Canadian Overseas Petroleum

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1 Canadian Overseas Petroleum Liberia looking for Liza s conjugate Company update Oil & gas Canadian Overseas Petroleum s (COPL) Mesurado-1 prospect in Liberia is set to be drilled in late 2016 or early 2017 by operator ExxonMobil, targeting multiple Santonian deepwater channel sands. Interest in block LB-13 has increased in recent months following ExxonMobil s discovery of the prolific Liza oil field in the conjugate basin in Guyana. Mesurado-1 has been de-risked through the use of modern seismic techniques as well as the discovery of oil in offset wells. Mesurado-1 s pre-drill gross P50 unrisked resource is estimated at c 400mmbbl, hence success could prove to be game changing for COPL. COPL remains funded through US$120m of gross exploration costs by partner and operator ExxonMobil. 2 August 2016 Price C$0.08 Market cap C$48m US$0.77/C$ Current net cash post Q2 raise 6.5 Shares in issue 606m Free float 99% Code XOP/COPL Primary exchange TSX-V Year end Revenue EBITDA PBT* Net cash Capex 12/ (7.7) (6.6) 4.7 (0.5) 12/ (6.5) (7.8) 2.0 (0.2) 12/16e 0.0 (4.2) (4.2) 4.4 (0.1) 12/17e 0.0 (4.4) (4.4) Note: *PBT and EPS are normalised, excluding amortisation of acquired intangibles, exceptional items and share-based payments. Secondary exchange Share price performance LSE Looking for Liza s conjugate twin sister After recent appraisal, ExxonMobil believes that the Liza oil discovery offshore Guyana could hold up to 1.4bnboe, making it one of the largest oil discoveries since the start of the decade. ExxonMobil is to looking to replicate this success by targeting a possible Liza Atlantic conjugate, Mesurado-1 offshore Liberia. Mesurado-1 is de-risked by the discovery of oil at the Montserrado-1 offset well on an adjacent licence (LB-15) as well as advanced seismic techniques (extended elastic impedance and full waveform inversion). Path to monetisation key in success case COPL is funded through the upcoming Liberia exploration programme operated by ExxonMobil up to a maximum gross carry of US$120m. We expect this to include drilling of the Mesurado-1 prospect, which we estimate at a P50 prospective resource of c 400mmbbl and geological chance of success (GCoS) of 30% (commercial chance of success 19.5%). Under Liberian PSC terms, we estimate a development could generate a 37% gross post exploration and appraisal IRR, and be underpinned by an NPV10 break-even oil price of c US$35/bbl. Monetisation in the success case will be key in determining the value of a discovery net to COPL. We provide a valuation based on COPL farming-down (farminee requiring a 20% IRR) as well as a high case valuation based on asset sale at NPV10 possible in the event of a major/noc seeking strategic basin entry. Valuation: Attractive risk/reward We see few small-cap E&Ps that offer a funded exploration programme targeting over 400mmbbl of prospective resource over the next 12 months. We value COPL on the basis of a post-discovery farm-down, driving a C$0.15/share RENAV, and also provide a potential strategic asset valuation of C$0.22/share. % 1m 3m 12m Abs Rel (local) week high/low C$0.10 C$0.03 Business description Canadian Overseas Petroleum (COPL) is an Africafocused E&P with exploration assets in Liberia and plans to expand into Nigeria through its ShoreCan JV. COPL is carried through a US$120m gross exploration programme in Liberia by ExxonMobil. Next events Liberia exploration Analysts Q416/Q117 Sanjeev Bahl +44 (0) Ian McLelland +44 (0) Elaine Reynolds +44 (0) oilandgas@edisongroup.com Edison profile page Canadian Overseas Petroleum is a research client of Edison Investment Research Limited

2 Liberia looking for Liza s conjugate Modern reconstructions of West Gondwana combining plate tectonics and geophysical data have provided for accurate correlations between the Amazonian and West African cratons. A number of operators have focused their exploration efforts on targeting cross Atlantic analogues in order to extend West African exploration across to South America (eg Tullow s knowledge of the Tano Basin in Ghana contributed to exploration success in French Guiana). Operator ExxonMobil and COPL are looking to follow recent exploration success in Guyana in similar aged stratigraphy offshore Liberia. ExxonMobil s Liza-2 exploration/appraisal well, deep-water Guyana, confirmed an 800-1,400mmboe discovery and has added weight to the upcoming LB-13 exploration programme. Conjugate Atlantic margins The opening of the southern Atlantic Ocean in the Early Cretaceous separated South America from Africa, fully separating by the Early Albian age with the West African Transform Margin, from Ghana to Liberia, the last region to fully separate. In the late Cretaceous, source rocks were formed by Cenomanian to Turonian organic-rich marine shales with multiple turbidite sandstone reservoirs overlying potential source rock intervals. The Liberian basin is known to be structurally complex, however between major fracture zones the upper Cretaceous was less affected by major faulting, allowing for the deposition of thick deepwater shales and turbidite sands. The combination of mature hydrocarbon source and multiple sandstone intervals provides for a prospective basin. Exploration of the late Cretaceous has led to several discoveries along the West African Transform Margin including those made offshore Ghana, Sierra Leone and Liberia. On the conjugate margin, several discoveries have been made in French Guiana, Suriname and Guyana. Exhibit 1: Transform tectonics along the South-Central Atlantic Source: COPL The fall in oil price over the last 18 months has led to a significant reduction in global deepwater exploration activity. A stand-out is ExxonMobil s Liza discovery in the Guyana-Suriname Basin, which the operator has estimated to hold 800-1,400mmboe. The Liza-1 well drilled in May 2015 encountered 90m of high-quality oil-bearing sand at 5,433m TVDSS and was followed by the Liza-2 discovery in June Liza-2 confirmed the presence of high-quality oil from the same reservoirs as Liza-1, encountering 58m of oil bearing sand in Upper Cretaceous formations. COPL believes that Liza is an analogue to the Mesurado-1 prospect in Liberia, a Santonian to Turonian channel/fan complex. The operator of Liza, ExxonMobil, has provided little detail on the discovery, other than Canadian Overseas Petroleum 2 August

3 stating that sands were oil bearing in the Upper Cretaceous. If it is found that Mesurado-1 has a similar AVO response and stratigraphy to Liza, it may be significantly de-risked pre-drill. Exhibit 2: Liza a game-changing discovery in deep-water Guyana Source: Spectrum The Mesurado-1 prospect Partners ExxonMobil (83%) and COPL (17%) are planning to drill the Mesurado-1 prospect offshore Liberia in late 2016 or early In addition to recent success across the Atlantic, Mesurado-1 is partly de-risked by offset wells on block LB-12 (Carmine-Deep and Goshtern-1) and block LB-15 oil discovery (Montserrado-1). The closest offset well, Montserrado-1, drilled to 5,400m in the late Cretaceous, has helped prove a light oil source. The well encountered good-quality, water-bearing sands at the primary objective and 8m of hydrocarbon pay (light oil) at a deeper secondary objective. COPL believes the trap was breached by an erosive channel at the primary objective, and does not see a similar erosive channel at Mesurado-1. In addition, slumping features give confidence that a seal is present. In addition to Monsterrado-1, the Narina-1 discovery in January 2012 made by African Petroleum in LB-9 encountered a total of 31m of light oil pay in Cretaceous age sand reservoirs. ExxonMobil and COPL have de-risked Mesurado-1 through the interpretation of modern 3D seismic in combination with log data from Montserrado-1. We describe two inversion techniques used by the partnership for lithology and fluid prediction below: 1. Extended elastic impedance: a sophisticated manipulation that extends beyond the typical incident angle range for seismic data and allows better distinction between a seismic anomaly caused by lithology and one caused by fluid content. For Mesurado-1, work carried out by COPL and partners demonstrates that the LB-13 block holds a number of channel features and fans, which tie with EEI anomalies associated with lithology and fluid content. 2. Full waveform inversion: ExxonMobil is a proponent of full waveform inversion (FWI), a technique that has been used to highlight sands potentially filled with oil in Exhibit 3. FWI is a method that optimises a subsurface model by minimising the difference between field data and Canadian Overseas Petroleum 2 August

4 simulated data, resulting in a highly resolved image of the subsurface, as shown in the exhibit below. Exhibit 3: Mesurado-1 full waveform inversion and well location Source: COPL Our interpretation of pre-drill risks is outlined in Exhibit 4. We believe that the Mesurado-1 prospect has been significantly de-risked through the use of modern seismic techniques, analysis of West African and Amazonian analogues as well as offset well logs such that it is no longer high risk. DeGolyer & MacNaughton (D&M) quote a GCoS of c 23%, however there is reason to believe that this is conservative based on more recent interpretation and Guyana exploration success. In our valuation we use a GCoS of 30% (commercial CoS of 19.5%) applied to a pre-drill volume of 400mmbbl gross. Gross prospective recoverable resources on LB-13 estimated by D&M range from P90 1.8bnbbl to P10 4.2bnbbl (P50: 2.6bnbbl). Exhibit 4: Mesurado-1 geological risks Source Migration Trap Seal Reservoir Montserrado-1 drilled to 5,400m made a late Cretaceous oil discovery. Source rocks Cenomanian to Turonian organic rich-shales. Reservoir directly above source. EEI anomalies associated with oil fluid contact. Stratigraphic trap (turbidite channel) with up-dip pinch-out. No major faults. Slump features seen at stratigraphic pinch-out on many channels and fans. Some similarities to slump related seals seen in Angola. Up-dip pinchout confirmed by AVO response. Shales above and below. Santonian-aged reservoir sand targets in levee-controlled turbidite channel complexes. Lateral accretion packages (LAPs) visible on seismic. Quartz-rich turbidite sands. Pre-drill expectations are of porosity 20-30% and permeability of 100mD to over 1,300mD. Mesurado-1 deepwater channel complex COPL believes that the Mesurado-1 prospect has geological similarities to Tullow s Enyenra discovery offshore Ghana and ExxonMobil s multi-billion barrel Dalia oil field in Angola. The bulk of Mesurado-1 prospective volume is expected to be within deepwater sinuous channels including localised thick sand packages known as lateral accretion packages (LAPs). LAPs are formed during lateral and down-dip migration of a channel where sand is deposited on the inner side of a bend (erosion occurring on the outside of the bend). These localised sand packages can be large in size and can make up a significant component of overall reservoir in prospective channel systems. These sand packages can be identified on high-resolution seismic and stacked sands targeted for Canadian Overseas Petroleum 2 August

5 exploration. The channel system being targeted at Mesurado-1 can be seen in the top maps in Exhibits 3 and 5. Exhibit 5: LB-13 multiple fans vertically stacked Source: COPL ExxonMobil cost carry COPL is carried for 17% of all costs until ExxonMobil spends US$120m gross on drilling. At current day rates, this should fund COPL through at least two exploration wells. There are a number of suitable drillships hot-stacked in West Africa (eg Seadrill West Capella and Deepsea Metro I), which should enable the deep-water well to be drilled at a fraction of 2014 costs; current spread rates should drive a dry hole cost of c US$50m to US$70m, enabling COPL to be carried through a multiple-well exploration programme. We await further details on a rig contract and Mesurado-1 spud date. Canadian Overseas Petroleum 2 August

6 Valuation and funding COPL s LB-13 production sharing contract (PSC) is a public document, available through the Alberta Securities Commission. The terms of the LB-13 PSC are used to drive our LB-13 asset valuation. Key terms include a water depth based royalty, 70% oil cost recovery, sliding scale production based profit share (60% to 40%), corporation tax (currently 30%) and also state back-in rights. Based on our valuation of a c 400mmbbl gross oil development, using unit costs comparable to West Africa analogues such as Tullow s Jubilee, we believe economics are attractive, based on Edison s base case long-term oil price of US$70/bbl. Gross value per barrel recovered under the contract is estimated at just over US$5/bbl. Exhibit 6: Liberia development key assumptions Opex (US$/bbl) 13.3 Capex (US$/bbl) 14.5 Prospect size (mmbbl) 409 Completed well cost 44 Gross project IRR 37% First oil 2020 Plateau production rate (mb/d) 110,040 Gross value per bbl (US$/bbl) 5.2, LB-13 PSC Our well count and production assumptions are outlined in Exhibit 7, with first oil modelled for 2020 and peak production at c 110mb/d. Our analysis suggests a post exploration and appraisal gross project IRR of 37% at US$70/bbl long-term or an NPV10 break-even oil price of US$35/bbl assuming unchanged costs. In a success case, we see a project that is likely to justify development given its relatively low break-even oil price and the potential to extend the production plateau as the play is fully explored. Exhibit 7: Liberia assumed production profile and well count Production (bopd) 120, ,000 80,000 60,000 40,000 20, Number of wells Wells (RHS) Production (bopd) In the current market, we see limited availability of reserve based lending (RBL) ahead of first oil and expect the most logical monetisation routes to be asset sale or farm-down. If ExxonMobil is able to open up the Santonian oil play in Liberia, we believe that COPL will have an extremely attractive acreage position with material further prospective upside as well as a best-in-class development partner in the form of operator ExxonMobil. We remain conservative in our pre-drill risked valuation, assuming COPL farms down its equity interest for a full development carry. A farminee would need to carry COPL for up to US$300m of costs ahead of first oil under this scenario (see Exhibit 8). Canadian Overseas Petroleum 2 August

7 Exhibit 8: Capex carry provided by farminee (full cost carry to first oil) versus COPL s retained working interest Capex carry provided by farminee % 2.0% 4.0% 6.0% 8.0% 10.0% 12.0% 14.0% 16.0% Working interest retained by COPL Our analysis suggests that a farminee would be required to acquire c 9.5% of COPL s 17% interest (prior to state back-in) in order to provide a full cost carry as well as generate a 20% IRR. Farminee IRR increases towards our gross project IRR of 37% in the case of acquisition (at zero cost/carry). Exhibit 9: Farminee IRR increases with acquired WI Farminee IRR % 35% 30% 25% 20% 15% 10% 5% 0% -5% 0.0% 2.0% 4.0% 6.0% 8.0% 10.0% 12.0% 14.0% 16.0% Farminee acquired WI % (provides full cost carry) Full cost carry COPL s LB-13 risked value remains geared to the oil price (Exhibit 10) and we estimate an NPV12.5 break-even at just below US$40/bbl and NPV10 break-even at c US$35/bbl, making a success case 400mmbbl development project attractive even in the current oil price and cost environment. At a corporate level, our RENAV sensitivity to the oil price is shown below. Exhibit 10: COPL RENAV sensitivity to oil price (no farm down) C$ US$/bbl long-term Cash / net debt minus G&A Exploration assets Current share price Canadian Overseas Petroleum 2 August

8 ShoreCan: Building a sub-saharan portfolio COPL s 50/50 JV with Shoreline Energy International Limited, or ShoreCan, continues to pursue upstream and gas-to-power asset acquisitions across sub-saharan Africa. Its recent focus has been on securing ministerial approval for the acquisition of OPL 226 in Nigeria. Nigeria ShoreCan is currently awaiting ministerial approval of the purchase of a 100% interest in OPL 226 in Nigeria (via 80% of the issued share capital of a 100% foreign owned Nigerian company). Management expects the deal to complete imminently, granting ShoreCan access to a proven basin and licence containing an existing shallow water oil discovery (Noa-1). Five wells have been drilled on OPL 226 by previous operators and include one oil discovery and four gas discoveries. There is thought to be significant follow-up potential to the 2001 Noa-1 oil discovery along the seismically mapped footwall-trap. COPL expects to publish a commissioned Netherland Sewell & Associates (NSAI) contingent and prospective resource report that incorporates the result of a D seismic programme on completion of the OPL 226 deal. We expect to include a more comprehensive analysis of OPL 226 and ShoreCan once the JV has received ministerial approval and published its revised resource report. Equatorial Guinea ShoreCan is in direct negotiations towards the award of a PSC for EG-018. PSC terms are currently under negotiation and final terms as well as government ratification are expected in Q416. Namibia ShoreCan has an 80% interest in three blocks 1708, 1808 and 1709 which have been ratified by the ministry of energy in Namibia. The blocks are located north of the Walvis ridge on the Namibia/Angola border. There are no current exploration plans. Canadian Overseas Petroleum 2 August

9 Valuation and financials We provide two valuation scenarios for COPL, firstly a valuation made on the basis of COPL farming down its LB-13 working interest in exchange for a full cost carry through to first oil. Under this scenario COPL retains a 7.5% working interest after state back-in. Our post-farm-down RENAV stands at C$0.15/share or 8.5p/share, offering substantial upside to the current share price. Exhibit 11: COPL Scenario 1: summary valuation assuming farm-down* and cost-carry Asset Diluted WI Recoverable reserves Net risked Value per share Country (pre back-in) CoS Gross Net NPV/boe value Risked Risked % % mmboe mmboe US$/boe** US$m C$/share p/share Net (debt)/cash post Q216 fund raise SG&A 3 years (11) (0.02) (1.1) Core NAV (5) (0.01) (0.5) Exploration (2016) Block LB-13 Liberia 7.5% 19.5% Block LB-13 Liberia 7.5% 19.5% RENAV Note: *Farminee 20% IRR. **Includes impact of cost-carry. We also provide an undiluted valuation, which reflects the full NPV10 risked value of COPL s 17% share of LB-13. This gives a company RENAV of C$0.22/share. Asset valuations close to or above NPV10 have been achieved by E&Ps in the past, often when the asset is sold to an oil major or NOC seeking strategic basin entry. An example of a strategic basin entry by an NOC would be PTTEP s acquisition of Cove Energy s East African asset base in PTTEP paid a significant premium to consensus NPV10 at the time of the transaction, potentially for exposure to follow-on exploration potential and to meet state-led goals of resource access. The valuation provided in the table below is more indicative of a high case, at a 39% premium to our farm-out RENAV. Under both scenarios, we see significant upside from the current share price, however we caveat that based on COPL s current asset base (excluding to be acquired ShoreCan assets), success or failure of the company is driven by a single exploration programme on the LB- 13 licence. We await further details on the ShoreCan asset base before including it in our RENAV. Exhibit 12: COPL Scenario 2: summary valuation Asset Diluted WI Recoverable reserves Net risked Value per share Country (pre back-in) CoS Gross Net NPV/boe value Risked Risked % % mmboe mmboe US$/boe US$m C$/share p/share Net (debt)/cash post Q216 fund raise SG&A 3 years (11) (0.02) (1.1) Core NAV (5) (0.01) (0.5) Exploration (2016) Block LB-13 Liberia 17% 19.5% Block LB-13 Liberia 17% 19.5% RENAV After an equity injection of just over C$8m in Q216, COPL is funded for the remainder of 2016 and 2017 based on our SG&A forecasts. Further capital will be required for full appraisal of a discovery in Liberia and for ShoreCan s Nigerian capital commitments, which remain contingent on deal completion. Canadian Overseas Petroleum 2 August

10 Exhibit 13: Financial summary US$000s e 2017e Year end 31 December IFRS IFRS IFRS IFRS IFRS PROFIT & LOSS Revenue Cost of Sales Gross Profit EBITDA (9,166) (7,685) (6,505) (4,152) (4,360) Operating Profit (before amort. and except.) (9,225) (7,747) (6,564) (4,184) (4,379) Intangible Amortisation Exceptionals Other Operating Profit (9,225) (7,747) (6,564) (4,184) (4,379) Net Interest Forex gains/(losses) 729 1,138 (530) (46) 0 Derivative gain/(losses) ,097 (654) 0 Share in JVs/associates 0 0 (729) (2) 0 Profit Before Tax (norm) (8,473) (6,581) (7,782) (4,209) (4,363) Profit Before Tax (FRS 3) (8,473) (6,554) (6,685) (4,863) (4,363) Tax Profit After Tax (norm) (8,473) (6,581) (7,782) (4,209) (4,363) Profit After Tax (FRS 3) (8,473) (6,554) (6,685) (4,863) (4,363) Average Number of Shares Outstanding (m) EPS - normalised (c) (2.8) (2.2) (1.7) (0.7) (0.7) EPS - normalised fully diluted (c) (2.8) (2.2) (1.7) (0.7) (0.7) EPS - (IFRS) (c) (2.8) (1.8) (1.5) (0.8) (0.7) Dividend per share (c) Gross Margin (%) N/A N/A N/A N/A N/A EBITDA Margin (%) N/A N/A N/A N/A N/A Operating Margin (before GW and except.) (%) N/A N/A N/A N/A N/A BALANCE SHEET Fixed Assets 16,581 16,502 16,615 16,665 16,646 Intangible Assets 16,347 16,305 16,455 16,537 16,537 Tangible Assets Investments Current Assets 2,580 5,203 2,383 4, Stocks Debtors Cash 2,227 4,705 2,015 4, Other Current Liabilities (1,736) (1,437) (1,791) (2,741) (2,741) Creditors (1,736) (1,437) (1,791) (2,741) (2,741) Short term borrowings Long Term Liabilities Long term borrowings Other long term liabilities Net Assets 17,425 20,268 17,207 18,635 14,273 CASH FLOW Operating Cash Flow (7,483) (7,515) (6,255) (3,850) (4,360) Net Interest Tax Capex (1,434) (507) (190) (82) 0 Acquisitions/disposals Equity financing and convertible debt 6,952 10,842 4,951 6,229 0 Dividends Other 83 (384) (1,237) 77 0 Net Cash Flow (1,859) 2,464 (2,690) 2,397 (4,343) Opening net debt/(cash) (4,405) (2,241) (4,705) (2,015) (4,412) HP finance leases initiated Other (305) 0 (0) 0 Closing net debt/(cash) (2,241) (4,705) (2,015) (4,412) (69), Canadian Overseas Petroleum accounts. Note: 2013 audited IFRS financials have been converted from reported currency of C$ to US$ at an average annual FX rate of US$0.934/C$ financials are for comparative purposes only and are as provided by the company in the 2015 financial report, which reflects the change in accounting policy resulting from a change in currency presentation to US$ financials are IFRS audited US$ accounts. Effective 1 January 2015 the functional currency was changed from Canadian dollar to US dollar. Canadian Overseas Petroleum 2 August

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Neither FTSE nor its licensors accept any liability for any errors or omissions in the FTSE indices and/or FTSE ratings or underlying data. No further distribution of FTSE Data is permitted without FTSE s express written consent. Frankfurt +49 (0) Canadian Schumannstrasse 34b Overseas Petroleum 280 High Holborn 2 August Park Avenue, 39th Floor Level 25, Aurora Place Level 15, 171 Featherston St Frankfurt Germany London +44 (0) London, WC1V 7EE United Kingdom New York , New York US Sydney +61 (0) Phillip St, Sydney NSW 2000, Australia Wellington +64 (0) Wellington 6011 New Zealand