Nigeria Oil Gas Sector Report

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CSL Stockbrokers is a division of FCMB (UK) Limited which is authorised and regulated by the Prudential Regulation Authority (PRA) and regulated by the Financial Conduct Authority (FCA) in the United Kingdom.

OML 26 At OML 26 Ogini and Isoko are currently producing 3,764boepd with a full field development plan approved at Ogini which envisages 37 new production wells from existing well pads and 13 work overs. An additional three production wells are planned for H2 2014, with a further two in 2015. The first of five wells was spudded in late July 2014 by the Durga rig. Production was impacted by a Force Majeure by Shell, the operator of the Forcados Terminal, in March 2014 due to challenging repairs on the export line leak. The repairs were completed in early April and the flow station has been brought back on-stream.

OML 26

Source: Afren

Isoko’s field development plan is expected to be approved in 2015 following submission in Q1 2015, and completion of an integrated reservoir study in 2014.

The Isoko FDP is in progress and is expected to be submitted by the end of Q1 2015, following the completion of the Integrated Reservoir Studies which commenced earlier this year. Significantly further upside may exist in the future marginal discoveries nearby at Aboh, Ovo, Ozoro.

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OPL 310

The Ogo discovery of 2013 ranks as the fourth largest with a P50 of 775mmboe, P10 of 1180mmboe. It was the largest discovery made offshore in Nigeria last year. Afren has a 40% stake in the field.

Largest Oil & Gas discoveries in 2013

Source: Forbes 1st August 2014 edition

In May 2014, Afren and its partners completed an extensive 3D seismic programme across OPL 310 and the neighbouring OML 113 licence. The objective to the full extent of the syn-rift play and further dip-closed structures on the acreage post the Ogo-1 discovery, which might offer further upside to existing reserve estimates.

OPL 301 & Ogo Field vs OML 113 Aje Field

Source: Afren

The size of the Ogo field relative to the Aje field (16.875% stake via FHN subsidiary) is at least four times the size of the Aje field.

Rank Country Name/Field Size (mmboe) Operator

1 Mozambique Agulha/Coral 1400 ENI

2 Angola Lontra 900 Cobalt

3 Malaysia B14/B17 850 Newfield

4 Nigeria Ogo 775 Afren/Lekoil

5 Congo Brazzaville Nene Marine 700 Statoil

6 Tanzania Tangawizi 575 Statoil

7 Gulf of Mexico Coronado 550 Chevron

8 Egypt Salamat 500 BP

9 Gulf of Mexico Maximino 500 Pemex

10 Canada Bay du Nord 450 Statoil/Husky

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OML 113 (Aje Field)

Full field development was granted in March 2015 and is focused on the Cenomanian oil reservoir. The first phase of full field development is planning to complete two subsea production wells, tied back to a leased FPSO. Likely wells include the recompletion of the Aje-4 well and a new well drilled to the Aje-2 subsurface location. First oil is expected in 2015 from mid case 2P reserves of 32.4mmboe, with a final investment decision being made by all JV partners shortly.

OML 113 Aje Field

Source: Afren

Okwok

Originally discovered by ExxonMobil/NNPC JV in 1967 (Okwok-1), two appraisal wells were drilled in 1968 (Okwok-2 and Okwok-3). The Okwok wells encountered oil in the LD1 and D2 series of reservoirs (also proved to be oil bearing and under development at the Ebok field) with over 100 ft of oil pay logged in the Okwok-2 well at the D2 level plus multiple 50ft oil bearing sections in the LD1 in the Okwok-1 and Okwok-2 wells.

Afren has deployed its subsurface knowledge gained from Ebok on Okwok to identify geological opportunities. There are many similarities between the two fields. The same reservoirs are present in both fields, as is the relationship of seismic amplitude to reservoir and hydrocarbon distribution. Afren therefore think there are larger in-place oil volumes than have been previously and independently quoted. Additionally, we have also identified significant potential in the deeper formations. Okwok now has 2P reserves

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of 46.6 mmbbls with potential to increase this if more oil is discovered in deeper formations. Following success at the Okwok-10 appraisal well and the Okwok-10 side track well, Afren successfully drilled one side-track well, the Okwok-11ST in 2013. This encountered 95 ft of net oil pay in the D-2 reservoir. The data acquired, together with the results of the Okwok-10 well (encountering 72 ft of net oil pay in the D-1 reservoir) and Okwok-10 side-track well (encountering 89 ft of net oil pay in the LD-1B reservoir), were integrated into the field model and used to update volumetric models and optimise a Field Development Plan (FDP), which was approved by the Nigerian government in January 2014. The development plan for Okwok comprises the installation of a separate dedicated production facility (see earlier Ebok diagram) and well head platform, with an export pipeline for stabilised crude oil tied back to, and sharing, the Ebok Floating Storage and Offloading vessel (FSO) located approximately 13km to the west. The Well Head jacket has been fabricated and is currently in the Okwok field awaiting installation which is currently scheduled for Q3 2014. Development drilling will commence following the completion of the platform installation.

Kurdistan Afren has two core assets in Kurdistan, including Barda Rash (operator 60% stake) and Ain Sifni, (Hunt Oil operator, 20% stake) both of which lie north west of Erbil and south of Gulf Keystone’s producing assets at the Shaikan oil fields. Currently both fields are shut in owing to the security situation deteriorating as the Islamic state of Iraq and al-Sham (ISIS) have advanced near Kurdish lands. Following US airstrikes on ISIS controlled cities in August and September 2014, the situation appears to have improved with Kurdish forces holding back ISIS forces for now. This has led to a number of oil companies, including Genel Energy (N/R), Oryx Petroleum (N/R) and Gulf Keystone (N/R), which operate producing assets in Kurdistan, all making positive statements indicating that their production facilities have not been affected by the security situation to date. Our view is that although production may not have been affected in the majority of cases, the ability of oil companies to operate in the region could be hampered by oil service companies withdrawing their personnel. The situation remains uncertain, therefore, with a military solution possible not just in Iraq but also in ISIS controlled Syria. Our view is that there is a likelihood of a military solution being implemented involving the use of ground forces with airstrikes serving to stop the advance of ISIS rather than destroy it. As Vice President Joe Biden was quoted as saying recently the US policy would involve ‘chasing ISIS to the gates of hell’, would seem to suggest military intervention through ground forces is inevitable now.

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ISIS Presence across Syria and Iraq

Source: Institute for the Study of War, BBC

Barda Rash

Barda Rash contains 14,015mmbbls STOIIP and 1,433mmbbls gross recoverable reserves. Geologically, Barda Rash is an elongated anticline with surface expression of 20km length and up to 7km width. The reservoirs are mainly fractured carbonates. Flow tests indicated a rate of 3,200boepd with relatively light oil of 30° to 32° API. in 2009, Two further wells were drilled in 2010, BR-2 and BR-3, both encountering oil in all reservoirs.

Barda Rash & Simirit Fields

Source: Afren

In 2012, development commenced the phased development of the field, initially targeting the development of light oil reserves. Initial flow rates in

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excess of 6,000bopd of 28° to 32° API oil were achieved, as well as obtaining valuable information on the production characteristics of the Mus/Adaiyah reservoir. In July 2013, Afren commenced preliminary crude oil sales to the local market. During 1H 2014, gross production from Barda Rash averaged 536bopd. As part of the second phase development of the field, the BR-4 well tested at a combined rate for 7,850bopd from two zones in the Triassic Kurra Chine formation. The BR-5 well, is expected to have a similar production capacity from the Kurra Chine reservoir as soon as drilling operations recommence. Due to the high levels of sulphur dioxide, the company has decided to limit production to around 1,000bopd while an interim gas solution in place that will allow the production capacity of the wells to be fully utilised. The current low rate of production is therefore not expected to have a meaningful impact on cashflows. Ain Sifni Ain Sifni was drilled on the crest of the Simrit anticline in 2010, Triassic reservoir targets were not penetrated by the well and no oil water contact was established. The PSC may have upside over and above the volumes discovered to date at the Simrit structure, with prospective resources estimated at 7,493 mmbbls STOIIP and 917 mmbbls recoverable on a gross unrisked basis. This upside comes from Simirit 2 Western section. To date four exploration wells have been drilled Simirit 3 in the East. Simirit-2 has reported a significant oil net pay zone of 1,342ft and significantly high flow rates of 19,641boepd under an extended well test. In Simirit-3 a total of nine drill string tests were carried in the Triassic, Jurassic and Cretaceous reservoirs reaching a cumulative rate of 6,293 bopd. Of the 9 tests, the Kurra Chine reservoirs produced at rates of 6,043 bopd 36° API gravity crude oil. Afren are reprocessing 3D seismic data so that the well data can be integrated with the updated structural understanding and volumetric estimates upgraded. The rig is currently being mobilised to the Maqlub-2 exploration well location. Afren recently confirmed that production would recommence in Kurdistan at the end of October 2014, with field operations at Barda Rash led by operator Hunt Oil (N/R) being resumed to normal levels

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Exploration

Afren has a material exploration portfolio across Africa with a bias towards East Africa which accounts for two thirds of the total gross prospective resources.

Afren Exploration Portfolio

Source: Afren

Afren’s current exploration focus for the next twelve months is in Nigeria (OML 115, OPL 310). Tanzania (Tanga), and Kenya (Block 1, Block L17/L18). Tanga is the largest in terms of net risked barrels at 241mmbbls, with the Nanasi prospect at the forefront of near term drilling prospects. In Kenya (Block 1) where six leads and prospects have been identified with a 2D seismic campaign across 290km² due to commence in H2 2014. A drill location will be finalised in early 2015. In OML 115 the Ameena East prospect is the main target, which has similar amplitudes and responses to discoveries made in Ebok, Okwok, Iyak, Utue, and Etisong. Drilling at OML 115 will follow on from drilling Ebok Deep, which is targetting deeper Qua Iboe and Biafra sands below existing 2P producing reservoirs. We have not included the Maqlub-2 exploration well in Kurdistan given the ongoing uncertainty over the security situation

Afren Exploration NAV

Source: CSL estimates

Gross prospective resources (mmboe) Net prospective resources (mmboe)

Ethiopia 344 103

Kenya 4,443 3,959

Seychelles 2,994 2,245

Madagascar 846 761

Tanzania 1,937 1,433

Total East Africa 10,564 8,501

Nigeria 1,943 786

Ghana 1,087 381

Côte d’Ivoire 87 57

South Africa 350 88

Other West Africa 252 35

Total Nigeria & other West Africa 3,719 1,347

Kurdistan region of Iraq 917 183

Total Group 15,200 10,031

Block Field/Prospect WI Net Reserves (mmboe) (Unrisked) US$/boe US$m US$/share CoS Risked US$(m) £/share

OML 67 Ebok Deep 50% 50 5 250 0.22 20% 50 0.03

OML 115 Ameena East 50% 65 10 650 0.57 20% 130 0.07

Tanzania Tanga 74% 963 5 4815 4.23 20% 963 0.51

Kenya Block 1 80% 2422 1 2422 2.13 10% 242 0.13

Kenya Blocks L17& L18 100% 2021 1 2021 1.77 10% 202 0.11

Expln NAV 5471 9908 8.70 1537 0.81

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Legal Position The legal position of Afren plc and its directors and former directors (suspended and current) is discussed here, though what follows, and other comments in this research, does not constitute a formal legal analysis and we would stress that internal investigations are still ongoing at Afren. The legal position is however important to consider, given the fact that any acquirer of Afren would need to ring-fence any potential liabilities through an indemnity agreement prior to any potential sale being agreed, or for that matter considered. We have attempted to quantify the potential liabilities faced by Afren here using publicly available information from previous cases lodged by the Financial Conduct Authority (FCA) and (Securities and Exchange Commission) SEC as well as the points of law arising from the BP case which provides a useful proxy. From an equity investment perspective it is important to try and estimate the potential liabilities resulting from any litigation that could be commenced either from institutional and/or retail investors as well as any potential sanctions and fines from the SEC, the FCA, and the Serious Fraud Office (SFO) since it affects the underlying value of the company. In addition it is also pertinent to assess the probability of sanctions and fines being levied on the company as well as the risk of civil litigation being commenced by existing shareholders. Possible FCA Liabilities and Sanctions Afren has admitted breaching the FCA Listing Rules (LR) under LR10.4.1R which relates to notification of Class 2 transactions. The company stated this during their last results release related to their H1 2014 results on the 29 August 2014. A class 2 transaction is defined as a transaction where any percentage ratio is 5% or more but is less than 25% as defined in the Class Tests LR10 Annex 1G, which tests a transaction size based on gross assets, pre tax profits, market value, and gross capital. The penalties the FCA can implement are based on a scale of 1-5 classified breaches, 1 being the least serious, 5 the most serious. These are then scaled by market capitalisation from 0.1% for a category 1, to 0.5% for a category 5 breach. If enforcement action were taken against Afren by the FCA as the UK Listing Authority and it were established that there had been a breach of the listing rules, we believe that any penalty or fine imposed would be calculated retrospectively using the historic market capitalisation prior to the RNS suspending their CEO and COO on 31 July 2014. In addition, if it is established that the listing rules were breached three times in three separate instances, it is possible that a fine of 1.5% of their historic market capitalisation might be applied. This would equate to a maximum fine of $42.4m (£25.4m) based on a price of 418.88p on 31st July 2014. It should be noted that there is no public information available to suggest that the FCA has commenced or might commence enforcement action against Afren. Historically the FCA and previously FSA have imposed fines which appear to be less than the maxima contemplated by the classification guidance. In the case of Lamprell (N/R) which has the highest fine by market cap in the United Kingdom, the company agreed to settle at an early stage of the FSA investigation and therefore qualified for a 30% discount in the overall fine as part of the FSA executive settlement procedures. Afren may

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choose to follow this example thus lowering any potential fine. Our $42.4m estimate could therefore be considered to be on the high side.

Fines by FCA/FCA on FTSE Companies for Listing Rule Breaches

Source: FCA, CSL estimates, RDS Market Cap on Aug 2004 is an estimate

Civil Action As well as the possibility of fines being imposed by the FCA, Afren may also face civil litigation by retail and institutional investors both in the US and UK. We would ascribe a low probability of this occurring given the fact that the company is still currently investigating what unauthorised payments may have been made to directors. Unless it transpires that the company committed unlawful behaviour then pursuing a civil case would be difficult to envisage at this juncture. The BP Case BP’s (N/R) liability position following the Deepwater Horizon disaster provides a useful legal precedent to see how the US legal system has reacted to a company found guilty of criminal and civil damages. We would stress that the BP case is an environmental one domiciled in the state of Louisiana US, with Afren’s case based outside the US (with assets in Nigeria and Kurdistan) and relate to alleged corruption by directors, where currently no unlawful behaviour has been proven with investigations still on going. In that respect they are very different, however the BP case provides a useful insight into how US and foreign investors could pursue securities litigation through the US legal system. BP investors initial efforts to lodge claims via America’s Supreme Court were blocked with the Morrison v National Australia Bank Ltd ruling which ensured that foreign investors could not seek redress for liabilities on the basis that BP trades its common stock in London not New York. Under this ruling only purchasers of BP ADRs in the New York Stock Exchange (NYSE) could seek damages. It is worth highlighting here that Afren also trades ADRs on the NYSE, and could therefore face litigation from ADR holders but probably not ordinary shareholders on that basis. In addition the Federal Securities Litigation Uniform Standards Act of 1998 (SLUSA) bars class actions under US State Law for foreign securities losses. To avoid this hurdle BP plaintiffs have pursued individual actions, rather than class actions, whilst at the same time seeking damages for any ADRs purchased on the NYSE through the US Federal Courts and SLUSA. In October 2013 the US District Judge based in Texas, Judge Keith Ellison assigned with the BP case, rejected any defence based on the ‘Morrison v National Australia Bank Ltd’ case and chose to oversee the case himself by applying English Common Law instead. The ‘Dormant Commercial Clause’ of the US Constitution was also rejected as a defence argument. This clause asks the question of whether a law discriminates against interstate commerce. In this regard ‘discrimination’ simply means differential treatment of in-state and out-of-state economic interests that benefit the former and burdens the latter. In BP’s case they argued that by pursuing an in-state case it might disadvantage those outside in other states.

FSA/FCA Fine Date Market cap US$(m) % Fine vs Market Cap

Prudential £14m Mar-13 29,500 0.05%

Lamprell £2.4m Mar-13 1,105 0.22%

Royal Dutch Shell £17m Aug-04 110,000 0.02%

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The rejection of both defence arguments by Judge Ellison, proved to be a watershed for the plaintiffs, with the Judge accepting the fact that there was evidence investors had been ‘induced’ to buy BP shares through face to face meetings with investment managers and through press releases aimed at shareholders. The judge further accepted the allegation that BP shareholders had been misled through BP’s false and misleading statements, with negligent misrepresentation proven. Significantly the latter provided a legal precept based on a more lenient standard of law to apply for damages on a retrospective or historical basis. Institutional investors who have successfully pursued this case through the Texas Courts include US Municipal and County Pension Funds, US limited partnerships, Employment Retirement Income Securities Act 1974 (ERISA) Trusts, and European and Australian Pension Funds. We believe that although the BP case is very different in terms of asset location and litigants, it does show that in the US there is a route to successfully achieve claims if litigation were to transpire for Afren. UK Courts In addition to investors seeking securities litigation through the US Courts, they could also seek this through the UK Court under the Companies Act 2006, by taking derivative action against individual directors. The law applies a threshold requirement whereby pursuers must have a significant shareholding in the company to warrant any derivative claim being lodged. In practice very few cases in the UK have been lodged and we see this route as having a low probability of occurring. It is worth highlighting the point that individual directors of companies are shareholders themselves so they can also lodge derivative claims. If civil action were to subsequently transpire as a result of unlawful actions, we see two options open to Afren, namely to settle out of court and allocate appropriate funds to cover any potential, or face possible civil litigation in the US and the UK. In the first case, settling out of court, Royal Dutch Shell (N/R) provides a useful basis for comparison since it avoided litigation. Royal Dutch Shell settled out of Court with non US based retail and institutional investors through the Stichting Shell Reserves Compensation Foundation, the VEB, ABP and SPZW for the sum of US$352.6m (£218.5m) in March 2007, over 3 years after the original reserves crisis. Importantly this was settled not through litigation, but by an agreement whereby Royal Dutch Shell admitted no wrongdoing in the reserves ‘misrepresentation’ case. US based shareholders received US$82.85m and the US SEC US$120m, making a total payment of US$555.45m (including payments made under the Stiching Shell Reserves Compensation Foundation). The majority of payments were made to non US shareholders, which is in line with the fact that over 80% of Shell’s stock traded on European exchanges. Similarly the majority of Afren’s stock trades outside the US via London. Given the fact that alleged unauthorised payments to directors may have occurred between 2012 and 2013 according to the company, the number of shareholders who could have been affected therefore increases. This could imply that any resulting litigation claimants could also increase. US claims could transpire via existing ADR holders, and through foreign shareholders seeking damages in a similar fashion to those lodged by BP shareholders.

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In order to properly estimate any potential civil liability, both in terms of UK and US claims, we must examine the share price of Afren on the LSE and ADRs in NYSE on or prior to 31 July 2014 when the original press release was issued, suspending two directors of the company (CEO and COO).

Afren ADR’s share price (US$), NYSE quote 29th July 2014 – YTD

Source: Bloomberg

According to the US Securities Exchange Act of 1934 ‘Plaintiffs can recover the excess of what they paid over the actual price of the security. The "actual price" is the average price of the security within a 90-day window of the disclosure’. In Afren’s case this implies the 29 October 2014 as the cut off date to assess any potential shareholder losses using ADR/ordinary share price quotes. If the price were to fall further in this intervening period the potential shareholder losses would therefore increase. Over the period 31 July Afren’s ADRs quoted on the NYSE have fallen by 34% and London quoted shares by 70%.

Afren Ordinary share price LSE quote 29th July 2014 – YTD

Source: Bloomberg

The actual size of the current shareholder loss based on the current share price is 104.4p/share which, given that there are 1.1 billion shares in issue, equates to a shareholder loss of £1.2bn (US$1.8bn). We know that around one third of Afren’s shareholders by market capitalisation are US-domiciled (source Bloomberg), so out of the US$1.8m estimated

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shareholder losses around US$549m could be US based. However, we do not know within this what percentage are ADR holders. Given our assumption that the US is probably more litigious than the UK, we could further deduce that this US$549m of estimated shareholder losses has a higher probability of being pursued on a civil basis in the US by investors given its more litigious culture. Furthermore, we already know from the BP Deepwater civil case that non-US shareholders have pursued litigation through the US Courts whilst at the same time lodging claims through the UK Courts. A further incentive for non US shareholders to pursue claims through the US Courts, is the fact that in the UK and Europe the unsuccessful litigant might have to pay the successful opponent’s legal fees whilst under the US system each party bears their own costs. In summary, therefore, the total shareholder losses and fines are split as follows:

· US shareholders losses of US$549m, which is a percentage of existing shareholder base (one third multiplied by the total estimated liability of $1.8bn). This has a higher probability of being pursued given the more litigious appetite of the US.

· Non-US shareholders losses of US$1.2bn is the remaining shareholder base (two thirds) multiplied by the total estimated liability of US$1.8bn. This has a low probability of being realised unless the company is subsequently proven to have engaged unlawful actions.

· Retail investors account for 1.47% of the total shareholder base, which is 1.47% of US$1.8bn, or US$27m. This has a very low probability of being realised in our opinion given the fact the UK Companies Act of 2006, requires that pursuers have a significant shareholding in the company before any claim is granted a hearing.

· FCA fines which could be, at least in theory, 1.5% (3 fines of 0.5%) multiplied by the historic market capitalisation based on the share price at 31 July 2014.

Afren - Estimated Shareholder Losses, Fines and Sanctions


Prosecution under the Bribery Act 2010, which is enforced by the UK Serious Fraud Office (SFO), is also possible with strict penalties including unlimited fines, and/or imprisonment of up to ten years for directors (both current and former) found guilty. The only defence Afren (or any other company faced with allegations linked to the Bribery Act 2010) could put forward is on the basis that they had ‘adequate procedures’ in place including implementing employee/HR policies and other anti-bribery procedures in accordance with the Ministry of Justice guidance. Prosecution and sanctions of individuals is more likely than of companies, since it could be argued that companies are comprised of shareholders who are the victims here of any alleged acts of bribery. Directors cannot

US$(m)

US shareholders 549

Non US shareholders 1251

Retail investors 27

FCA Fines 42

Total Liability 1869

SFO Fines Unlimited

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claim that they ‘took a blind eye’ having full knowledge of acts of bribery. Recent cases that have been pursued by the SFO include BAE Systems plc (N/R) which took 6 years to settle with a £280m fine being imposed, split £250m in the US and £30m in the UK. In addition, as well as a UK SFO investigation concurrent prosecution could also occur via the Department of Justice in the US under the US Foreign Corrupt Practices Act (1977) related to anti bribery as cited in Section 30A of the US Securities Act 1934. Violations of the FCPA can lead to civil and criminal penalties, sanctions, and remedies, including fines, disgorgement, and/or imprisonment.

SWOT Analysis

Strengths Weaknesses

Growing production and cashflow base Uncertainty created from internal investigation

Strong exploration track record - Oyo 4th largest discovery in 2013

Opportunities Threats

To crystallise 2C into 2P reserves Possible legal sanctions by FCA and SEC

Development opportunities in Nigeria Shareholders claims for damages via civil actions in UK and US

Wide exploration portfolio in Africa and Kurdistan Risk of M&A given current depresssed share price

Deterioration of security situation in Kurdistan

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CAMAC Energy

Investment conclusion We reiterate our BUY recommendation on CAMAC with a target price of US$0.92/share using a RENAV based valuation methodology which includes a core value (2P) of US$0.45/share, and exploration upside of US$0.47/share. Our core valuation is supported by historic acquisition prices for CAMAC’s core acreage offshore Nigeria in OML 120/121.

CAMAC is set to increase production from its flagship Oyo field in deepwater Nigeria with an exit production rate of 14,000bpd by the end of 2014. Further production increases beyond this are forecast with a peak production rate of 25,000bpd by 2016 based on 3P estimates. This ramp up will provide the necessary cashflows to increase exploration drilling activity across CAMAC’s portfolio which encompasses deepwater Nigeria, Kenya (onshore and offshore), Gambia offshore, and Ghana offshore

As a further catalyst for the share price, the probability of a reserves and/or resources upgrade appears high. This is due to the fact that management has previously stated in an April 2014 update that they have high graded three prospects with over 200mmboe unrisked potential each. We estimate this to be worth US$0.53/share risked. A successful listing on the Johannesburg Stock Exchange earlier this year provided US$270m to acquire the remaining 70% economic interest from Allied Energy Plc in OML 120/121, thus securing 100% of this producing asset. CAMAC is currently increasing their sources of finance through a senior credit facility. We anticipate an announcement regarding this shortly which would provide the catalyst for further upside in the share price, in our view

Company overview CAMAC Energy is an independent oil and gas exploration and production company focused on Africa. Its portfolio consists of nine licenses across four countries covering an area of 43,000km² (10 million acres), including production and other projects offshore Nigeria, as well as exploration licenses offshore Ghana, Kenya and Gambia, and onshore Kenya. CAMAC Energy is headquartered in Houston, Texas, and is listed on the New York Stock Exchange and Johannesburg Stock Exchange. It has a 100% interest and operatorship of the deepwater licences of OML 120/121 which contain the Oyo producing field, which has a targeted exit production rate of 14,000bpd in 2014. The company plans to use cashflow generated from the Oyo field, and may seek a farm-in partner, to fund the exploration of existing prospects which could have additional upside. An exploration well is planned for 2015 in OML 120/121. The risk-reward of deepwater Nigeria is compelling with an average success rate of 50% based on historic wells drilled to date. Allied with this is the fact that currently the majority of producing acreage is in the Miocene formation based with evidence of good trapping mechanisms and flow rates from existing giant fields including Exxon-operated Erha which lies adjacent to CAMAC’s OML 120/121 assets.

BUY (Price: US$0.71 – Target: US$0.92)

Key data

Year to December (US$m except EPS)

2013A 2014E 2015E 2016E

Sales 8 256 657 842

Net. Inc. -16 135 493 615

EPS -0.04 0.11 0.39 0.49

P/E (x) -10.7 4.2 1.2 0.9

Div Yield (%) 0 0 0 0

Mkt. cap.(US$m) 567

Free float 51.4%

Bloomberg CAK US

Reuters CAK A

Six month share price

Contact information

London: +44 (0) 20 7220 1043

Lagos: +234 (0)1 448 5436 Angus McPhail

Guy Czartoryski (Head of Research)

Temi Popoola (Lagos Sales)

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Outside Nigeria, CAMAC has interests in Ghana, Kenya, and the Gambia where seismic activities are being conducted prior to any drilling programme, which is tentatively planned for 2016.

Valuation We have valued CAMAC using a NAV analysis incorporating a 12% discount rate and a US$90/bbl oil price base from 2016 onwards. Our core NAV, which only includes the value of producing assets (2P) in Oyo, is US$0.45/share. CAMAC has a long list of exploration prospects, none of which have reached the appraisal stage yet. The most attractive on a risk-reward basis appear to be prospects P and G with an estimated risked value of US$0.41/share and US$0.25/share respectively. Given the fact that CAMAC intends to drill one exploration prospect next year and has indicated in its last operational update in April 2014 that it has now high graded three prospects to be worth in excess of 200mmboe each (unrisked), we think that it is justifiable to include the value of at least one of these prospects and furthermore we assume that it will be drilled within the next twelve months. We have only included the value of one prospect since we know that only one prospect will be drilled within the next twelve months which is in line with our valuation horizon. We have therefore valued this separately to be worth US$0.47/share (risked) using similar risk parameters contained within the CPR published in December 2013 by Gaffney Cline for existing prospects. We have applied further risking to reflect associated development risk attributable to the deepwater location and lack of existing infrastructure, which would require another Oyo-type FPSO development to minimise operating costs.

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CAMAC Oil & Gas Valuation

The probability of another Erha-type discovery (OPL 209, 495mmbbls of oil and 2.7Tcf of gas) should not be ruled out given the analogous Miocene geology, which historically has proven to be a prolific zone for discoveries of significant size in deepwater Nigeria. We have attempted to value this for CAMAC using Erha as a template for the economics of a 1bnbbls discovery (P50), and risking it using conservative assumptions for the chance of success and development risk. Erha and Erha North is a US$3.5bn development with capex costs of US$2.97/boe. The risked value we have estimated is US$2.63/share, which, if we include existing production at Oyo, implies a ‘blue sky’ RENAV of US$3.08/share. This is very much a ‘blue sky’ scenario, however the potential for CAMAC to achieve this is a useful valuation exercise in light of the compelling geology in the area.

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CAMAC NAV Waterfall


In addition to the traditional NAV valuation methodology we also have the benefit of historic transactions in OML 120/121. These include the recent acquisition by CAMAC of 70% of the economic interests from Allied Energy Plc, and the 30% stake in CAMAC acquired by the Public Investment Corporation (SOC) Limited. Both deals closed in February 2014, and imply a value of US$0.68/share and US$0.71/share, respectively. We have included a historic cumulative gross capex estimate of US$1.2bn which implies the highest value of US$0.95/share.

OML 120/121 Historic Transactions and Capex

Source: CAMAC Energy

The average value of these transactions is US$927m or US$0.73/share, which is less than our estimated NAV. The estimate based on historic capex by BP, Statoil, ENI, and Allied Energy is US$0.95/share which is close to our estimated RENAV value.

0.00

0.20

0.40

0.60

0.80

1.00

1.20

Producing Net debt/cash Exploration Total RENAV

p/share

Date US$(m) % Stake Implied Value (Gross) US$(m) $/bbl US$/share Comment

Feb-14 600 70% 857 45.2 0.68 Allied transaction

Feb-14 270 30% 900 47.4 0.71 PIC transaction

2005 -2010 1200 63.2 0.95 Cumulative capex by stakeholders BP, Statoil, ENI, Allied Energy

2010 300 40% 750 39.5 0.59 Allied Energy acquisition from ENI

Average 927 48.8 0.73

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Oyo Field Development The Oyo Field was the first ever deepwater Nigerian discovery made back in 1995. It is located in deepwater (200-500 meters) approximately 75 km offshore Nigeria. As of February 2014, CAMAC has a 100% working interest and operatorship in OML120 and 121. The Oyo Field commenced production in December 2009. The Oyo wells are connected to the Armada Perdana FPSO, a Floating Production, Storage and Offloading (FPSO) vessel, with maximum capacity of 40,000bpd and 1.1mmbbls storage capacity. The associated gas is partly used as fuel for the FPSO, partly re-injected into the Oyo Field reservoir by another well, Oyo-4, to maximise oil recovery rates, and partly flared. The FPSO has been secured for a period of seven years from January 2014 and therefore underlines the long term commitment CAMAC has towards fully developing OML 120/121. To date eight wells have been drilled in the Oyo field, with Oyo wells 1-4 being exploration and appraisal wells, and Oyo wells 5-8 producers. Oyo wells 5 and 6 came onstream in 2009 at a combined peak rate of over 25,000 bpd, producing 1,600bpd during Q2 2014.

OML 120, 121 (Oyo Field)


The development plan for 2014 is to replace Oyo 5 and 6 with Oyo 7 and 8, with an anticipated flow rate of 7,000bpd each. In recent Q3 2014 results CAMAC indicated that Oyo-8 was sucessfully drilled to a depth of 6,059ft and encountered four new oil and gas reservoirs with a hydrocarbon thickness of 112ft which is high a gives us confidence that 7,000bpd flow rate is achieveable.The plan is to bring one producing well (Oyo 7 or 8) into production completing horizontals on both by the end of this year, then

water depths of 330-3,300 feet

OYO FIELD

46 miles offshore

BONGA NORTHWEST

ERHA FIELD

Discovery: 1999

Production: 2006

Current production: ~140,000 bbls/d

ExxonMobil 56%, Shell 44%

BOSI FIELD

Discovery: 1996

Production: TBD

ExxonMobil 56%, Shell 44%

BONGA FIELD

Discovery: 1995

Production: 2005

Current production: ~150,000 bbls/d

Shell 55%, ExxonMobil 20%, Total 12.5%, Eni 12.5%

SONAM FIELD

Discovery: 1999

Production: 2016 est.

Chevron 40%, NNPC 60%

OYO

OYO FAR EAST

EBOLIBO FIELD

EWO NORTH

EWO DEEP

PROSPECT “O”

PROSPECT “G”

ERENG

PROSPECT “R”

PROSPECT “P”

OYO FIELD

Discovery: 1995

Production: 2009

Q2 ‘14 production: 1,600 bbls/d

1P of 9.9 MMBbls of oil



CAMAC Energy 100%

EBOLIBO FIELD

Discovery: 2007

2C of 120 Bcf

CAMAC Energy 100%

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another one early in 2015 The exit target production rate for 2014 is 14,000bpd. Oyo-5 will be converted from a producer well into a water injection well in order to maintain the aquifer pressure within the reservoir and enhance the flow rates in Oyo 7 and 8. To date the Oyo 7 well was successfully drilled in October 2013, and will aim to use a directional well in the Pliocene formation, prior to being completed horizontally.

Beyond this, forward plans to develop the field include drilling Oyo-9 (development well) in 2015, while Oyo-10 and 11 (development wells) are planned for 2016. Each well is anticipated to contribute 7,000bpd to achieve a target production of 20,000bpd by 2016. Decline rates of between 20-25% are forecasted.

Oyo Field – Oyo wells 1-8


Oyo-1

Discovery well, 1995

West Area

Central Area

Far East Area

Oyo-4

Gas injection well, 2007

Oyo-5

2009

IP 9,500 bopd

Peak 16,890 bopd

Oyo-6

2009

IP 6,300 bopd

Peak 8,800 bopd

Oyo-2

Appraisal well, 2006

Oyo-3

Appraisal well, 2007

Oyo-8

Completion stage

Oyo-7

Completion stage

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CAMAC Production Profile


CAMAC’s production profile forecast is targeting 25,000bpd by 2016, with additional prospects coming onstream in 2018 at the earliest, given a lead time of three to four years between exploration success and first oil from development. Within our forecasts we have assumed that 3P reserves (35mmboe) are crystallised into 2P reserves by 2016, and brought into production. In addition we have further assumed that CAMAC develops one of its prospects from a +100mmboe discovery. Our production forecasts are in line with company guidance.

0

5

10

15

20

25

30

35

40

2014e 2015e 2016e 2017e 2018e 2019e 2020e

kbpd

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Exploration

Nigeria CAMAC is planning to drill at least one exploration well in OML 120/121 in the next 12 months. We believe this could be a game changer for the company given the proximity of existing prospects to Exxon’s producing oil and gas field at Erha.

CAMAC Prospects OML 120/121

Source: CAMAC

The underlying logic to this view is the geological sequence in which all of CAMAC’s prospects lie, namely they are in the Miocene formation which is a

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known, producing formation where significant, mainly oil based, discoveries have been made. CAMAC’s existing prospects also exhibit a bias towards oil rather than gas phasing with an average of 65%. CAMAC’s Oyo field lies between Exxon’s producing Erha field and Chevron’s gas development at Sonam.

CAMAC Prospects OML 120/121

Source: GCA, CAMAC Energy

Deepwater Nigeria Existing Discoveries

Source: GCA

OML 120/121 Cross Section vs Erha (Exxon) and Sonam (Chevron) wells


Unrisked - P50 Risked - P50

Prospects Block Formation OIL GAS OIL & GAS Oil/Gas Split GCoS OIL GAS OIL & GAS

P 121 Pliocene 41 427 112 37% 56% 23 239 63

G 120 Miocene 64 24 68 94% 56% 36 13 38

Oyo T1B 120 Miocene 2 3 3 80% 64% 1 2 1

Oyo Deep 120 Miocene 1 1 1 86% 35% 1 1 1

Ereng 120 Miocene 78 90 93 84% 13% 44 50 52

Ewo North Upthrown 120 Miocene 17 29 22 78% 22% 10 16 12

Ewo North Downthrown 120 Miocene 3 42 10 30% 32% 2 24 6

O 120 Pliocene 2 64 13 16% 63% 1 36 7

Kigbo 121 Pliocene to Pleistocene - 226 38 0% 42% - 127 21

Q 120 Miocene 96 86 110 87% 17% 54 48 62

Total 304 992 469 65% 56% 170 556 263

Reserves

Field Reservoir Trap Date Depth (m) Oil (mmboe) Gas (Tcf) Oil & Gas (mmboe) Oil/Gas split Comment

Erha Miocene Anticline 1999 1200 500 3 1,033 48% 30-32° API

Bosi Miocene Combined structural-stratigraphic trap 1996 1424 683 2 1,066 64%

Oberan Miocene Faulted anticline 2002 900 93 - 93 100% HPHT 157°C

Bonga/Bonga SW Miocene Fault block/flank of mud diapir 1995 1311 1,235 1 1,394 89%

Nsiko Miocene Thrusted anticline 2003 1812 289 - 289 100%

Agbami Middle Miocene - Oligocene Partly sub-thrust anticline, cored by reverse fault/mud diapir 1998 1463 780 1 876 89% 35-45° API oil

Nnwa Miocene Thrusted anticline 1999 1200 200 4 933 21% Gas

Akpo Miocene Anticline/minor strat component 2000 1400 590 1 790 75% 50° API condensate

Usan Miocene Complex structure in eastern deformed belt 2002 750 450 - 450 100% 21-42° API oil

Total 4,820 13 6,925 70%

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Global deepwater plays fall into four broad types of basins: (1) Basins with mobile substrates (salt, shale) fed by large rivers; (2) Basins with mobile substrates fed by small rivers (3) Basins with nonmobile substrates fed by small rivers; (4) Basins containing non deepwater reservoirs

To date, about 75% of the discoveries in deep water globally occur in the first two types of basins, with deepwater Nigeria basins associated with the first category. In terms of stratigraphy, CAMAC’s blocks are located in the (thick Akata) mobile shale belt with mobile substrates (salt, Akata shale) fed by large rivers (Niger and Benue Rivers).

Nigerian Offshore Stratigraphy

Source: GCA

Examining structural plays, Nigeria offshore is divided into eight structural plays, including eastern and western mini basins, eastern and western fold belts, eastern and western thrust belts, and the relatively unstructured Transform margin. To date nearly 7bnboe have been discovered in offshore Nigeria with 70% (4.8bnboe) oil based with a commercial success rate of 50% since 1995. The fold plays in the east and western portions of deepwater Nigeria cover 9,200 and 10,000km2 respectively. Water depths range from 1,500m to 2,000m. The fold plays are characterised by a small number of very large simple traps. The wells have proven one of the largest global deepwater field size distributions with a mean discovery volume of 475mmboe. The

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eastern fold play is characterised by relatively simple anticlines with Middle to Lower Miocene Basin floor reservoirs. The western fold play targets predominantly channel over nose structural stratigraphic traps in Middle to lower Miocene reservoirs. This is where CAMAC has acreage in OML 120/121. The low density of large traps results in rapid creaming of the plays. Thrust plays cover 35,000km2, half the structured play area in deepwater Nigeria. Thrust plays are sub divisible into 3 segments; an inner and outer thrust belt in the west and an eastern outer thrust belt. The outer thrust belts are toe of slope compressional trends coincident with the main phase of extension along the coast to the outer shelf. The western inner thrust belt is probably an older fold/thrust system reactivated by shale diapirism from the upper Miocene to present. This latter formation is where CAMAC has its acreage located in OML 120/121.

Niger Delta Structure Provinces and Bathymetry

Source: CAMAC

OML

120/121

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Critical to this are the presence of confined or unconfined settings which ultimately determine in deepwater if a discovery can be made commercial or not. In general, those reservoirs deposited in confined basins have smaller trap areas and larger net pay values than do reservoirs deposited in unconfined settings, making commerciality easier to achieve. To date Miocene plays have exhibited confined settings with several stacked plays, with Nigeria exhibiting a good record of achieving these.

Deepwater Nigeria Existing Discoveries

Source: GCA

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Ghana

Outside Nigeria, CAMAC has exploration assets in Ghana, Kenya and Gambia. In Ghana, CAMAC has signed a petroleum agreement in the Expanded Shallow Water Tano block offshore, across 373,000 acres in water depths of 180-380ft taking a 30% stake and operatorship. Three discoveries have been made in this acreage. The South Tano field was discovered in 1978 by Phillips Petroleum, the North Tano field in 1980 by Phillips Petroleum, and West Tano field in 2000 by Dana Petroleum. To date no prospective resources estimates have been provided; however, they are in close proximity to proven commercial developments of size like the Jubilee field in West Capes Three Points, and TEN (Tweneboa, Enyenra, and Ntomme) in the Deepwater Tano Block where extensive turbidite fan systems have been discovered. CAMAC has nine months to determine commerciality of the three previously discovered fields, then the initial exploration period lasts two years. Over the next nine months, CAMAC will be analysing 3D seismic data, and geological and well data, as well as commercialising the existing discoveries.

CAMAC in Ghana – Expanded Shallow Water Tano Block

Source: CAMAC, Government of Ghana

GHANAGHANA

DeepwaterTano Block(TEN Fields)

Expanded Shallow Water Tano Block

West Cape Three Points

Block

(Jubilee Fieldand

Teak-AkasaDiscoveries)

Expanded Tan

(Jubilee Fieldand

Teak-AkasaDiscoveries)

JUBILEE FIELD104,000 bbls/dQ2 2014 production

GHANA

Expand

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North & South Tano Prospective Resources Estimates

Source: GNPC

In the West Tano Basin there is better visibility on the reservoir potential with Dana Petroleum encountering a significant column of oil of 150ft at a target depth of 10,414ft at well TW-IX in 2000. Flow rates of 1,000bpd were achieved with 20 API gravity oil which is relatively heavy. Dana did attempt to continue drilling beyond 10,414ft but had pressure problems and had to plug the well. CAMAC could therefore re-enter this well using a high spec rig and conduct a full appraisal including flow testing of this discovery which was never achieved previously due to the over pressuring encountered. Current plans by CAMAC involve assessing the economic viability of developing the three previous discoveries. CAMAC is currently reviewing 3D seismic data with an announcement regarding the potential of the acreage due in the first half of 2015, with the possibility of the first development well being drilled in 2016.

Kenya

Kenya is an emerging oil region with recent success by Tullow in the South Lokichar Basin in Northern Kenya, increasing the commercialisation of the country. Forward plans for 2015/16 for the government of Kenya include building a pipeline to Lamu on the coast estimated to cost US$3bn. The economics of the pipeline are improved by linking up to existing producing Ugandan oil fields, and plans to link in the future to South Sudan and Tanzania. Other international oil companies are operating in Kenya including Anadarko, Marathon, Statoil, Total and Eni all acquiring acreage onshore and offshore. CAMAC entered Kenya in 2012 when it was awarded four blocks including L1B and L16 (both onshore) and Blocks L27 and L28 offshore with a 100% stake and operatorship. The government, through the National Oil Corporation of Kenya (NOCK), has the option to take up a participating interest of up to 20% upon development. To date CAMAC has identified five leads in L1B block onshore located in the Lamu Basin with plans to drill the first exploration well on its onshore blocks in 2016. CAMAC is actively maturing prospects onshore and has completed a gravity and magnetic survey, as well as an environmental social impact assessment study, and recently announced plans to shoot 2D seismic beginning this year.

S. Tano N. Tano Total

Oil (mmboe)

STOIIP 71.3 53.6 124.9

P50 14.3 1.1 15.4

Gas (Bscf)

STOIIP 44.2 102 284.2

P50 18 73 193

Total Oil & Gas (mmboe)

STOIIP 79 71 172

P50 17 13 48

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Earlier this year, CAMAC announced that it had contracted Polaris Seismic International Limited to conduct a 2D seismic survey covering 125,000 acres (506 sq. km.) within Block L16 partly onshore and partly offshore Kenya. In Block L1B onshore, BGP Kenya Limited has been engaged to conduct a 2D seismic survey covering 170,000 acres (700 sq. km.) The initial exploration period for the onshore blocks expires in June 2015, but only covers the initial exploration phase (seismic), not drilling of any exploration wells. In L27/L28 offshore CAMAC acquired 2D seismic in March, and it is currently being processed by WesternGeco, a division of Schlumberger. Plans are to then acquire 3D seismic on the most promising areas, with exploration well drilling to follow thereafter. Prospectivity is good with evidence of gas and some oil shows in eastern blocks adjacent to CAMAC according to Imara Energy (N/R). Commercial success onshore has increased the impetus by the government to review its petroleum taxation regime. Currently, companies pay corporate tax at 30% (foreign operators at 37%). The government is considering introducing a windfall tax and capital gains tax to obtain more revenues. This is obviously a key risk, with likely introduction in Q4 2014.

Kenya CAMAC Acreage

Source: CAMAC

Offshore, CAMAC has acreage in blocks L27 and L28 adjacent to Anadarko, Statoil, Eni and Total, with forward plans to drill the first exploration well in the next few years. Like onshore acreage, the licence work requirements only cover seismic being completed prior to the licence expiring in August 2015. To date offshore, only two significant discoveries have made. These include Mbwana in Block L8 (Apache operated) in 2012, which was a gas

ETHIOPIA

TANZANIA

KENYA

Oil Discovery

Gas Discovery

CAMAC Acreage

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discovery, and Sunbird-1 well in Block L10A (BG operated) which made the first oil discovery offshore Kenya in June 2014. The significance of the Sunbird-1 oil discovery is important to recognise since it was the first oil discovery to be made along the eastern African seaboard from South Africa to Somalia, thereby dispelling the myth that East Africa offshore only contains gas. CAMAC acquired 2D seismic covering their offshore blocks in March 2014, and is currently processing the data. They are also conducting a regional Geophysical Study.

Gambia Exploration is very much in its infancy in Gambia, with a focus on offshore rather than onshore plays given the obvious river delta plays from the Gambia river, which is 700 miles long. CAMAC entered Gambia in 2012 through offshore blocks A2 and A5. The acreage lies on the West African Transform margin which is a proven hydrocarbon play. The area marks the northern extent of the Casamance-Bissau sub-basin forming part of the Mauritania-Gambia-Guinea Bissau coastal basin which is characterised by halokinetic deformation (which create salt domes) and proven petroleum systems. CAMAC owns 100% of the interests in these two blocks, and is currently reprocessing 2D seismic and conducting a regional geological study, followed by a 3D seismic survey. Recent exploration activity in the area includes two wells being drilled by Cairn Energy (N/R) offshore Senegal located north of CAMAC’s acreage. These include the FAN-1 well which was spudded on 17 April 2014, then the SNE-1 well is set to be drilled next. Both wells are being drilled by the Cajun Express, a semi submersible rig owned by Transocean. The wells are the first to be drilled in the area in over 20 years with the results important to prove up the potential of the West African Transform Margin in this area. The success of either of these two wells will have a significant positive impact on CAMAC’s prospects offshore Gambia.

Gambia CAMAC Acreage

Source: CAMAC

Gambia is not without its risks however, including the recent revocation of two blocks earlier this year. These included Blocks A1 and A4 offshore, which were operated by African Petroleum (ASX listed, N/R) and one onshore block operated by Nigerian based Oranto Petroleum (N/R). The government was quoted as saying that these oil companies were not following their work program, and were holding the acreage for ‘speculative purposes’.

30 In 1979,

18 miles

April 17, 2014 FAN-1 exploration

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SWOT Analysis


Operatorship of offshore Nigerian assets Smaller player relative to IOC's operating in deepwater

Large acreage position in Kenya, Gambia and Ghana Limited access to finance given current size of 2P/3P base

Strong geological team based in Houston


Additional acreage opportunities in Nigeria and ROW Changes to PRT in Nigeria, Ghana, Gambia, Kenya

Farm out opps pre development

Possible upgrade to current reserve/resources position

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Executive Management Kase Lawal (Chairman & CEO)

In addition to serving as Chairman & CEO of CAMAC Energy, Dr. Lawal also serves as Chairman of privately-held CAMAC International Corporation, a diverse, global group of companies. Dr. Lawal is committed to public service, and contributes valuable leadership while serving on the Board of Directors of the National Urban League, and the Cullen Engineering Research Foundation. In addition, Dr. Lawal is a member of the board of directors and a shareholder in Unity National Bank, the only FDIC-insured and licensed African American-owned bank in Texas. Dr. Lawal earned a bachelor's degree in chemistry from Texas Southern University and an MBA in finance and marketing from Prairie View A&M University. He was awarded an honorary doctorate in philosophy from Fort Valley (Georgia) State University and an honorary doctorate in humane letters from Texas Southern University.

Earl McNiel (Senior VP and CFO)

Earl McNiel joined the company in March of 2012. Mr. McNiel has more than thirty years of experience with public companies, primarily in the energy and waste management industries, and has broad experience in the areas of corporate finance, mergers and acquisitions, and financial reporting. From 2004 to 2009, he served as Vice President and Chief Financial Officer of Transmeridian Exploration Incorporated, an international independent oil and gas exploration and production company. From 1994 to 2004, he was a senior executive with Pride International, Inc., an international oilfield service provider and drilling contractor, serving as Chief Financial Officer, Vice President of Planning & Corporate Development, and Chief Accounting Officer. Prior to joining Pride, Mr. McNiel served as a senior financial executive with several waste management companies and an oilfield service company. He began his career in public accounting with a major international accounting firm.

Segun Omidele (Senior VP, Exploration & Production) Segun Omidele was named Senior Vice President, Exploration & Production in March 2012. Mr. Omidele joined the company as Senior Vice President, Business Development & New Ventures in September 2011. Previously, he was Senior Vice President, Exploration and Production for Allied Energy Corporation, a subsidiary of CAMAC International Corporation, since October 2008. Prior to joining Allied Energy Corporation, Mr. Omidele worked for 28 years with Shell companies in Nigeria, the UK and the USA where he held several technical and management positions. His last position with Shell was Regional Resource Volume Manager for Africa. Mr. Omidele holds a Bachelor's degree in Petroleum Engineering from the University of Ibadan, Nigeria and a Masters degree in Petroleum Engineering from the University of Houston, USA. He is also a graduate of the Advanced Management Program of Harvard Business School. Mr. Omidele is a member of the Society of Petroleum Engineers and the Nigerian Society of Engineers.

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Financials Forecasts

Income Statement

Source: CSL estimates, Note: US$90/bbls oil price assumption from 2016 onwards

USDm, YE December 2009 2010 2011 2012 2013 2014e 2015e 2016e 2017e 2018e 2019e 2020e

Oil & liquids production (mb/d) 0 0 0 0 0 7.000 20.000 25.000 18.750 28.063 35.047 32.410

Gas production (mmcf/d) 0 0 0 0 0 0.000 0.000 0.000 0.000 0.000 0.000 0.000

Total production (mboe/d @ 5.8) 0 0 0 0 0 7 20 25 19 28 35 32

Growth 185.7% 25.0% -25.0% 49.7% 24.9% -7.5%

Revenue 0.07 20.7 37.9 16.6 7.9 255.5 693.5 821.3 631.3 968.5 866.7 888.4

Cost of Sales -0.44 -34.3 -30.9 -0.3 0.7 -72.8 -73.0 -93.5 -71.9 -110.3 -266.1 -166.8

D, D & A -0.13 -4.2 -13.5 -10.8 -4.5 -32.0 -51.2 -83.2 -83.2 -83.2 -83.2 -80.0

Gross Profit -0.5 -17.9 -6.4 5.5 4.0 150.7 569.3 644.5 476.2 775.0 517.5 641.6

Admin expenses -9.03 -13.5 -13.3 -11.0 -14.5 -15.3 -41.6 -49.3 -37.9 -58.1 -52.0 -53.3

Exploration write-off -1.88 -1.1 -0.9 -3.2 -5.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Impairment charge -0.22 -186.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Other op costs 0.00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Operating profit -11.6 -218.7 -20.7 -8.7 -16.0 135.4 527.7 595.2 438.4 716.9 465.5 588.3

Investment income 0.04 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Finance costs -0.00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Other gains/(losses) 0.00 0.0 0.0 4.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Associates 0.00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Pre-tax profit -11.6 -218.7 -20.7 -4.5 -16.0 135.4 527.7 595.2 438.4 716.9 465.5 588.3

Tax 0.00 0.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Net income/loss -11.6 -218.2 -20.7 -4.5 -16.0 135.4 527.7 595.2 438.4 716.9 465.5 588.3

Loss from discontinued ops 0.00 0.0 -4.0 3.2 -0.0 -0.0 -0.0 -0.0 -0.0 -0.0 -0.0 -0.0

Minority interests profit/(loss) 0.10 0.3 -0.1 -0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Net income/loss for the period -11.6 -218.2 -24.7 -1.4 -16.0 135.3 527.7 595.2 438.3 716.9 465.4 588.2

EBITDA -11.5 -214.4 -7.2 2.1 -11.4 167.4 578.9 678.4 521.6 800.1 548.7 668.3

EPS -0.114 -0.760 -0.066 -0.004 -0.042 0.107 0.418 0.471 0.347 0.567 0.368 0.464

Gross profit/boe N.A N.A N.A N.A N.A 58.98 77.99 70.63 69.59 75.66 40.45 54.23

EBIT/boe N.A N.A N.A N.A N.A 52.98 72.29 65.23 64.05 69.99 36.39 49.73

Net Inc/boe N.A N.A N.A N.A N.A 52.98 72.29 65.23 64.05 69.99 36.39 49.73

EBITDA/boe N.A N.A N.A N.A N.A 65.50 79.30 74.35 76.21 78.11 42.89 56.49

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Cashflow Statement



Profit/loss for the period -11.5 -230.5 -24.9 -6.1 -15.9 135.4 527.7 595.2 438.4 716.9 465.5 588.3

Forex gain/loss 0.0 0.0 0.0 0.0 1.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Depreciation 0.1 4.2 13.5 10.8 4.5 32.0 51.2 83.2 83.2 83.2 83.2 80.0

Unsuccessful exploration costs

Impairment 0.2 186.2 - - - 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Decomissioning liabilities 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Loss on disposal of property 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Income tax expense/benefit 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Fair value loss on derivatives 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Share based payments 3.5 4.6 2.5 0.7 2.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Increase in provisions 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Discontinued ops 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Other 0.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Op Cash Flow before working capital -6.9 -35.5 -9.0 5.4 -8.4 167.4 578.9 678.4 521.6 800.1 548.7 668.3

Increase/decrease in inventories -0.1 5.5 0.1 - - 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Increase/decrease in receivables -0.1 3.5 -8.5 12.8 -3.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Increase/decrease in payables 0.1 -0.1 35.8 -20.8 0.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Current tax paid 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Others 0.8 35.1 -33.1 -3.4 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6

Net cash used in operating activities -6.1 8.6 -14.7 -5.9 -7.4 171.0 582.5 682.0 525.2 803.7 552.3 671.9

Proceeds from disposals - - - 2.4 - 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Purchase of PP&E - Oil & Gas assets -0.5 -39.9 -7.2 -3.6 -0.6 -200.0 -120.0 -200.0 0.0 0.0 -200.0 -100.0

Purchase of PP&E - Others 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Exploration & evaluation expenditure 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Purchase of investments 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Cash from discontinued ops 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Net change in working capital 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Investments -0.5 1.5 0.3 2.0 - 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Others 0.9 -0.1 0.0 0.5 - 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Net cash used in investing activities -0.0 -38.5 -6.9 1.2 -0.6 -200.0 -120.0 -200.0 0.0 0.0 -200.0 -100.0

Interest paid

Repayment of borrowings - - -25.0 -10.1 - -10.0 -10.0 -10.0 -10.0 -10.0 -10.0 -10.0

Proceeds from borrowings - - 31.0 5.0 4.4 100.0 0.0 0.0 0.0 0.0 0.0 0.0

Proceeds from issue of convertible pref shares 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Proceeds from issue of ordinary shares, net 0.0 55.2 0.2 0.0 - 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Treasury shares 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Net cash from financing activities 0.0 55.2 6.2 -5.1 4.4 90.0 -10.0 -10.0 -10.0 -10.0 -10.0 -10.0

Net decrease/increase in cash -6.1 25.3 -15.4 -9.8 -3.7 61.0 452.5 472.0 515.2 793.7 342.3 561.9

Cash at beginning of period -0.0 -0.0 0.0 0.0 0.0 61.0 513.5 985.5 1,500.7 2,294.4 2,636.6

Forex changes -0.0 0.0 0.0 -0.0 0.0

Cash at end of period -0.0 -0.0 0.0 0.0 0.0 61.0 513.5 985.5 1,500.7 2,294.4 2,636.6 3,198.5

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Balance Sheet



Intangible assets

PP&E 0.6 207.3 211.8 215.4 216.0 384.0 452.8 569.6 403.2 320.0 468.8 536.8

Exploration & evaluation assets 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Accumulated depreciation -0.2 -2.3 -15.6 -26.4 -30.9 -80.0 -80.0 -80.0 -80.0 -80.0 -80.0 -80.0

Goodwill 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Financial assets 0.5 0.0 0.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Deferred tax asset 0.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Deposit paid 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Other long term receivable 0.0 0.4 0.2 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

Restricted cash 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Non-current assets 1.5 205.0 196.4 189.1 185.2 304.1 372.9 489.7 323.3 240.1 388.9 456.9

Inventories 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Other current financial assets

Trade and other receivables 0.1 10.4 18.9 6.1 1.1 36.1 98.0 116.0 89.2 136.8 122.4 125.5

Cash 3.6 28.9 13.6 3.8 0.2 61.0 513.5 985.5 1,500.7 2,294.4 2,636.6 3,198.5

Other current assets 2.2 3.1 1.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Assets held for sale

Current assets 5.9 42.5 34.3 9.9 1.3 97.1 611.4 1,101.5 1,589.8 2,431.2 2,759.0 3,324.0

Total Assets 7.4 247.5 230.7 199.0 186.5 401.2 984.3 1,591.2 1,913.1 2,671.3 3,147.9 3,780.9

Trade and other payables 0.17 0.1 35.3 15.1 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2

Borrowings 0.0 0.0 0.0 0.0 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5

Current tax liabilities

Deferred consideration & payables 1.9 38.9 2.7 2.8 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4

Other creditors 0.0 1.9 1.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Current liabilities 2.0 40.9 39.7 17.9 20.2 12.7 12.7 12.7 12.7 12.7 12.7 12.7

Deferred tax liabilities

Borrowings 0.0 0.0 6.0 0.9 0.0 33.0 0.0 0.0 0.0 0.0 0.0 0.0

Provisions 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Retirement benefit obligation 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Deferred revenue 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Other long term payables 0.0 0.0 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Non current liabilities 0.0 0.0 6.0 0.9 0.1 33.0 0.0 0.0 0.0 0.0 0.0 0.0

Total Liabilities 2.0 40.9 45.7 18.8 20.2 45.7 12.7 12.7 12.7 12.7 12.7 12.7

Net Assets 9.4 288.3 276.3 217.9 206.7 446.9 997.0 1,603.9 1,925.9 2,684.0 3,160.7 3,793.6

Share capital 0.0 0.2 0.2 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4

Additional paid-in capital 26.0 458.5 461.2 462.6 464.6 219.7 443.5 982.8 1,461.7 1,941.2 2,669.4 3,179.5

Translation reserve

Other reserves 0.1 -0.5 -0.5 -0.8 -0.9

Retained earnings/deficit -20.5 -250.9 -275.8 -281.9 -297.9 135.4 527.7 595.2 438.4 716.9 465.5 588.3

Contributed surplus 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Equity attributable to shareholders 5.7 207.3 185.0 180.2 166.2 355.4 971.6 1,578.5 1,900.4 2,658.5 3,135.2 3,768.1

Minority interests -0.3 -0.6 0.0 -0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Total Equity 5.4 206.6 185.0 180.2 166.2 355.4 971.6 1,578.5 1,900.4 2,658.5 3,135.2 3,768.1

Total Liabilities and Equity 7.41 247.48 230.66 199.05 186.48 401.15 984.31 1,591.19 1,913.12 2,671.25 3,147.93 3,780.86

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Key Risks

Apart from the risks common to all E&Ps in terms of exploration and operational risk, the key risks investors need to be aware of when investing in CAMAC are:

1) Exploration risk: OML 120/121 exploration prospects may prove to be dry wells, and even in the event of a discovery, may not have sufficient proven reserves to justify economic development.

2) Capex/cost risk: Currently there is a high demand for oil and gas exploration and production equipment and personnel, and this may result in the company encountering delays or incurring higher than anticipated costs in its exploration and production activities.

3) Operator risk: Oil and gas exploration activities involve certain operating hazards such as blowouts and mechanical failures, which can cause fires, explosions, hydrocarbon seepage or spillage or chemical spills, which may lead to pollution or contamination.

4) Country risk: CAMAC operates offshore Nigeria, Kenya, Ghana and the Gambia, and onshore Kenya. All four countries have specific country risks associated with them. In Nigeria this specifically includes terrorism which can lead to disruption of facilities and installations onshore, and potential health risks associated with the Ebola virus

5) Fiscal risk: The risk of a change in the petroleum fiscal regimes where CAMAC currently operates is high in our opinion.

6) Limited financial resources: CAMAC has limited financial resources and will need to farm out OML 120/121 to finance any planned exploration programme.

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Eland Oil & Gas

Investment conclusion Eland Oil & Gas is now in a prime position to increase production from its core asset OML 40 in the Niger Delta which could provide it with important first cash flows enabling the company to expand its footprint throughout Nigeria with further acquisitions in addition to the recent Ubima (OML 17). The recent acquisition of a 40% stake in Ubima in OML17 for 2C resources of 50mboe for US$10m implies a competitive price of US$0.50/boe versus a Nigerian onshore average of US$1.54/boe. A cost recovery scheme allowing 88% of revenues to be recovered ensures an early payback from this asset with additional upside through a gas utilisation project. The recently awarded pioneer status according to our estimates could nearly double the existing core NAV estimate and provides impetus to develop OML 40 within the specified tax shield time period until mid 2019. To date Eland has been inhibited at OML 40 in delays transpiring from the operator NPDC, and we believe through its new tax status, and improved infrastructure it is well placed to leverage the development of OML 40 now. We initiate coverage with a BUY recommendation and target price of 269p/share based on our core NAV which includes appraisal upside in OML 40. We have not included any exploration upside given the fact any drill prospects are not drill ready within the next 12 months. Eland Oil & Gas reported an upgrade to its oil and gas reserves and resources last year, illustrating the excellent medium- to long-term potential within OML 40, which we expect will begin to be converted into value with the start of drilling planned for H2 2014. Further upgrades could occur in our opinion based on further appraisal and development drilling on OML 40 combined with exploration on known prospects and leads located in the Western and Eastern sections of the block..

Company Overview Eland Oil & Gas obtained a listing on the AIM market in September 2012. The listing raised £118m which in turn enabled Eland to complete the purchase of a 45% interest from Shell in OML 40. Although Eland Oil & Gas is a relatively new company the management have a long experience of working in Nigeria with many of them having worked previously for Addax Petroleum. Eland has achieved first oil from OML 40 in February 2014 at 3,500bpd, with a targeted exit rate of 7,000bpd by the end of 2014 through the addition of another producing well. First oil was achieved after a number of delays caused by the operator NPDC. Production is then forecast to increase to 34,000bpd under the current 2P scenario (gross). 2P reserves and 2C resources currently stand at 177mmboe, split 82mmboe 2P and 95mmboe 2C. Scope to increase these estimates exists in our opinion. For example at OML 40 only 18 wells ever drilled across this large licence area. Reserve estimates There both these numbers, particularly the 2C, to rise substantially in the next few years once Eland starts its drilling campaign.

BUY (Price: 86p – Target: 269p)

Key data


2012A 2013A 2014E 2015E

Sales 0 0.0 1.7 14.2

Net. Inc. -14 -26 35 112

EPS -0.31 -0.19 0.26 0.77

P/E (x) -4.66 -7.55 5.56 1.85

Div Yield (%) NM NM NM 5.1

Mkt. cap.(US$m) 129

Free float 92%

Bloomberg ELA LN

Reuters ELA.L


Contact information

London: +44 (0) 20 7220 1043




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Valuation We have valued Eland using a NAV analysis which utilises a 12% discount rate and US$90/bbl oil price base from 2016 onwards. Our core NAV which includes the value of appraisal assets in OML40 and Pioneer Tax is £2.69/share. If we exclude Pioneer Tax this falls to £1.37/share.

Eland Oil & Gas Valuation

Eland Oil & Gas NAV Waterfall


Reserves WI¹ Unrisked Risked

Block Field/Prospect WI (%) EI (%) mmboe US$/boe US$m US$/share CoS² US$m £/share

Production

OML 40³ 22.05% 35.90% 24 11.07 260 1.79 70% 182 0.75

Appraisal

OML 40³ 22.05% 35.90% 16 11.44 186 1.28 60% 112 0.46

OML 17 Ubima 40.00% 40.00% 20 2.75 56 0.38 60% 33 0.14

Less net debt/cash 17 0.07

Less corporate items -12 -0.05

Pioneer tax 320 2.20 30% 96 1.32

Core NAV 60 4.33 260 1.79 428 2.69

Current share price 0.87

% Upside/(Dow nside) 209%

Exploration

Other prospects 22.05% 35.90% 120 0.66 79 0.54 40% 31 0.13

Exploration NAV 120 0.66 79 0.54 31 0.13

TOTAL RENAV 180 1.89 339 2.33 459 2.82


Note: ¹ Gross recoverable resources ² Chance of Success ³ EOG owns 49% of Elcrest which owns 45% of the licence

12% NPV, US$90/bbl L-T

0.00

0.50

1.00

1.50

2.00

2.50

3.00

£/share

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Exploration assets are located at OPL 452 where it has a 40% option to acquire the asset following evaluation. We consider this to be out with the current 12 month investment time farm with the primary focus being to develop OML 40 and have therefore excluded it from our core NAV. We have also shown the value of achieving pioneer tax status on a 2P basis only to be worth £1.32/share. We have discounted the tax effect of this over 5 years using our 12% discount rate and risked this by 30%. The acquisition of Ubima adds an additional 50mmboe of 2C reserves to Eland’s existing base at OML 40 making 95mmboe. 2P and 2C reserves and resources currently stand at 177mmboe (gross). The near term objective at Ubima will be to convert Ubima 2C resources into 2P reserves through development.

Eland Gross Reserves (post Ubima acquisition)

Source: CSL

Gross (mmboe) Ubima (OML 17) OML 40 Total % Change

1P 0 38 38 0%

2P 0 82 82 0%

3P 0 105 105 0%

2C 50 45 95 111%

PR 0 120 120 0%

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Development Plan OML 40 is a legacy asset from Shell’s operations in the Niger Delta dating back to the 1970s. Between 1975 and 2006 Shell produced 43mmbbls from the Opuama field within OML 40, however from early 2006 Shell decided to stop production due to ongoing security problems. The Opuama field has 56 mmbbls (2P, net) remaining to develop according to the last CPR published in August 2013 and therefore represents an excellent redevelopment opportunity with no exploration risk. The underlying security issues which prevented Shell from producing have been mitigated by the federal government amnesty programme in 2009 which offered unemployed youths from the Niger Delta the opportunity to train in the oil and gas industry through government sponsored schemes. First oil from OML 40 block was achieved in early 2014, after a delay of around a year. Almost all indigenous E&P companies that acquired assets sold by Shell have found the NPDC to be slow and unresponsive, and Eland is no exception, hence the delay in first oil production from OML 40. We believe the problem within the NNPC is one of resources, both financial and manpower. The recent announcement of achieving pioneer tax status creates an incentive to accelerate the development of OML 40 within a window of 5 years.

OML 40 Fields and Planned Facilities

Source: Eland

The forward plan this year is to drill an additional infill well at Opuama to compliment the existing two producing wells with a flow rate of around 3.5kbpd. The plan is to exit 2014 on 7kbpd with this third well onstream by the end of the year. The redevelopment plan of Opuama plans to increase recovery rates via directional wells targeting under saturated reservoirs and any existing gas cap.

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The whole field benefits from having a strong aquifer which ultimately could improve the recovery rates from the field.

OML 40 Opuama Redevlopment ties

Source: Eland

Beyond drilling a well in 2014, the priority for Eland particularly given its recently achieved pioneer tax status is to fast-track development at OML 40. A detailed field development plan for OML 40 was completed in 2013. Eland plans to drill a total of seven new development wells, which are aiming to infill targets in four main reservoirs. It also includes carrying out appraisals with the possibility of developments on three so-called intra reservoirs, which carry at present total contingent resources of some 8 mmbbl. All new wells will be drilled from a central location near the flowstation minimising the environmental and social impact, increasing efficiency and ensuring the security and safety of the facilities. The development concept is to drill a total of seven new wells which include five deviated wells and two horizontal wells. The wells will be drilled using a swamp rig after dredging of the existing access canals to enable easy access. After completion of the wells the Opuama gross production is expected to reach over 25,000 bopd.

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In addition to the producing Opuama field there are other assets which could be developed with OML 40 including the Gbetiokun field (Gross 2P 27.6mmboe) where a number of drilling locations have been identified. Gbetiokun is located 63km North West of Warri on the boundary of OML 40 and OML 49, which is operated by Chevron. The field is known as Gbetiokun in OML 40 whilst the extension of the field in OML 49 is called Bime. ̀ The field was discovered by well Gbetiokun 1 in 1987 and presently four wells have been drilled on the structure (two in OML 40 and two in OML 49). `` The Bime wells are located close to the licence boundary between OML 40 and OML 49 and provided valuable information about the eastern flank of the field. The extension to the east is very limited with the second Bime appraisal well not finding any hydrocarbons. The latest appraisal well Gbetiokun 2 was drilled in August 1991 on the western flank of the field where it found a significant number of reservoirs containing hydrocarbons. A total of 20 hydrocarbon reservoirs have been identified in the Gbetiokun field. The crude is generally characterised as having a low viscosity, high API gravities from 39-41_and also being under-saturated. Pressure, Volume and Temperature (PVT) samples were taken in the discovery well and the results indicate the presence of good quality oil. The reservoirs are analogous to those found in Opuama and it is considered very likely that they will have moderate to strong aquifer drive. The field development plan envisages the use of an early production facility with a 30km wet crude export pipeline planned to join the Opuama-Otumara export pipeline system.

OML 40 Export Pipelines

Source: Eland

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OML 17 – Ubima Field Eland recently announced the acquisition of the Ubima Field in OML 17 from Allgrace Energy Limited. Ubima is located in the northern part of Rivers State located in OML 17 which is held by NNPC (55%), Shell (30%), TOTAL (10%), and ENI (5%). To date four wells have been drilled in the field between the 1960s and 1981 with hydrocarbons being encountered in all four across multiple stacked reservoirs.

OML 40 Export Pipelines

Source: Eland

Ubima-1 well was suspended and never completed for development. Eland intends to re-enter the well through the Wester Ord with an extended production test being performed. Oil production will initially be trucked to the Ubima export pipeline. The development plan aims to drill four development wells with full production commencing nine to twelve months. The full development programme is estimated by Eland to cost US$125m, with around two thirds of this from the initial four wells estimated to cost US$20m each or US$80m according to our forecasts. The farm-in agreement for 40% of Ubima will cost US$10m (split US$7m signature bonus and US$3m production bonus, (contingent on production and Ministerial consent for the farm-in). This implies a value of US$0.50/boe for 2P and 2C reserves and resources of 50mmboe (split 34mmbbls oil, 97bcf (16mmboe) gas which compares well with other recent transactions averaging US1.54/boe over the last 5 years. Importantly for Eland the terms of the agreement entitle Wester Ord to 88% of cashflows under a cost recovery scheme. Our NAV indicates a value of US$33m (net risked) for this asset currently which implies a value of 14p. We have not ascribed any additional value if this asset achieves pioneer tax status

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Exploration Eland’s core exploration area is in OML 40 where 120mmboe (unrisked) prospective resources have been identified using existing 3D seismic shot by Shell. Exploration prospects are divided between the Western and Eastern sections where 3D has been shot. In the western area the prospects are Amobe, Polobo South and Opuama North. In the eastern area of OML 40 there are a large number of prospects including covered by 3D seismic surveys. The central part of OML 40 is not covered by 3D seismic surveys, however the previous operator identified an number of sizeable leads within the area using 2D seismic that had been conducted by Shell. Eland are planning 3D seismic within the area in the future. Furthermore, upside to existing prospective resource estimates exists through possible extensions at Ojumole and Tsekelewu (outside OML 40) into the OML 40 block on the Western side. In addition a number of deep turbidite prospects have been identified including Adagbassa Deep, Polobo Deep, Abiala Deep, and Gbetiokun Deep. These prospects are too too immature to be defined within the prospective resource category and require further detailed studies to mature as drillable prospects.

OML 40 Leads and Prospects

Source: Eland

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Executive Management Team Henry George Wilson (Non Executive Chairman) Harry has over 35 years’ international experience in upstream oil and gas initially as an explorer with British Petroleum and then as the founder and Chief Executive Officer of several independent oil companies. During this period, he led listings for four companies and has been a director of public companies both in the UK and abroad across a number of sectors. Harry graduated with a BSc Hons in Physics from Manchester University and attended the Insead Business School in France. George Maxwell (CEO) George has over 20 years oil industry experience in both the producing and service/manufacturing arena. He was Business Development Manager for Addax and, prior to this, Commercial Manager in Geneva. George joined Addax in 2004 and held the General Manager’s position in Nigeria, responsible for finance, fiscal and commercial activities. Prior to this, George was Europe & Africa Vice President of Finance for ABB Oil & Gas. He held a similar position in Houston, for its operations in 10 countries. George was Finance Director in Singapore for Asia Pacific and Middle East, handling currency swaps and minimising exposures during the Asian financial crisis of the late 1990s.George graduated from the Robert Gordon University, Aberdeen with an MBA. Louis Emmanuel Castro (CFO) Louis has over 25 years’ corporate finance and broking experience, in the UK and overseas, during which time he has been responsible for a number of oil, gas and mining IPOs and capital raisings. Louis is Managing Director of Northland Capital Partners in London, previously being head of corporate finance at Matrix LLP and at Insinger de Beaufort. Prior to this Louis spent eight years at Williams de Broe, six years at Price Waterhouse and three years at SG Warburg. He has widespread international expertise, having advised the boards of companies worldwide, including in the oil & gas, mining, and energy sectors. Louis is a Fellow of the Institute of Chartered Accountants in England and Wales and graduated with a BSc & BComm (Hons) in Engineering Production & Economics from Birmingham University. Louis was appointed to the Board as Non-Executive Director in August 2012.

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SWOT Analysis

Financials Forecasts

Income Statement



Strong technical team based in Aberdeen Single producing asset currently

Management have long history in Nigeria via Addax

Securing infrastructure issues through new pipeline

FCF positive in 2015


Exploration prospects MEND disruption

Upside to existing reserve estimates NNPC delays

Acquisitions via continued IOC sales and marginal rounds

US$m, YE December 2010 2011 2012 2013 2014e 2015e 2016e 2017e 2018e 2019e 2020e

Oil & liquids production (mb/d) 0.0 0.0 1.5 13.0 11.2 8.9 7.2 5.7 4.6

Gas production (mmcf/d) 0.0 0.0 0.7 6.7 2.2 14.2 2.2 2.2 2.2

Total production (mboe/d @ 5.8) 0.0 0.0 0.0 0.0 1.7 14.2 11.6 11.4 7.5 6.1 5.0

Growth 754.5% -18.4% -1.4% -33.9% -19.0% -18.8%

Revenue 0.0 0.0 56.3 451.1 367.2 314.3 260.4 216.3 180.2

Cost of Sales 0.0 0.0 -18.3 -138.6 -112.1 -92.5 -76.1 -62.7 -51.6

D, D & A 0.0 0.0 -9.0 -72.1 -58.7 -50.2 -41.6 -34.6 -28.8

Gross Profit 0.0 0.0 0.0 0.0 29.0 240.4 196.5 171.5 142.7 119.1 99.8

Admin expenses -1.7 -1.0 -8.7 -8.4 -7.0 -7.2 -7.4 -7.5 -7.7 -7.9 -8.1

Exploration write-off

Impairment charge

Other op costs -2.4 -4.3 -16.5 -4.0 -4.5 -5.0 -5.0 -5.0 -5.0 -5.0

Operating profit -1.7 -3.4 -12.9 -24.9 18.0 228.7 184.1 159.0 130.0 106.2 86.6

Investment income 0.2 0.0 0.0 32.4 32.4 32.4 32.4 32.4 32.4 32.4

Finance costs -0.2 -14.5 -1.2 -0.9 1.2 3.2 7.0 11.9 16.8 21.0 25.0

Other gains/(losses)

Associates

Pre-tax profit -1.8 -17.7 -14.2 -25.8 51.6 264.3 223.5 203.3 179.2 159.6 144.0

Tax 0.0 -0.3 -16.9 -148.8 -123.5 -111.0 -96.0 -83.9 -74.2

Minority interest

Net income/loss -1.8 -17.7 -14.2 -26.1 34.7 115.5 100.0 92.3 83.1 75.7 69.8

Loss from discontinued ops

Net income/loss for the period -1.8 -17.7 -14.2 -26.1 34.7 115.5 100.0 92.3 83.1 75.7 69.8

EBITDA 0.0 -2.4 -4.3 -16.5 14.3 134.1 107.1 87.5 71.1 57.7 46.6

EPS (Basic) -0.04 -0.38 -0.31 -0.19 0.26 0.79 0.69 0.64 0.57 0.52 0.48

EPS (Diluted) -0.04 -0.38 -0.31 -0.19 0.26 0.79 0.69 0.64 0.57 0.52 0.48

DPS

Gross profit/boe 48.00 46.49 46.57 41.25 51.88 53.45 55.12

EBIT/boe 29.81 44.24 43.64 38.24 47.25 47.65 47.87

Net Inc/boe 57.34 22.34 23.70 22.20 30.23 33.98 38.57

EBITDA/boe 23.64 25.95 25.38 21.05 25.86 25.88 25.76

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Cashflow Statement


Balance Sheet


US$m, YE December 2010 2011 2012 2013 2014e 2015e 2016e 2017e 2018e 2019e 2020e

Profit/loss for the period -1.5 -1.4 -19.6 -13.3 34.7 115.5 100.0 92.3 83.1 75.7 69.8

Financing costs 0.0 0.0 1.2 3.2 7.0 11.9 16.8 21.0 25.0

Forex gain/loss

Depreciation 0.0 0.0 9.0 72.1 58.7 50.2 41.6 34.6 28.8

Op Cash Flow before working capital -1.5 -1.4 -19.6 -13.3 44.9 190.8 165.7 154.4 141.5 131.2 123.6

Increase/decrease in inventories

Increase/decrease in receivables

Increase/decrease in payables

Current tax paid

Others

Net cash used in operating activities -1.5 -1.4 -19.6 -13.3 44.9 190.8 165.7 154.4 141.5 131.2 123.6

Proceeds from disposals

Purchase of PP&E - Oil & Gas assets -16.9 -140.0 -6.1 -46.3 -4.4 0.0

Purchase of PP&E - Others -0.4 -1.0 -1.0 -1.0 -1.0 -1.0 -1.0 -1.0

Net cash used in investing activities -0.4 -16.9 -140.0 -6.1 -47.3 -5.4 -1.0 -1.0 -1.0 -1.0 -1.0

Interest paid

Repayment of borrowings -148.4

Proceeds from borrowings 163.3 0.1

Proceeds from issue of convertible pref shares 2.6

Proceeds from issue of ordinary shares, net 4.1 181.2 14.0

Net cash from financing activities 6.7 14.9 181.3 0.0 14.0 0.0 0.0 0.0 0.0 0.0 0.0

Net decrease/increase in cash 4.8 -3.4 21.7 -19.4 11.6 185.3 164.7 153.4 140.5 130.2 122.6

Cash at beginning of period 0.0 4.9 1.4 24.5 3.9 15.4 200.8 365.5 518.9 659.4 789.7

Forex changes 0.1 -0.1 1.4 -1.2

Cash at end of period 4.9 1.4 24.5 3.9 15.4 200.8 365.5 518.9 659.4 789.7 912.3

US$m, YE December 2010 2011 2012 2013 1H 14 2014e 2015e 2016e 2017e 2018e 2019e 2020e

Intangible assets 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8

PP&E 0.4 17.2 174.9 175.1 179.1 212.4 144.8 86.1 35.9 -5.7 -40.2 -69.0

Non-current assets 0.4 17.2 174.9 175.1 182.9 216.2 148.6 89.9 39.7 -1.9 -36.4 -65.2

Inventories 1.3

Other current financial assets

Trade and other receivables 0.6 0.6 2.1 4.2 10.7

Cash 5.0 1.4 24.5 3.8 19.7 15.3 200.6 365.3 518.7 659.3 789.5 912.1

Other current assets

Assets held for sale

Current assets 5.6 2.0 26.6 8.0 31.7 15.3 200.6 365.3 518.7 659.3 789.5 912.1

Total Assets 6.0 19.2 201.5 183.2 214.6 231.5 349.2 455.2 558.4 657.4 753.1 846.9

Trade and other payables -0.9 -8.8 -3.3 -20.4 -29.4 -9.1 -11.3 -17.3 -28.2 -44.0 -64.0 -88.0

Borrowings

Convertible redeemable loan notes -15.0

Cum convertible redeemable loan notes -2.5 -2.7

Current tax liabilities

Deferred consideration & payables

Other creditors

Current liabilities -3.4 -26.5 -3.3 -20.4 -29.4 -9.1 -11.3 -17.3 -28.2 -44.0 -64.0 -88.0

Deferred tax liabilities

Borrowings

Decommissioning provision -17.7 -12.0 -12.1 -12.1 -12.1 -12.1 -12.1 -12.1 -12.1 -12.1

Finance lease obligations

Deferred revenue

Non current liabilities 0.0 0.0 -17.7 -12.0 -12.1 -12.1 -12.1 -12.1 -12.1 -12.1 -12.1 -12.1

Total Liabilities -3.4 -26.5 -21.0 -32.4 -41.6 -21.3 -23.5 -29.5 -40.4 -56.2 -76.2 -100.2

Net Assets 2.6 -7.3 180.5 150.8 173.0 210.2 325.7 425.7 518.1 601.2 676.9 746.7

Share capital 4.3 4.3 214.8 214.8 241.4 214.8 214.8 214.8 214.8 214.8 214.8 214.8

Additional paid-in capital

Translation reserve 0.2 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4

Other reserves -0.1 -0.2 -10.5 -15.5 -15.5 -15.5 -15.5 -15.5 -15.5 -15.5 -15.5 -15.5

Retained earnings/deficit -1.8 -10.3 -15.1 -11.7 -9.4 23.0 138.5 238.5 330.8 413.9 489.6 559.4

Equity reserve 0.2 8.0 8.0 8.0 14.8 4.7 8.0 8.0 8.0 8.0 8.0 8.0

Equity attributable to shareholders 2.6 2.0 198.6 196.9 232.7 228.4 347.2 447.2 539.5 622.6 698.3 768.1

Minority interests -9.3 -18.1 -46.2 -59.7 -18.1 -21.4 -21.4 -21.4 -21.4 -21.4 -21.4

Total Equity 2.6 -7.3 180.5 150.8 173.0 210.3 325.8 425.8 518.1 601.2 676.9 746.7

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Mart Resources Investment Conclusion We reiterate our BUY recommendation on Mart with a DCF-derived RENAV which indicates a value of US$672m or C$1.66/share at current exchange rates. Our estimated core NAV is US$467m or C$1.44/share, implying that Mart is currently trading at a discount to its core value. We are confident that through the development programme at Umusadege, which involves horizontal drilling and exploration activities planned over the next 12 months, this could add a further C$0.63/share, which implies 45% upside from here. Unusually for an E&P company Mart has paid a C$0.05/share quarterly dividend in 2013/14, although this has been suspended recently in order for the company to assess its capex requirements for H2 2014 and into 2015 which are a function of the development and exploration programme. We have not included any value for the acquistion of OML 18 on the basis that this still needs to be ratified by the Nigerian government, however we know that Mart have paid US$135m for a 10% indirect stake in the asset which could increase Mart’s production base significantly if fully developed.

Company overview Mart Resources was an early entrant to the Nigerian oil patch and was the first foreign company to partner with an indigenous E&P company. Mart Resources is the technical and financial partner of Midwestern Oil & Gas and Suntrust who in turn own the Umusadege marginal oil field. Mart provides technical advice and is entitled to a 50% economic interest in the Umusadege field. The company also funds 100% of field capex and is able to recover these capital costs via an adjustable economic interest that can rise to 82.5% when Mart is in cost recovery mode. Within our forecasts we have assumed a 60% economic interest and have applied this to our valuation Reserves attributable to Mart Resources economic interest in the Umusadege field are 16.9mmbbls on a 2P basis, and 11.8mmbbls on a 1P basis. We understand the Ministry of Petroleum Resources carries a higher recoverable reserve estimate for the Umusadege field (49.3mmbbls on a gross basis). The service contract with Midwestern and Suntrust is currently Mart’s sole asset. The company recently acquired an 10% indirect interest in OML 18 with a US$135m cash payment being made. We estimate this asset is worth US$978m based on prevailing 2P and 2C multiples in the onshore Nigerian oil space with potential to lift production immediately by 2-3kboepd (net) from 30 prpoducing wells.

BUY (Price: C$0.85 – Target: C$1.66)

Key data


2012A 2013A 2014E 2015E

Sales 161.4 136.04 306.6 748.98

Net. Inc. 58.0 35.5 107.3 235.5

EPS 0.16 0.10 0.30 0.66

P/E (x) 5.2 8.5 2.8 1.3

Div Yield (%) 14% 14% 7% 7%

Mkt. cap.(US$m) 303

Free float 96%

Bloomberg MMT CN

Reuters MMT.V


Contact information

London: +44 (0) 20 7220 1043




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Mart Resources Valuation Mart is currently trading near our implied core NAV value of C$1.44/share, using a US$90/bbl base and 12% discount rate. If we include the value of additional appraisal at Umusadege and exploration of known prospects and leads in Umusadege West and East our RENAV value is C$1.66/share. Given the fact that Mart intends to rollout its appraisal and exploration programme in the next 12 months gives us comfort that this valuation could be achieved and crystallised into any valuation. Examining the risks behind this we have attributed an 80% risk factor to appraisal prospects at Umusadege. Our risked value of C$0.31/share for exploration at Umusadege includes development risk of 60% and geological risk of 50% to arrive at our calculated 30% risk factor. Currently Umusadege exploration areas (West and East) have a P50 estimate of 20mmbbls, with an upside on a P10 basis to 38mmbbls. As we have seen previously at Umusadege existing producing area, reserve estimates have risen as exploration and appraisal drilling has proceeded, and we believe further exploration at Umusadege could demonstrate the same upside risk. Our RENAV estimates could therefore be conservative on that basis and importantly do not at this stage include the value of Mart’s 10% indirect stake in OML 18 which is still subject to government approval.

Mart Resources Valuation

Reserves WI¹ Unrisked Risked

Block Field/Prospect WI mmboe US$/boe US$m US$/share CoS² US$m C$/share

Production

OML 56 Umusadege 50-82.5%³ 16.9 29.75 503 1.41 100% 503 1.55

Less net debt/cash -104 -0.29

Less corporate items -2 -0.01

Core NAV 16.9 29.75 503 1.41 397 1.22

Appraisal

OML 56 Umusadege upside 50-82.5%³ 6.1 21.42 131 0.37 80% 105 0.32

D&A NAV 6.1 21.42 131 0.37 105 0.32

Exploration

OML 56 Umusadege East 50-82.5%³ 12.0 10.00 120 0.34 30% 36 0.11

Exploration NAV 12.0 10.00 120 0.34 36 0.11

Total RENAV 35.0 21.53 753 2.11 537 1.66

Current share price 1.43

% Upside/(Downside) 16%


Note: ¹ Gross recoverable resources ² Chance of Success ³ WI varies subject to cost recovery

12% NPV, US$90/bbl L-T

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Mart Resources NAV Waterfall


Operations & Infrastructure To date 2014 has been better operationally for Mart than 2013, with production losses being lower to date than previously experienced with no shut-in’s either for maintenance or disruption link activities.

Mart Resources Average Monthly Production (April 2012 – May 2014)*

Source: Mart Resources, *Calendar days

Production achieved a record of 16,567bpd in February 2014, excluding 4 days downtime arising from pipeline losses which took 32,272bbls (or 1,152bpd).

0.00

0.50

1.00

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2.50

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14,000

bpd

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Mart Resources - % Losses from Umusadege Field

Source: Mart Resources

Mart’s solution to the operational problems associated with the Agip pipeline is through the construction of the new 51km Umugini spur pipeline from Umusadege field to the Shell-operated Trans Forcados Pipeline (TFP) which was recently completed in October 2014 The current Agip export pipeline has a limited capacity ceiling of 13,500bpd, The Umugini pipeline will have a 45,000 b/d with 75% of this capacity being allocated to Umusadege (33,750bpd). A secondary benefit would be access to an export pipeline with a better track record of regularity and lower production losses than the current Agip pipeline. Production losses on the TFP are said to be around 8% to 10%.

Mart Resources Pipeline Infrastructure

Source: Mart Resources

Delays to the Umugini pipeline have inevitably lead to higher costs, with the original 2014 budget of US$8.7m with US$9.2m being spent in .H1 2014 from a projected budget (net) of US$11m for FY 2014. Mart funds a 15% share of the project.

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2011 2012 2013 Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14

Documents

Nigeria Oil Gas Sector Report