb-07 Stratic Energy Corporation Grove Energy Ltd Corporate Conventional 99 14 - 6.85 - 25-Jan-07 Premier Oil plc Hess Corporation Asset Shallow Water 60 13 4,000 4.73 15,025 16-Jan-07 TAQA Talisman Energy Incorporated Asset Shallow Water 550 34 19,000 16.18 28,947 31-Dec-06 Icahn Management LP Institutional Investors; Talisman

Energy Incorporated Corporate Conventional 82 109 - 0.75 - 18-Dec-06 StatoilHydro ASA Norsk Hydro ASA Corporate Shallow Water 32192 - 560,401 - 57,445 13-Dec-06 Dana Petroleum plc Ener Petroleum ASA Corporate Shallow Water 192 12 5,807 16.40 33,046 28-Nov-06 TAQA BP plc Asset Conventional 694 50 - 13.96 - 28-Nov-06 Dana Petroleum plc GDF Suez SA Asset Shallow Water 55 5 2,833 11.38 19,412 1-Aug-06 Venture Production plc CH4 Energy Ltd Corporate Shallow Water 286 31 3,667 9.34 78,135 14-Jul-06 Ener Petroleum ASA Royal Dutch Shell plc Asset Shallow Water 57 12 5,807 4.84 9,747 26-May-06 Endeavour International Corp Talisman Energy Incorporated Asset Shallow Water 414 18 8,812 23.00 46,981 11-May-06 Altinex ASA Denerco Oil A/S Corporate Shallow Water 377 23 10,009 16.69 37,685 3-Mar-06 Centrica plc BP plc; Britoil plc Asset Shallow Water 266 25 - 10.50 - 12-Feb-06 Nippon Oil Corporation BP plc Asset Shallow Water 266 25 - 10.50 -

------------------------------------------------ Median ------------------------------------------------------ 293 15 5,807 12.65 57,445 ------------------------------------------------Average------------------------------------------------------ 1261 26 31,684 15.37 72,893

Source: J.S. Herold, Renaissance Capital estimates

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consideration of GBP35mn (the transaction was completed in June). The company saw a GBP28.9mn profit on the sale of these assets in 1H08.

The proceeds from the sales are expected to be allocated to funding capex for developments at an earlier stage, particularly Jubilee and the Lake Albert Rift Basin where there is potential for significant valuation creation.

Production exceeding expectations in Equatorial Guinea Tullow has interests in two production licenses, offshore EG at the Ceiba field, and the Okume Complex. The company owns 14.25% stakes in each asset with Hess as the operator (see Figure 13).

Figure 13: Tullow Oil – Equatorial Guinea licences Licence Fields Area, km2 Tullow interest Operator Other partners Ceiba Field Ceiba 70 14.25% Hess GEPetrol Okume Complex Okume, Oveng, Ebano & Elon 192 14.25% Hess GEPetrol


Equatorial Guinea accounted for 22% of total company production in 1H08, with total production of 15.4 kbpd net to Tullow. Development drilling is ongoing at Okume, with further drilling at Ceiba under review.

Figure 14: Tullow Oil Equatorial Guinea interests



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Gabon production to remain steady Tullow has interests in 16 licences in Gabon, with 12 producing fields. Figures 15 and 16 show the company’s interests in Gabon

Figure 15: Tullow Oil – Gabon licences Licence Fields Area, km2 Tullow interest Operator Other partners Avouma Avouma 52 7.50% Vaalco Addax, Sasol, Sojitz, PetroEnergy Azobe 1,737 60.00% Tullow MPDC Gabon Echira Echira 76 40.00% Perenco Etame Etame 49 7.50% Vaalco Addax, Sasol, Sojitz, PetroEnergy Gryphon Marin 9,764 18.75% * Forest PetroSA Kiarsseny Marin 5,442 47.50% Tullow Addax, Sonangol P&P Limande Limande 10 40.00% Perenco Niungo Niungo 96 40.00% Perenco Nziembou 1,027 40.00% Perenco Oba Oba 44 5.00% Perenco AIC Petrofi Obangue Obangue 40 3.75% Addax AIC Petrofi Tchatamba Marin Tchatamba Marin 30 25.00% Marathon Oranje Nassau Tchatamba South Tchatamba South 40 25.00% Marathon Oranje Nassau Tchatamba West Tchatamba West 25 25.00% Marathon Oranje Nassau Tsiengui Tsiengui 26 3.75% Addax AIC Petrofi Turnix Turnix 18 27.50% Perenco Arouwe 4,414 7.50% Perenco AIC Petrofi Azobe 1,737 5.00% Tullow MPDC Gabon, AIC Petrofi Dussafu Marin 2,780 5.00% Harvest Nat. Res AIC Petrofi, Perenco, Premier Ebouri Ebouri 15 7.50% Vaalco Addax, Sasol, Sojitz, PetroEnergy Etame Marin 2,972 7.50% Vaalco Addax, Sasol, Sojitz, PetroEnergy Etekamba 773 5.00% Maurel & Prom Transworld, AIC Petrofi Gryphon Marin 9,764 10.00% Forest PetroSA Maghena 631 3.75% Addax AIC Petrofi Nyanga Mayombe 2,831 3.75% Maurel & Prom AIC Petrofi Ombena 5,981 5.00% Perenco AIC Petrofi Omoueyi 4,133 7.50% Maurel & Prom AIC Petrofi Onal Onal 46 7.50% Maurel & Prom AIC Petrofi


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Gabon accounted for 19% of total company production in 1H08, with total net production of 13.1 kbpd. There are 35 development wells scheduled for 2008 on the Ebouri, Tsiengui, Obangue and Onal fields, and oil production is expected to be maintained, with the Onal and Ebouri fields due to come on stream at YE08.

There is also additional potential in Gabon for Tullow, with the company owning back-in rights to a number of exploration licenses, equating to approximately 40% of Gabon’s licensed acreage. A number of near-term exploration wells are expected to be drilled on these blocks, including on the Etame Block (Vaalco operator) where Tullow has a 7.5% back-in right. 2009 drilling in Gabon has gross upside potential of 100 mmbbl, with Tullow owning interests ranging from 7.5-60% on the respective blocks.

Figure 16: Tullow Oil interests in Gabon



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Cote d’Ivoire production increase in 2009 with FPSO upgrade Tullow’s interests in Cote d’Ivoire include offshore producing assets from the East and West Espoir fields on Block CI-26 where the company owns a 21.33% interest (Canadian Natural Resources operator, 58.67%; see Figures 17 and 18).

Figure 17: Tullow Oil – Cote d'Ivoire licences Licence Fields Area, km2 Tullow interest Operator Other partners CI-26 Special Area "E" East Espoir & West Espoir 139 21.33% CNR PETROCI CI-102 865 31.50% Edision Kufpec, PETROCI CI-103 2603 85.00% Tullow PETROCI CI-105 2070 22.37% Al Thani PETROCI


The CI-26 Special Area E accounted for 9% of total company production in 1H08, with respective total gross production rates of 30.4 kboepd and 6.5 kboepd net to Tullow. Production rates are currently restricted by facilities constraints, with an FPSO upgrade project expected to increase capacity to 70 kbpd and 80 mmscfd in 2H09.

The company’s remaining interests in Cote d’Ivoire are offshore exploration blocks, including CI-102 and CI-103, where there is potential in the conventional Albian play; as well as younger channel and fan systems similar to the Mahogany/Hyeuda complex. In 2009, Tullow also expects to drill a well on Block CI-105.

Mauritania production uplift Tullow’s producing interests in Mauritania comprise a 19.01% stake in PSC – Area B Chinguetti EEA. Potential development interests Banda, Tiof and Tevet are located on PSC – Area A, where Tullow owns a 24.3% interest and in PSC – Area B, where it owns a 21.6% interest. Mauritania assets accounted for 3% of total company production in 1H08. The company also owns a number of exploration interests in Mauritania (see Figures 19 and 20).

Figure 18: Tullow Oil interests in Cote d’Ivoire


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Figure 19: Tullow Oil – Mauritania licences Licence Fields Area, km2 Tullow interest Operator Other partners Block 1 3,936 38.00% Dana GDF, Roc Oil Block 2 4,898 83.78% Tullow* Dana, Roc Oil PSC - Area A Block 3 Blocks 4 & 5 shallow

Banda 6,969 24.30% Petronas Premier, Kufpec, Roc Oil

PSC - Area B Blocks 4 & 5 deep Tiof, Banda Tevet 8,028 21.60% Petronas Premier, Kufpec, Roc Oil PSC - Area B Chinguetti EEA Chinguetti 929 19.01% Petronas SMH, Premier, Kufpec, Roc Oil Block 6 4,023 22.42% Petronas Roc Oil Block 7 6,676 16.20% Dana Petronas, GDF, Roc Oil Block 8 7,875 18.00% Dana GDF, Wintershall, Roc Oil


The Chinguetti Field, located in PSC – Area B, is the first oil development offshore Mauritania – a Miocene field, discovered in 2001. Chinguetti production volumes increased to 17 kbpd as at 17 Oct 2008, relative to a 1H08 rate of 10 kbpd with the completion of phase two development work.

Figure 20: Tullow Oil interests in Mauritania



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The Chinguetti field came onstream in Feb 2006 at the targeted production rate of 75 kbpd. Subsequent to initial production, rates fell significantly to the 10 kbpd level and gross proved plus probable (2P) reserves are now estimated to be in the region of 50 mmbbl, vs original expectations of about 123 mmbbl. Petronas took over as operator of the field from Woodside in Dec 2007, and Phase 2B drilling has now been completed with two further development wells and three well interventions (workovers).

Two potential oil discoveries can also be tied back to the Chinguetti FPSO: 1) the Tiof Miocene oil and gas field, discovered in 2003, with potential for 500 mmbbl of stock tank oil initially in place (STOIIP), and up to 50 mmbbl being developed in the first phase (based on industry estimates); and 2) the Tevet Miocene Oil field, discovered in 2004, with potential for up to 100 mmbbl of STOIIP (as estimated by Petronas).

Other discoveries on PSA A and PSC B include: 1) the Banda Miocene Gas field, discovered in 2002, with natural gas reserves estimated in the 1-2 TCF range and a significant oil leg; and 2) the subeconomic Labeidna Miocene Oil field discovery.

Namibia In Namibia, Tullow holds a 70% operating licence on Production Licence 001, where the Kudu Gas Field is located. The initial development plan for Kudu was to supply natural gas to a 800 MW power station developed and operated by NamPower, with excess electricity supplied to the South African market. As a result of delays in commercial arrangements for the gas-to-power development, alternative options for development are being considered, including a compressed natural gas project to supply gas into regional industrial and transport markets as a replacement for diesel, HFO and LGP.

Significant exploration potential in Africa

Tullow continues to participate in a significant exploration programme throughout Africa, particularly in Uganda, Ghana, Cote d’Ivoire and Mauritania. Figure 17 illustrates near-term exploration prospects for the company.

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Other exploration in Africa In Africa, Tullow is pursuing purely exploration prospects in: 1) offshore Angola, where two commitment wells are planned for 1H09; 2) onshore Madagascar, where the company operates two licenses; 3) offshore Senegal, with the St. Louis Licence that is contiguous to Mauritania Block 1; and 4) in Tanzania, where the company operates two licences and is scheduled to drill two oil wells in 1H09. The licences in Tanzania are adjacent to the Mnazi Bay gas field, which is currently being developed by Artumas.

UK North Sea Production in the North Sea has been disappointing in 2008, leading to overall reductions in company production guidance for the year. The North Sea accounted for 33% of total company production in 1H08, and is 100% natural gas-weighted. Figure 22 illustrates Tullow’s UK North Sea assets.

Figure 21: Tullow Oil - 12 M exploration programme Country Licence/ Block Prospect/ Campaign Interest Gross upside Date/ Status Europe Netherlands SNS Prospect 20-50% 10 mmbo 4Q09 Africa Ghana Jubilee Field Jubilee Exploratory Appraisal 22.9-49.95% 1,000 mmbo 3Q08/3Q/4Q 2009 Ghana Deepwater Tano Tweneboa/Onyina/Owo Prospect 49.95% 900 mmbo 4Q08/3Q09 Ghana West Cape Three Points Teak Prospect 22.90% 750 mmbo 1Q09 Ghana Shallow Water Tano Ebony Prospect 31.50% 35 mmbo 4Q08 Côte d’Ivoire CI-105 Prospect 22.37% 200 mmbo 2Q09 Uganda Block 1 and 2 Butiaba Campaign 50% - 100% 1,000 mmbo 3Q08/4Q09 Uganda Block 2 Ngassa Prospect 100% 600 mmbo 4Q08/1Q09 Uganda Block 3A Kingfisher Prospect 50% 200 mmbo 3Q/4Q08 Uganda Block 3A Pelican Propect 50% 200mmbo 4Q09 Mauritania PSC A & B Block 7 Campaign 16.2& - 24.3% 500 mmbo 1Q/2Q09 Tanzania Lindi & Mtwara 2 Prospects 50% 250 mmbo 1Q/2Q09 Gabon Etame/Azobe/Gryphon/ Kiarsseny Campaign 7.5%-60% 100 mmbo 1Q-4Q09 South Asia India CB-ON/1 Campaign 50% 150 mmbo 3Q08/1Q09 Pakistan Kohat Prospects 40% 50 mmbo 1Q09 South America Suriname Coronie/Uitkijk Campaign 40% 250 mmbo 3Q/4Q08/4Q09 French Guiana Guyane Maritime Matamata Prospect 97.50% 850 mmbo 2009



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Figure 22: Tullow Oil North Sea interests Licence Blocks Fields Tullow interest Operator Other partners North Sea P450 44/21a Boulton B&F 9.50% ConocoPhillips GDF

44/22a Murdoch P451 44/22b Boulton H, Watt 34.00% ConocoPhillips GDF 44/23a P452 (part) Murdoch (K) 6.91% ConocoPhillips GDF

P453 44/28b Ketch 100.00% Tullow P516 44/26a Schooner 97.05% Tullow GDF P847 49/2b 15.00% GDF RWE P1006 44/17b Munro 20.00% GDF ConocoPhillips P1013 49/2a 25.00% GDF RWE

44/18b, P1058 44/23b Kelvin 22.50% ConocoPhillips GDF P1139 44/19b 22.50% ConocoPhillips GDF

E.ON, P1437 44/13a 25.00% GDF Endeavour 44/17a Boulton H, 14.10% 44/17c Hawksley, 44/21a McAdam, 44/22a Murdoch K, 44/22b Watt 44/22c

CMS III Unit

44/23a

ConocoPhillips GDF

44/17b Murdoch Unit 44/17a Munro 15.00% ConocoPhillips GDF 44/26a Schooner Unit 43/30a Schooner 90.35% Tullow Faroe Petr., GDF

North Sea Thames - Hewett Area 49/24F1(part) 100.00% Tullow

(Excluding Gawain)

P007

49/24F1(part)

Gawain

50.00% Perenco

P028 48/30a, 52/5a Hewett 53.24% Tullow Eni 48/28a, 48/29a Hewett 49.84% Perenco Eni 49/28a, 49/28b Thames, Yare, 66.67% Perenco Centrica

Bure, Deben, Wensum, Thurne*

49/28d

P037

66.67% Perenco Centrica 53/4a Welland** 75.00% Tullow First Oil P039 53/4d Wissey 62.50% Tullow First Oil, Faroe Petr.

P060 50/26a Orwell 100.00% Tullow P105 49/29a(part) Gawain 50.00% Perenco P112 52/4a Hewett 52.39% Tullow Eni, Perenco

53/3a 45.00% BG Dyon P133 53/3a P4 35.00% BG Dyon P786 53/3c Horne 50.00% Tullow Centrica P852 53/4b Horne & Wren 50.00% Tullow Centrica

48/28c 52/3a 52/4b P1445 52/5b

100.00% Tullow

49/24F1 (part) Gawain Unit 49/29a (part) Gawain 50.00% Perenco 48/28a, 48/29a, Hewett Deborah,

48/30a (part) Della, Delilah Hewett Unit 52/4a, 52/5a

51.69% Tullow Eni, Perenco

49/29b (part) Welland Unit 53/4a Welland** 33.73% ExxonMobil First Oil North Sea - Central North Sea P477 16/13c 6.25% ConocoPhillips Maersk, BG, Endeavour, Global Santa Fe P1045 16/18b 6.25% ConocoPhillips Maersk, BG, Endeavour, Global Santa Fe


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In 1H08, production from the Thames Hewett Area was 51 mmscfpd – down 27% YoY on 1H07 – due to natural field declines, mainly at the Orwell and Thurne fields. Poor weather also constrained production efficiency.

In the Caister Murdoch System Area, production averaged 86 mmscfd in 1H08, representing a decline of 6% YoY, due to lower capital allocation. Additionally, declines at the Kelvin field have been faster than predicted. UK exploration activity is concentrated on the core CMS Area.

The company also holds North Sea exploration assets in The Netherlands, with potential drilling in 2009, and Portugal, where the company is acquiring seismic data.

South Asia growth in Bangladesh Tullow’s interests in South Asia include producing natural gas assets onshore Bangladesh at the Bangora field on Block 9, where the company owns a 30% operated interest. The Bangora field produced 21 mmcfpd net to Tullow in 1H08, accounting for 5% of total company production. This field is expected to increase gross production to 100 mmscfd once the Bangora-3 well is tied-in in Sep 2008. The company also holds a 32% interest in exploration blocks, Block 17 and Block 18 offshore Bangladesh.

Pakistan production assets are located onshore at Chachar and Sara/Suri, with 11 mmcfpd production in 1H08 net to Tullow, accounting for 3% of total company production.

Assets in India are onshore exploration blocks CB/ON-1, where the company holds a 50% interest, and AA-ONJ/2, where Tullow holds an operated 60% interest (ONGC). Exploration is focused on CB/ON-1.

Latin America exploration All Tullow’s assets in French Guiana, Suriname and Trinidad and Tobago are exploration-focused. In Suriname, a second exploration phase on near-infrastructure targets is scheduled to commence in 3Q08.

Less likely acquisition target than African E&P peers Given Tullow’s enterprise value of $5,615mn, the diversity of the company’s asset base, and the fact that most of the company’s assets are non-operated, we think Tullow is less likely to be acquired than many other companies in our Africa oil and gas universe. However, we think any acquisition of Tullow would likely be motivated by the company’s recent operated discoveries at Jubilee offshore Ghana and at Lake Albert in Uganda/DRC. However, Tullow has publicly stated that it plans to divest 50% of its holding in the Lake Albert region prior to development.


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Tullow Oil’s capital structure is illustrated in Figure 23.

Figure 23: Tullow Oil capital structure as at 30 June 2008 Share structure Amount

Basic shares 724,768,338 Stock options 10,507,830

Fully diluted shares outstanding 735,276,168 Sources of capital Amount, $mn

Long-term debt 552 Cash & cash equivalents 131

Shareholders' equity 585 Source: Company data, Renaissance Capital estimates

Balance sheet, capex, hedging and future funding needs Capex for 2008 are estimated at GBP480mn, with 2009 capex projected to rise to approximately GBP567mn.

The company is currently paying an interim dividend of GBP0.02/share.

Tullow currently has oil hedges in place for 2H08 of 18 kbpd at $70.85/bbl; for 2009 of 11.5 kbpd at $66.28; and for 2010 5 kbpd at $112.65/bbl. Natural gas hedges for 2H08 are 65.2 mmscfd at GBP0.554/therm, for 2009; 44.9 mmscfd at GBP0.559/therm, for 2010 16.6 mmscfd at GBP0.607/therm; and 3.1 mmscfd at GBP0.71/therm.

Tullow plans a significant refinancing in 4Q08, with about $2bn of capacity.

Figures 24 and 25 indicate Tullew’s net debt-to-cash flow and plough-back ratios.

Capital structure

Figure 24: Tullow Oil net debt to cash flow from operations, GBPmn

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Figure 26: Tullow Oil 2P reserves

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Figure 27: Tullow Oil 2P plus contingent reserves

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Reserves and resources As of the last reserve report of 30 June 2008, reserves consisted of total proved plus probable (2P) reserves of 184.2 mmboe (68% oil, 32% natural gas), with 2P plus contingent resources of 536.3 mmboe (53% oil, 47% natural gas). Total 2P plus contingent African gas resources are 1,033.9 bcf. Contingent resources include the Jubilee field discovery wells, Hyedua-1 and Mahogany-1 in Ghana, and a limited area around the Kingfisher-1 well in Uganda.

Figure 28:Tullow Oil F&D/Reserve replacement (net, 2P) 2005 2006 2007 3-year average

Organic F&D (including revisions) ($/bbl) 14.08 28.76 168 25.63 All-in F&D (FD&A) ($/bbl) 17.42 33.68 168 32.06

Organic reserve replacement (including revisions), % 118% 89% 17% 71% All-in reserve replacement (including revisions), % 189% 216% 17% 134%


Figure 25 Tullow Oil plowback ratio

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We value Tullow Oil using a DCF-derived NAV methodology that includes value for proved plus probable (2P) reserves for producing assets, and value for developments at Jubilee in Ghana and Block 3A in Uganda, as well as prospective resources mainly comprising deepwater Ghana and Block 1 and Block 2 in Uganda. Tullow 2P reserves include only 35 mmbbl in Uganda and no reserves in Ghana. Contingent resources include 80 mmboe in Ghana.

Our target price of BPN600/share equates to: 10.1x 2009E and 10.6x 2010E P/CF; 9.5x 2009E and 9.7x 2010E EV/EBITDA; and 27.7x 2009E and 24.2x 2010E P/E and $105,370 per daily 2009 flowing barrel and $39.50/2P bbl, excluding African natural gas reserves. Based on 2P plus contingent resources, our target price implies $6,65/bbl, excluding African natural gas.

On our estimates, the company is currently trading at 7.7 2009 and 8.0 2010 P/CF, 7.4 2009E and 7.5 2010 EV/EBITDA; 20.9x 2009E and 18.3x 2010E P/E, 81,330 per daily flowing barrel and $30.49/2P bbl (excluding Africa natural gas). This represents a premium to Tullow’s peers, given the company’s significant non-producing asset value. Global E&P peers are trading at 4.2x 2009E and 3,76x 2010E P/CF, 3,51x 2009E and 3,12x 2010E EV/EBIDA, 7,80x 2009E and 5,49x 2010E P/E, $60,336 per daily flowing barrel and $13.41/2P boe.

Valuation

Figure 29: TLW - net asset valuation summary NAV, $mn Per share, $ NAV, GBPmn BPN % of value share

Production & development EG 947 1.31 604 83.38 11% Gabon 471 0.65 301 41.52 6% UK 559 0.77 357 49.20 7% Cote D'Ivoire 361 0.50 230 31.80 4% Mauritania 149 0.21 95 13.17 2% Bangladesh 38 0.05 25 3.39 0% Pakistan 11 0.02 7 0.99 0% Production NAV 2,537 3.50 1,619 223.44 30% Appraisal & development Ghana 2,112 2.91 1,348 186.02 25% Uganda Block 3A 1,209 1.67 772 106.49 14% Production NAV 3,321 4.58 2,120 292.52 40% Prospective resources Uganda Block 1, Block 2 1,688 2.33 1,077 148.63 20% Ghana deep water (ex.Jubilee) 497 0.69 317 43.78 6% UK 65 0.09 41 5.69 1% Cote D'Ivoire 54 0.07 34 4.73 1% French Guiana 41 0.06 26 3.65 0% Mauratania 41 0.06 26 3.57 0% Netherlands 35 0.05 22 3.08 0% Tanzania 25 0.03 16 2.20 0% Suriname 25 0.03 16 2.20 0% Pakistan 16 0.02 10 1.41 0% Ghana shallow water 13 0.02 8 1.17 0% Gabon 13 0.02 8 1.10 0% Best estimate risked prospective resources NAV 2,512 3.47 1,603 221.21 30% Total 8,369 11.55 5,343 737.17 100% Liabilities Long-term debt 592 0.82 378 52.18 -7% Less cash 287 0.40 183 25.30 4% Net debt 305 0.42 195 26.88 -4% Current net asset value 8,064 11.13 5,148 710.29


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The major risks to Tullow, in our view, include development and execution risk at the Jubilee discovery, as the company’s first operated deepwater asset; as well as government or business corruption, and uncertainty about the interpretation and application of foreign laws and regulations. A transportation solution for the Lake Albert discovery is also a key risk for the company, as is rebel activity in DRC.

Risks inherent in the global oil and gas business include the volatility of oil and natural gas pricing; currency risk; cost inflation for materials and services; geological risk; operating hazards; access to supplies and equipment; access to drilling rigs and experienced trades; geopolitical risk and unforeseen weather conditions that can affect drilling programmes. Other risks include potential changes to existing royalty regimes, regulatory environments, political regimes and environmental considerations.

Key risks


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Tullow was founded by Aidan Heavy, its current CEO, in 1985, and a licence was subsequently signed in Senegal, with natural gas production and sales commencing in 1987. In 1989, the company listed on the London and Irish stock exchanges, and secured its first licenses in the UK (onshore).

In 1990, Tullow signed its first licence agreement in Pakistan, entering South Asia, and discovered the Sara gas field in Pakistan in 1994 (this was brought on stream in 1999). In 1996, Tullow acquired licences in Bangladesh and Cote d’Ivoire, marking the company’s entry into Africa, and included the Espoir fields where first production occurred in 2000.

In 2000, Tullow made its first major acquisition, with the GBP200mn purchase of producing gas fields and related infrastructure in the UK Southern North Sea from BP. In 2004, the company acquired Energy Africa for $570mn, creating critical mass for Tullow in Africa. The same year, the company acquired the Schooner and Ketch producing assets, in the CMS area of the North Sea, for GBP200mn, from Shell and ExxonMobil.

Company background

Figure 30: TLW event chart—company history

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30 June 2004: Entered into an agreement with ChevronTexaco to acquire its 50% equity in licence containing Orwell gas field located near the Anglo-Dutch median line

1 Dec 2003: Purchased a 23.3% stake in Thames gas fields & associated licence interest, P037 (Block 49/28)

2 Aug 2004: Acquires Energy Africa Limited & 50% of Energy Africa Gabon for total consideration of $570mn

16 Aug 2004: Acquires 15% working interest in Gryphon project in southern Gabon offshore

1 Apr 2005: Completes the acquisition, from Shell U.K. Limited and Esso Exploration and Production UK Limited, of their entire producing interests in Schooner and Ketch gas fields and associated acreage

16 Sep 2008: Tullow announces G1 well located in Block CB-ON/1 onshore India, has been plugged and abandoned

4 Apr 2007: Tullow agrees to sell a 20% interest in Namibia Production Licence No. 001, containing Kudu gas field, to Itochu Corporation

6 Jan 2006: Tullow concludes a farm-in agreement with Ocean Angola Corporation to assume 15% interest in Block 24

2 Oct 2003: Tullow's subsidiary, Tullow Oil UK Ltd, assumes operatorship & increases interest in Hewett gas field complex, export pipelines and associated onshore processing terminal at Bacton on East Anglian coast

11 Nov 2005: Tullow concludes a farm-in agreement with Sonangol P&P to assume 15% interest in Block 10 offshore Angola

20 Dec 2006: Announces shareholders of Harmdan Resources Ltd. have approved acquisition of Hardman by Tullow

31 Jan 2008: Announces the sale of its 11% interest in onshore M'Boundi field in Congo for $435mn

3 Apr 2008: Agrees to sale of its interests in 10 CMS Area blocks for GBP35mn

10 Jun 2008: Signs a MoU with Eni for the sale of its 51.69% interest in the offshore Hewett Unit fields for £210mn

27 Aug 2008: Appoints Ian Springett CFO

21-Oct 2008: Tullow announces successful exploration well Warthog-1 in Uganda, operated by Heritage Oil, in which they hold a 50% stake



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Board of directors and senior management profiles Patrick Plunkett, chairman

Pat Plunkett (57) joined the board as a non-executive director in 1998, and was appointed as non-executive chairman in 2000. He is also chairman of the Tullow’s nominations committee and a member of its remuneration committee. Plunkett is an accountant, with more than 30 years’ experience in the financial services sector, and is a former director of the Irish Stock Exchange. He managed the stockbroking and corporate finance businesses of ABN AMRO Bank in Ireland from 1993 to 1998. Since then, he has provided strategic advice and non-executive director services to a number of private companies.

Aidan Heavey, CEO

A founding director and shareholder of the company, Aidan Heavey (55) has played a key role in Tullow’s development, since its formation in 1985. Heavey is a chartered accountant, and previously held roles in the airline and engineering sectors in Ireland. He is a member of Tullow’s nominations committee.

Heavey is also a director of Traidlinks, an Irish-based charity established to develop and promote enterprise and diminish poverty in the developing world, particularly Africa.

Ian Springett, CFO

A chartered accountant, Ian Springett (50) was appointed as Tullow’s CFO and admitted to its board on 1 Sep 2008. Prior to joining Tullow, he worked with BP for 23 years, gaining considerable international oil and gas industry experience. Most recently, Springett worked as Tullow’s group vice-president for planning, reporting to the CEO and executive team. He also held a number of other senior positions at BP, including upstream CFO, commercial director of BP’s supply and trading business, and vice-president for finance in the US (where he led the group treasury function and was simultaneously BP’s CFO in the Americas). Before joining BP, Springett worked with Coopers and Lybrand between 1979 and 1985.

Angus McCoss, exploration director

Angus McCoss (46) was appointed to the board in Dec 2006, having joined Tullow in Apr 2006 as general manager, exploration. A geologist. McCoss has 20 years of wide-ranging exploration experience, working primarily with Shell in Africa, Europe, China, South America and the Middle East. He has held a number of senior positions at Shell, including Americas regional vice-president, exploration, and ultimately general manager of exploration throughout onshore and offshore Nigeria.

Paul McDade, COO

Paul McDade (44) was appointed to the board in Mar 2006. He joined Tullow in 2001, and was appointed as COO following the Energy Africa acquisition in 2004, having previously managed Tullow’s UK gas business. An engineer with over 20 years’ experience, he has worked in various operational, commercial and management roles with Conoco, Lasmo and ERC. He has broad international experience, having worked in the UK North Sea, Latin America, Africa and South East Asia; and holds degrees in civil engineering and petroleum engineering.


176

Graham Martin, general counsel and company secretary

Graham Martin (54), a solicitor, joined Tullow as legal and commercial director in 1997, from international law firm Vinson & Elkins, where he was a partner. Prior to that, Martin was a partner in Dickson Minto WS, a UK corporate law firm. He has over 25 years’ experience of UK and international corporate and energy transactions. He has been the principal legal adviser to Tullow since its formation in 1985, and was appointed to his current position as general counsel in 2004. Martin also recently assumed the role of company secretary.

Clare Spottiswoode CBE, non-executive director

Clare Spottiswoode (55) was appointed as a non-executive director in 2002. She is chairman of Tullow’s remuneration committee, and a member of its audit and nominations committees. A mathematician and an economist by training, Spottiswoode began her career at the Treasury, before starting her own software company. Between 1993 and 1998, Spottiswoode was director general of Ofgas, the UK gas regulator. She chairs Gas Strategies Limited, and also a non-executive director of Bergesen ASA. In Nov 2006, Spottiswoode became policyholder advocate for Aviva plc. Previously, she was deputy chairman of British Energy from 2002 to 2007. In 1999, she was awarded a CBE for services to the gas industry, and holds an honorary doctorate of social sciences from Brunel University (UK).

Steven McTiernan, senior independent director

Steven McTiernan (56) was appointed as a non-executive director in 2002, and senior independent director on 1 Jan 2008. He is a member of Tullow’s audit, nominations and remuneration committees. McTiernan began his career as a petroleum engineer, working with BP, Amoco and Mesa in the Middle East and UK. In 1979, he joined Chase Manhattan Bank, where he became senior vice-president and head of the bank’s energy group, based in New York. From 1996 to 2001, he held senior energy-related positions at NatWest Markets and then CIBC World Markets. He is currently principal of Sandown Energy Consultants Limited, a natural resources advisory firm, based in London.

David Bamford, non-executive director

David Bamford (61) was appointed as a non-executive director in July 2004. He is a member of Tullow’s audit, nominations and remuneration committees. With a PhD in geological sciences from the University of Birmingham (UK), Bamford has more than 23 years’ exploration experience with BP, for which he was chief geophysicist from 1990 to 1995, general manager for West Africa from 1995 to 1998, and vice-president, exploration (directing BP's global exploration programme) from 2001 to 2003. He is a non-executive director of Paras Limited, a specialist oil and gas industry consulting firm.

David Williams, non-executive director

David Williams (62) was appointed as a non-executive director in 2006. He is chairman of the company’s audit committee and a member of its nominations and remuneration committees. A chartered accountant, Williams has extensive public company experience prior to his time at Tullow, following many years with Bunzl plc, where he was finance director until he retired in 2006; and prior to that as finance director of Total Group plc. He is a non-executive director, and a senior independent


177

director of both Taylor Wimpey plc and Mondi plc. He is also a non-executive director of Meggit PLC and Dubia-quoted DP World Limited. Williams was a non-executive director of The Peninsular and Oriental Steam Navigation Company until its acquisition in 2006.

Ann Grant, non-executive director

Ann Grant was appointed as a non-executive director in May 2008, and is a member of Tullow’s audit, nominations and remuneration Committees. She is currently senior adviser on Africa and development issues to Standard Chartered Bank. Grant has had an extensive diplomatic career with the British Foreign and Commonwealth Office, including more than four years as British High Commissioner to South Africa. She chairs the Banking Working Group of the Commonwealth Business Council, and is a Council Member of the Overseas Development Institute, the UK Disasters Emergency Committee and the Institute of Public Policy Research.


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Share-price sensitivity tables Figure 31: Tullow Oil net asset value sensitivity

LT Brent oil price ($/bbl) $59.56 40 45 50 55 60 65 70 75 80 85 90 95 100 15% 498 521 543 566 588 611 633 656 679 701 724 746 769 14% 522 545 569 592 616 640 663 687 711 734 758 782 805 13% 548 573 597 622 647 672 696 721 746 771 795 820 845 12% 577 603 629 655 681 707 733 759 785 811 837 863 889 11% 609 637 664 691 719 746 773 801 828 855 883 910 937 10% 646 675 703 732 761 790 818 847 876 904 933 962 991 9% 687 717 747 778 808 838 869 899 929 959 990 1020 1050

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8% 733 765 797 829 861 893 925 957 989 1021 1053 1085 1116 Source: Renaissance Capital estimates

NAV sensitivity


179 179

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Disclosures appendix

180

November 2008 Africa oil and gas

Renaissance Capital equity research distribution ratings Investment Rating Distribution Renaissance Capital Research Oil and gas Buy 149 33% Buy 18 64% Hold 76 17% Hold 3 11% Sell 32 7% Sell 3 11% UR 35 8% UR 3 11% NR 162 36% NR 1 4% 454 28 Investment Banking Relationships* Renaissance Capital Research Oil and gas Buy 6 46% Buy 0 0% Hold 4 31% Hold 0 0% Sell 2 15% Sell 0 0% UR 1 8% UR 0 0% NR 0 0% NR 0 0% 13 0

* Issuers from which Renaissance Capital has received material compensation within the past 12 months. NR – Not Rated UR – Under Review

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Head of Africa Research Matthew Pearson

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Infrastructure & Transportation + 7 (495) 662 5607 Paul Roger [email protected] Artur Galimov Banking + 7 (495) 258 7748 David Nangle [email protected] Svetlana Kovalskaya Chemicals & Engineering + 7 (495) 783 5653 Marina Alexeenkova [email protected] Rinat Kirdan Consumer/Retail + 7 (495) 258 7753 Natasha Zagvozdina [email protected] Ivan Nikolaev Ulyana Tipsina Equity Strategy + 7 (495) 258 7916 Roland Nash [email protected] Tom Mundy Ovanes Oganisian Central Asia Equities/Strategy + 7 (727) 244 1544 Milena Ivanova-Venturini Elena Savchik Ekaterina Gazadze Bektas Mukazhanov

Metals & Mining + 44 (20) 7367 7781 Rob Edwards [email protected] Andrey Krupnik Boris Krasnojenov

Oil & Gas + 7 (495) 258 7904 Alexander Burgansky [email protected] Elena Savchik Evgenia Dyshlyuk Irina Elinevskaya Real Estate + 7 (495) 258 4350 Alexei Yazykov [email protected] Telecoms, Media & Technology + 7 (495) 258 7902 Alexander Kazbegi [email protected] Ivan Kim David Ferguson Ukraine Equities/Strategy + 38 (044) 492-7394 Wilfred Willwong [email protected] Svetlana Dryhush Dmitry Anufriev Utilities + 44 (20) 7367 7793 Derek Weaving [email protected] Vladimir Sklyar

Fixed Income + 7 (495) 258 7946 Alexei Moisseev [email protected] Nikolai Podguzov Petr Grishin Maxim Raskosnov Andrey Markov Valentina Krylova Anastasiya Golovach (Ukraine) Olesya Cherdantseva Economics & Politics + 7 (495) 258 7703 Katya Malofeeva [email protected] Elena Sharipova Alexey Alyokhin Mikail Matytsin

Macro & Strategy + 44 (20) 7367 7734 Matthew Pearson [email protected] Samir Gadio Financials +234 1 448 5300 Kato Mukuru [email protected] Oil & Gas +234 (01) 448 5300 Adam Zive [email protected] East Africa + 254 20 360 18 22 Mbithe Muema [email protected] Terry Kimundi Southern Africa + 263 1 163 44 63 Dzika Danha [email protected] Anthea Alexander West Africa + 234 1 271 91 33 Esili Eigbe [email protected]