international oil gas report 061608

Published by Raymond James Ltd., a Canadian investment dealer. Please see end of INsight for important disclosures. www.raymondjames.ca

JUNE 16, 2008

INTERNATIONAL OIL & GAS PRODUCERS

Rafi Khouri, B.Sc., [email protected]

Braden Purkis (Associate)[email protected]

SECTOR SUMMARYCOMPANY RATING

TICKER CUR PRICE RETURN TARGETAddax Petroleum OUTPERFORM 2

AXC-TSX C $52.45 32% $69.00Bankers Petroleum STRONG BUY 1

BNK-TSX C $2.12 65% $3.50Gran Tierra Energy MARKET PERFORM 3

GTE-T/GTE-A C $6.62 6% $7.00Pacific Rubiales Energy STRONG BUY 1

PEG-TSX C $10.71 59% $17.00Solana Resources OUTPERFORM 2

SOR-TSX C $4.42 24% $5.50WesternZagros Resources OUTPERFORM 2

WZR-TSX C $3.05 48% $4.50

Closing prices as of June 9, 2008All figures in C$, unless otherwise noted.Sources: Raymond James Ltd.,ThomsonOne, CapIQ

International Oil & Gas Initiating Coverage: A World of Opportunity

Investment Road Map

Our international oil & gas investment guide focuses on identifying companies offering a well thought investment risk‐reward proposition. It is our view that this is normally found through companies built around current or near term production assets, a technically sound management team that understands regional geopolitics, and solid long term reserves and production growth potential.

Assets Define the Underlying Value

We believe the core value of international petroleum companies is defined by their assets. Determining the intrinsic value is more challenging.

Geopolitics and Geology can Modify Asset Based Valuations

International investments carry higher geopolitical risk than Canadian and US petroleum assets. The key lies in understanding and managing the risks. Calculating exploration value is also critical in defining risk/reward. Geological risking can be more of an art than science.

Near Term Frothiness

We are very bullish, in the longer term, on oil as a commodity, and oil & gas companies as an equity investment. We do, however, believe that fundamental supply and demand equations only partially account for the recent highs and volatility in commodity pricing.

Long Term Value will be Recognized

Majors, and even nations, increasingly struggling to replenish reserves through the drill bit, are increasingly doing so via acquisition. We expect, for the rest of this decade, that any potential capital markets valuation gaps on oil & gas equity will be seized upon by majors, as well as economically growing countries looking to replace production and reserves. With this view, we are initiating on the following international oil & gas companies: Addax Petroleum (AXC‐TSX, OUTPERFORM), Bankers Petroleum (BNK‐TSX, STRONG BUY), Gran Tierra Energy (GTE‐TSX/GTE‐AMEX, MARKET PERFORM), Pacific Rubiales Energy (PEG‐TSX, STRONG BUY), Solana Resources (SOR‐TSXV, OUTPERFORM), WesternZagros (WZR‐TSXV, OUTPERFORM).

RJ Equity Research │ of 23

Table of Contents

International Oil & Gas

Why Invest in International Oil & Gas? ......................................................................... 8 The Canadian Advantage ..........................................................................................10 Mature Basin Experience...........................................................................................10 Valuing the Assets .....................................................................................................12 Net Asset Valuations .................................................................................................15 Geopolitical Risks ......................................................................................................16 Bullish Long Term Oil View Further Supports Sector Activity ......................................19 Initiating Research Coverage .....................................................................................22 Risks .........................................................................................................................23

Addax Petroleum Corp. (AXC-TSX; OUTPERFORM)

Investment Highlights ......................................................................................... AXC-4 Stock Valuation and Recommendation ............................................................... AXC-5 Reserves Growth................................................................................................ AXC-8 Production Growth ........................................................................................... AXC-10 Company Profile............................................................................................... AXC-11 Operations ....................................................................................................... AXC-14 Cameroon ........................................................................................................ AXC-26 Kurdistan Region of Iraq ................................................................................... AXC-27 Appendix.......................................................................................................... AXC-32 Risks ................................................................................................................ AXC-38

Bankers Petroleum Ltd. (BNK-TSX; STRONG BUY)

Investment Highlights .........................................................................................BNK-4 Stock Valuation and Recommendation ...............................................................BNK-6 Reserves Growth................................................................................................BNK-8 Production Growth ........................................................................................... BNK-10 Company Profile...............................................................................................BNK-11 Operations .......................................................................................................BNK-13 Risks ................................................................................................................BNK-19

Gran Tierra Energy Inc. (GTE-TSX | GTE-AMEX; MARKET PERFORM)

Investment Highlights ......................................................................................... GTE-4 Stock Valuation and Recommendation ............................................................... GTE-5 Reserves Growth................................................................................................ GTE-7 Production Growth ............................................................................................. GTE-8 Company Profile................................................................................................. GTE-9 Operations ....................................................................................................... GTE-12 Colombia.......................................................................................................... GTE-13 Argentina.......................................................................................................... GTE-22 Peru ................................................................................................................. GTE-24 Appendix.......................................................................................................... GTE-29 Fiscal Regimes ................................................................................................. GTE-31 Risks ................................................................................................................ GTE-32


Pacific Rubiales Energy Corp. (PEG-TSX; STRONG BUY)

Investment Highlights ......................................................................................... PEG-4 Stock Valuation and Recommendation ............................................................... PEG-5 Reserves Growth................................................................................................ PEG-8 Production Growth ............................................................................................. PEG-9 Company Profile............................................................................................... PEG-10 Operations ....................................................................................................... PEG-13 Colombia.......................................................................................................... PEG-13 Peru ................................................................................................................. PEG-30 Appendix.......................................................................................................... PEG-33 Fiscal Regimes ................................................................................................. PEG-35 Risks ................................................................................................................ PEG-36

Solana Resources Ltd. SOR-TSXV; OUTPERFORM)

Investment Highlights .........................................................................................SOR-4 Stock Valuation and Recommendation ...............................................................SOR-5 Reserves Growth................................................................................................SOR-7 Production Growth .............................................................................................SOR-8 Company Profile.................................................................................................SOR-9 Operations .......................................................................................................SOR-11 Colombia..........................................................................................................SOR-11 Appendix..........................................................................................................SOR-21 Fiscal Regimes .................................................................................................SOR-23 Risks ................................................................................................................SOR-24

WesternZagros Resources Ltd. (WZR-TSXV; OUTPERFORM)

Investment Highlights .........................................................................................WZR-4 Stock Valuation and Recommendation ...............................................................WZR-5 Company Profile.................................................................................................WZR-8 Operations .......................................................................................................WZR-10 Kurdistan Region of Iraq ...................................................................................WZR-11 Appendix..........................................................................................................WZR-18 Fiscal Regimes .................................................................................................WZR-20 Risks ................................................................................................................WZR-22

Note: Cover photos courtesy of Addax Petroleum


Rafi Khouri, B.Sc., MBA (403)‐509‐0560Braden Purkis (403)‐509‐0534 (Associate)

2PPrice (C$) 52 wk 52 wk AT Netback ($/boe) Net Asset Value Production (boe/d) Reserves RJ 1‐Yr Total

Company Ticker 9 Jun 08 High Low 2008E 2009E RJ NAV P/NAV 2008E 2009E (MM BOE) Rating Target ReturnAddax AXC.T $52.45 $55.21 $29.22 35.88 27.95 $68.55 77% 144,500 164,890 447 OP‐2 $69.00 32%Bankers BNK.T $2.12 $2.24 $0.35 35.74 48.79 $3.57 59% 6,850 12,670 156 SB‐1 $3.50 65%Gran Tierra GTE.T $6.62 $6.85 $3.15 69.02 92.31 $6.96 95% 4,015 6,234 15 MP‐3 $7.00 6%Pacific Rubiales PEG.T $10.71 $12.51 $5.40 54.32 74.25 $17.00 63% 28,567 38,181 208 SB‐1 $17.00 59%Solana SOR.V $4.42 $4.60 $1.07 70.90 71.29 $5.48 81% 3,182 5,773 14 OP‐2 $5.50 24%WesternZagros* WZR.V $3.05 $4.25 $1.90 nm nm $4.56 67% nm nm nm OP‐2 $4.50 48%Average 53.17 62.92 74% 39%

O/S Mkt Ent.Shares Cap Value CFPS (basic) EPS (basic) EV / Prod* Reserves P/CF 08 Net Debt/(Cash)

Company Ticker ($Mln) ($Mln) ($Mln) 2008E 2009E 2008E 2009E ($/boe/d) ($/boe) 2008E 2009E Debt $MM D/CFAddax AXC.T 155.6 8,163.4 9,282 $13.97 $16.46 $7.99 $9.04 $64,238 $20.78 3.8x 3.2x $734.0 0.3xBankers BNK.T 519.3 1,100.9 1,072 $0.18 $0.45 $0.11 $0.36 $156,542 $6.87 12.0x 4.7x ($49.9) (0.5x)Gran Tierra GTE.T 100.0 661.9 637 $0.80 $1.76 $0.50 $1.35 $158,623 $42.58 8.3x 3.8x ($54.3) (0.7x)Pacific Rubiales PEG.T 201.3 2,156.4 2,034 $1.73 $3.53 $0.22 $1.83 $71,214 $9.77 6.2x 3.0x ($154.2) (0.4x)Solana SOR.V 123.2 544.4 472 $0.72 $1.52 $0.39 $0.89 $148,376 $33.16 6.2x 2.9x ($84.6) (1.0x)WesternZagros WZR.V 207.5 632.8 494 nm nm nm nm nm nm nm nm ($63.1) nmAverage $119,799 $22.63 7.3x 3.5x

Commodity Price Assumptions 2007A 2008E 2009E Long‐TermWTI Crude Oil (US$/bbl) $72 $113 $130 $130Dated Brent Differential (US$/bbl) ‐$0.29 $0.00 $0.00 $0.00Dated Brent (US$/bbl) $72.66 $112.84 $130.00 $130.00Foreign Exchange Rate (US$/C$) $0.94 $1.00 $1.00 $1.00

*EMV is used in lieu of NAV

EV

Notes: Ratings:SB-1: Strong BuyOP-2: OutperformMP-3: Market PerformUP-4: Underperform.

Exhibit 1: Comparative Table Source: Raymond James Ltd., Capital IQ, Company reports With continued strong hydrocarbon pricing driving interest in oil & gas assets both in and outside of North America, we believe the coming years will provide investors with a growing number of opportunities in the international oil & gas arena. With this report, we aim to provide investors with our thoughts and analysis on the sector, while also offering a road map aimed at identifying value creating opportunities. It is our view that a good international oil & gas investment is mainly offered by companies built around current or near term producing assets, a technically sound management team that understands regional geopolitics, and solid long term reserves and production growth potential. We also believe that certain well managed, engineered and executed exploration stories should be included as part of an international oil & gas portfolio.


Our view, however, is a fundamental valuation driven, long term focus one. For the shorter term investor, while our targets are all for a 6‐12 month period, we suspect that current oil commodity frothiness could create some near term opportunistic investing windows within our coverage universe. Borrowing from Mr. Andrew Bradford et al (Raymond James Oilfield Services Report dated January 23, 2008), “being fundamentally right is cold comfort when the market is driven to push stocks to either extreme.” Given this schism between longer term fundamentals and short term commodity runs, as well as the rapid recent share price appreciation on all our coverage universe, try as we might, we struggle with using the ʺtop picksʺ phraseology in describing the companies listed below. Having made this point, we highlight the companies below as the “preferred ones”, given our six to twelve month time horizon, in our current coverage universe.

Addax Petroleum Corp. (AXC‐TSX, OUTPERFORM). From a mathematical standpoint, the potential 32% return to our target price clearly places this African and Middle Eastern company in this category. A second, and more subjective reason, is that we view Addax as a cornerstone holding in any international oil & gas portfolio. We remain unaware, after extensive investigation, of any other, similar sized, international oil & gas companies offering investors the same compelling risk/reward strategy. Mainly, a reserve base capable of sustaining production rates of 140,000 to 150,000 barrels of oil per day over the next four to five years; a geopolitically savvy and technically proven management team; exploration exposure to a potential 2,200 million barrels of oil; and over 2.4 trillion cubic feet of contingent gas present on the company’s Nigerian blocks. Given that valuations might pull back on commodity weakening, we believe that “timing the market” on an Addax investment might yield the “lucky” a couple additional percentage return points. Then again, a couple of percentage points, in our view, are paled by the potential return to our target price, as well as the potential fivefold return based on our unrisked NAV of over C$300 per share on the company.

Bankers Petroleum Ltd. (BNK‐TSX, STRONG BUY). Borrowing

phraseology from Mr. Dennis Gartman, we consider the ideal investment as one with valuations growing “from the bottom left to the top right.” Having adhered to this rule since late 2007, we strongly believe Bankers will continue to be such an investment. Bankers is currently focused on monetizing the two billion barrels of Original Oil In Place (OOIP) estimated to be contained in Albania’s Patos Marinza heavy oil field. Operationally Bankers is guiding towards Albanian production of 20,000 bopd by 2010. While at first glance this fourfold


production increase from current levels might be considered aggressive, Mr. Badwi and his team have an established track record of under promising and over delivering. We would not be surprised were the company to exceed this production target by the end of 2010. Furthermore, it is our view that a doubling, or even tripling, of the current 147 million barrels of booked oil reserves in Albania could be achieved over the next 36 months. Having identified several visible, potentially value adding, catalysts over the next six months, we rate Bankers as a STRONG BUY.

Pacific Rubiales Energy Corp. (PEG‐TSX, STRONG BUY). We are

recommending Pacific Rubiales as an investment in an extremely well managed, and connected, growth oriented South American independent E&P Company. On the heels of its recent merger with Pacific Stratus, the company has transformed into Colombia’s largest independent oil & gas company. Going forward, we expect Pacific Rubiales to continue on this growth path, potentially becoming one of South America’s largest independent oil & gas companies. In addition to current market valuations reflecting the C$10.65 per share (fd) in reserve backed NAV, Pacific Rubiales offers investors exposure to over C$107 per share (fd) in potential upside. The reserve base NAV is underpinned by 208 million barrels of oil equivalent (working interest) Colombian reserves, and backed by a ‘proven’ management team, with a depth of regional technical and geopolitical experience. While the bulk of the potential upside is based on the company’s vast exploration potential in Peru, C$7 per share (Rubiales and La Creciente pipelines and extensions) only require management to deliver on project execution, and contract ‘negotiations’. Having identified several visible, potentially value adding, catalysts over the next six months, we rate Pacific Rubiales as a STRONG BUY.

We also like the following names as well, though there are mitigating factors keeping them off our top‐pick list:

Gran Tierra Energy Inc. (GTE‐TSX/GTE‐AMEX, MARKET PERFORM). While current valuations reflect a discount to our calculated risked NAV on Gran Tierra, market is offering close to a 60% premium to the company’s reserve backed core NAV (under our commodity assumptions). Our concern is that markets could adjust to a potential short term commodity pullback by re‐pricing Gran Tierra closer to reserve NAV. We are, however, recommending that longer term investors seeking a growth oriented, well managed, South American focused international oil & gas junior keep Gran Tierra on their radar screens. With an asset base in Colombia, Peru, and


Argentina, a ‘blue chip style’ management team, growing production, and extensive exploration acreage, we believe Gran Tierra offers long term upside associated with investing in international oil & gas, with potentially lower risk than some of its peers. Growing cash flow from Gran Tierra’s production combined with medium to low risk exploration potential offers the platform for building a substantial oil & gas company. Gran Tierra’s high impact exploration lands have the potential to transform the company, with the associated returns for current shareholders.

Solana Resources Inc. (SOR‐TSXV, OUTPERFORM). Having

established an impressive Colombian land position, Solana’s board, in October 2006, engaged a new management team to focus on reserves, and production growth. By focusing on transforming land into reserves, and reserves into production, this team has been able to deliver tangible value add in under 18 months. Specifically, for 2007, year‐over‐year production grew by 40%, while year‐over‐year reserves increased threefold. In the longer term, we believe Solana’s three pronged strategy will yield continued shareholder value growth. While markets are valuing Solana on the basis of its core reserve backed NAV, the company’s non‐operatorship of its core areas prevents us from including it in our preferred list. We are recommending the company to investors who want exposure to the growth oriented Costayaco field in Colombia, without owning the Argentinean and Peruvian assets of the field’s operator, mainly Gran Tierra (GTE‐TSX/GTE‐AMEX, MARKET PERFORM). We also view Solana as a potential M&A candidate in the longer term.

WesternZagros Resources Ltd. (WZR‐TSXV, OUTPERFORM). We are

recommending WesternZagros to investors looking for exposure to a pure play; high‐impact; exploration portfolio in one of the world’s most prolific hydrocarbon basins. It is only the company’s pure exploration stage, and thus higher inherent risk, that prevents us from including it in our top picks. WesternZagros’ is a junior international oil & gas company, currently focused on exploration in the Kurdistan region of Northern Iraq. The company has a 40% interest in a 2,120 km2 production sharing contract (PSC) in the Kalar‐Bawanoor area of Kurdistan. WesternZagros has currently identified eight prospects and leads on the block, as well as three conceptual stratigraphic plays. We believe current market valuations offer investors a very attractive risk/reward proposition. Specifically, markets appear to be valuing WesternZagros on the basis of a 300‐350 million barrels of recoverable oil discovery, less than 3% of the 12 billion barrels of potential OOIP on the block.


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Why Invest in International Oil & Gas?

While, given the advances in Liquefied Natural Gas (LNG) and other similar technologies, gas is moving towards becoming a truly global commodity; it remains priced as a local commodity. Oil on the other hand, is global commodity in every sense of the word. This in turn, in our view, leads most international petroleum companies to focus the bulk of their efforts on oil exploration and production. We have therefore opted to focus our attention, both in our investment guide, as well as our company selections, on oil weighted activities.

Trillion barrels and counting

First, and foremost, oil is mainly found outside of North America. With close to 95% of the 1.2 trillion barrels of global proved oil reserves1, and over 80% of current global2 production, we believe the International Oil & Gas sector will continue to offer investors a very attractive risk/reward proposition well into the next decade. Exhibit 2: Global Oil Reserves Source: BP, Raymond James Ltd. Note that over 70% of the Middle East reserves are currently ‘owned’ by the various states in the region, via their National Oil Companies, and thus not open to investment via publicly traded E&P companies. This still leaves close to 500 billion barrels of international oil reserves open to investment that we have broken down into three play types. 1 BP Statistical Review of World Energy 2007 2 Oil & Gas Journal


Frontier Basins, such as the deep offshore waters of Brazil, Western and Eastern Africa. Mature Basins, such as parts of Colombia, West Africa, and Europe. Under explored/under developed basins, such as the Maranon Basin in Peru, the Kurdistan region of Iraq, and large fields in Iraq/Iran. We view the frontier basin as the playground of the “majors”, or intermediate to large oil companies, as exploration and development activities tend to require extensive technical expertise, and are very capital; human and financial; intense. As an example, a ‘typical’ deep water exploration well could cost in excess of US$100 million. Addax (AXC‐TSX, OUTPERFORM), at over C$9 billion in Enterprise Value, would be one of the smaller players in these basins. Note, however, that small cap public companies have been able to obtain minority interest positions in some very prospective African deep water acreage. While this is one way to invest in this play type, we prefer equity positions in companies with a larger interest, and ideally operatorship, of these blocks. Mature and under explored/under developed basins are, in our view, where the junior to intermediate Canadian international oil & gas companies can generate the best risk/return values. Mature basins are characterized by “smaller” fields, typically ranging from a few million barrels to tens of millions barrels. In addition to exploration value creation, these basins present shareholder return opportunities via production improvements, such as workovers, directional drilling field development, and other enhance oil recovery methods. Under explored/under developed basins are ones we define as having had limited historical activity due to political and/or security issues, or due to their remoteness and limited infrastructure presence.


The Canadian Advantage

We view management as a critical component, if not the most important, in determining the success of an international oil & gas company. In addition to depth in technical expertise and experience, we also look for management teams able to manage geopolitical risks inherent in international operations. Some of the advantages we believe Canadian management teams, or international teams with a Canadian flavour, offer are:

Extensive experience in exploring, developing, and producing oil from mature basins gained by working in Canada’s mature basins.

The ability to tap into a wide pool of technically experienced, outside

the box thinking, oilfield service companies based in Canada. A “spirit of adventure” and acquired tolerance for hardship working

conditions, forged by working in remote North American oil & gas provinces for over 100 years.

The political advantage of flying the Canadian flag.

Mature Basin Experience

“Necessity is the mother of ʺtaking chances” – Mark Twain The majority of North American basins, including the Western Canadian Sedimentary Basin (WCSB), by most metrics, have been mature basins for anywhere from 5 to 15 years. Adapting to this, Canadian oil & gas teams, be it E&P companies or oilfield service providers, have developed new or improved on existing, technologies to maximize production from existing fields, or commercially discover new ones. A typical example of this is the growth of directional drilling in North American basins to improve drainage from ‘smaller’ and ‘harder to produce’ fields.


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Exhibit 3: Directional Drilling

Source: Baker Hughes, Raymond James Ltd. The next logical step was to apply this ‘home grown’ technology in other global mature basins. Bankers Petroleum (BNK‐TSX, STRONG BUY), by working on deploying horizontal, as well as vertical, infill drilling to increase recovery and production from a ‘mature field’ is just one example of many. Pacific Rubiales (PEG‐TSX, STRONG BUY) is another.

The spirit of adventure

“Adventures are to the adventurous” – Benjamin Disraeli A side effect of the maturing of most North American basins, especially in Canada, has been to drive Canadian oil & gas exploration and production further north. Having worked for close to five years in Alberta’s Oil Sands, we are able to convey first hand information on the acquired tolerance, and even ‘love’ for adventurous working conditions. While the extreme cold of Northern Alberta is the antipode of North African heat waves, operational skills and required adaptations for either extreme tend to be similar. Infrastructure, or rather lack of, and associated challenges in Canada’s north are very similar to some of the under explored/under developed basins Canadian international oil companies are successfully tackling. Peru’s remote


Marañon Basin is a typical example of where companies such as Gran Tierra (GTE‐TSX/GTE‐AMEX, MARKET PERFORM) and Pacific Rubiales (PEG‐TSX, STRONG BUY) are faced with the same infrastructure and access constraints as those in Northern Alberta.

The Maple Leaf

“A good head and a good heart are always a formidable combination” – Nelson Mandela

Based on the latest Washington‐based Program for International Policy Attitudes (PIPA), BBC World and Globescan data, Canada, along with Japan, tops the list of countries ‘viewed positively’ by the rest of the world. This, in our view, gives oil & gas companies flying the maple leaf a tangible advantage in operating internationally. While not easily quantifiable in an excel spreadsheet, the ability to fly the maple leaf above an oil & gas lease appears to help operations, and oil, flow better. We draw on personal experience to ‘make our point’: a Canadian passport continues to draw warm welcomes in various global oil & gas airports, ports, and other entry points.

Valuing the Assets

We believe the core value of international petroleum companies is defined by their assets.

A guide to fiscal terms

Royalty/tax regimes are relatively straightforward. A contractually agreed percentage of total production is typically paid to the host government as royalties. In addition, the corporation’s income, normally net of costs, is then taxed at a pre‐set corporation tax rate. Note that royalty/tax regimes can also include a nominal ‘rental’ fee, or block license cost. The balance of the oil ‘belongs’ to the oil company, and can be booked as reserves. In addition to North America, South America and Europe are mainly royalty/tax based jurisdictions. Production sharing contracts (PSC), in addition to the above royalties, taxes, and rent, allocate a portion of production revenues to the host government; adding a layer of complexity in comparing assets, or companies, to each other. The balance of the oil ‘belongs’ to the oil company, and can be booked as reserves. Most of Africa, parts of the Middle East, and parts of the Far East tend to operate in PSC mode. Note that PSC terms can also include post discovery back‐in rights for the host government.


Total Oil Produced

Net Available Oil

Cost Recovery OilOil Company (varying %)

Operating Costs

Exploration Costs

Development Costs

Profit Oilremaining net available oilsharing based on varying

factors

Oil Company Host Government

Royalty OilHost Government

Exhibit 4: PSC Example Source: Raymond James Ltd. Technical services contracts (TSC), as the name implies, tend to be a ‘pay for service’ type agreement, where the oil company is paid a ‘pre‐agreed’ production fee. Under these contracts, all of the oil typically remains the property of the host nation, preventing oil companies from booking any of it as reserves. Parts of the Middle East tend to operate under TSC models. In addition to the above contract, various international jurisdictions have introduced ‘withholding taxes’, aimed at capping the realized price oil & gas companies can sell their production at, further muddying the valuation waters. The net result of all these fiscal terms is that international oil & gas companies ‘collect’, at best, 55% of the total hydrocarbon resource on their blocks.


Exhibit 5: Oil & Gas Company Percentage Take

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*excluding recent withholding taxes Source: BP, Wood Mackenzie, Daniel Johnston, Raymond James Ltd.

If host governments believe they are not getting their fair share of the resource, there is a higher risk of their revising contracts, such as Nigeria’s recent ‘change’ to its older PSCs. Similarly, if oil companies believe they are not achieving ‘fair’ rewards for the undertaken risks, they might opt to invest their capital in other locals. Ecuador and Venezuela come to mind as examples of this. Colombia, on the other hand, has shown that changing fiscal regimes to better contractor terms is a good tool in increasing oil production and reserves. While it is not our place to argue what is a ‘fair share’, there seems to be a mutually acceptable balance around 30% to 40% of the resource allocated to the oil company. We also note that increasing the oil company’s share, such as with Colombia’s introduction of the ANH contracts in 2003, shows direct correlation to production growth. Specifically, Colombia’s production changed from a drastic decline on a yoy pre‐ANH to a plateau, and slight increase post‐ANH.


Net Asset Valuations

We believe that NAV calculations are a more representative valuation metric for international oil & gas companies than cash flow multiples. One reason is that PSC artificially inflate cash flows during the cost recovery years (front end) of a project. In addition, by valuing the actual resource base, NAV calculations allow for an easier comparison of the core values for companies under various fiscal regimes. As Canadian listed public companies are required to book their reserves under NI‐51‐101 criterion; which we consider as one of the more stringent methodologies used globally; we attribute full value for booked reserves (proven and probable) in our NAVs. In certain instances, where we believe that this is justified, we might also allocate partial value to possible reserves. Note that under NI‐51‐101, each reserve P (proven, probable and possible) reflects a statistical chance of recovering, at minimum, a set number of barrels. Calculating exploration value is also critical in defining risk/reward. We also include a geologically risked net present value (NPV) for seismically identified prospective resources to our risked sum‐of‐the‐parts NAVs. While actual geological, or exploration, chance of success (COS) is always prospect and lead dependent, we use Otis and Schneidermann’s work as a rough guide in assigning our COS estimates. Exhibit 6: Geological Risk Classification

75% COS 37.5% COS 18.3% COS 5% COS

Same Play Same Play New Play, New BasinAdjacent Structure Nearby Structure Play with Negative Data

Very Low Risk Low Risk Moderate Risk Very High Risk

9.2% COS

New Play, Same TrendOld Play, New Trend

High Risk Source: Otis and Schneidermann, Raymond James Ltd. COS captures the risk in having, or not, the typical elements required to find hydrocarbons in any sedimentary system. Mainly, the chance of having an oil charge (source and migration path for the oil), the odds of having reservoir rocks present, and the probability that oil was actually trapped in these rocks. As each of these factors is independent of the others, total COS is the product of each individual one. COS = Chance of charge x chance of trap x chance of reservoir


As an added layer of conservatism, we tend to move one COS down (to right of scale) in our evaluations. Given the very subjective nature of chances of success (COS) estimates for a same play, we believe this extra step is justified in our valuations. For pure exploration stage companies, such as WesternZagros (WZR‐TSXV, OUTPERFORM) we believe Expected Monetary Valuations (EMV) to be a better value gauge than NAV calculations. An EMV reflects the exploration geological risk (chance of success (COS)), the value of exploration success (NPV), as well as the cost of failure (COF). Specifically, we calculate our EMV as follows: EMV = (NPV x COS) – (COF x {1‐COS})

Geopolitical Risks

While calculating asset values is a fairly straightforward exercise, determining the intrinsic value of the oil & gas company is more challenging. Specifically, as international investments are perceived as carrying higher geopolitical risks than Canadian and US petroleum assets, the key lies in understanding and managing the risks. The first, and in our view, most critical aspect of risk management is people. We search for management teams that understand regional geopolitics, and who can manage risk rather than merely avoid it. In addition, specific regions within a given country can carry higher, or lower, risks than the national average. We point to Addax (AXC‐TSX, OUTPERFORM) as an example in point. While Nigeria is regularly making headlines due to militant activities in the Niger Delta, none of the company’s assets have had any material militant related production disruption since the company entered the country. Similarly for Colombia, while parts of the country, such as the borders with Ecuador and Venezuela, witness regular guerrilla activities, other areas tend to be much safer. In analyzing our companies’ operations and management teams, we have opted not to ascribe any political risking to our valuations, as we are confident that each one of them is well equipped to manage and mitigate specific risks in its areas of operations. We do, however, address any regional higher risk areas by adjusting our long term production forecast to reflect potential disruptions. We are, in addition, for investors wishing to assign an additional political risk factor to valuations, providing geopolitical risking information for the countries in which our coverage universe companies currently operate.


The RJ oil risking factor is on a scale of 0 to 100%, with 100% being no risk, in our view, to oil & gas operations. For reference, we would list Canada at 90%, as the government has shown, on two recent occasions, that it is willing to change oil & gas fiscal regimes to the detriment of oil companies. Exhibit 7: Global Political Risk

Country S&P Moodyʹs Fitch RJ OilRisking

Albania NR Ba1 NR 85%Argentina B+ B3 B 65%Cameroon B+ NR B 80%Colombia BBB‐ Ba2 BB+ 80%Gabon NR BB‐ BB‐ 80%Kurdistan NR NR NR 75%Nigeria BB‐ NR BB‐ 75%Peru BB+ Ba2 BBB‐ 80%

Source: Bloomberg, Raymond James Ltd. The second aspect to risk management is that rewards have to outclass risks. With the international oil & gas companies in our coverage universe offering blue sky returns ranging from 150% to 500%, we believe that potential rewards do outclass any geopolitical risks.

Value will be recognized

While we accept that capital markets will tend to attribute a higher ‘risk’ premium to the more volatile regions of the world, it is our view that as oil resources continue to get scarce, core values will be recognized; if not by capital markets, then by major oil companies looking to replace reserves and production, or by sovereign nations looking for energy supply security. Specifically, since 2005, corporate oil & gas acquisitions have been done at an average 35% premium to capital market valuations, with some transactions ranging as high as a 67% premium (Tullow Oil’s 2006 acquisition of Hardman Resources). The lowest reported transaction premium was also in 2006, mainly Lundin Petroleum’s acquisition of Valkyries Petroleum at an 8% premium to market.


Exhibit 8: M&A Premium to Market Range

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Source: Capital IQ, Raymond James Ltd., Company reports As an aside, we note that the top four oil & gas majors – ExxonMobil (XOM‐NYSE), BP (BP‐NYSE), Shell (RDSA‐LSE) and Total (TOT‐NYSE) – reported combined cash holdings in excess of US$70 billion at the end of 1Q08, more than enough to acquire, five times over, all the international oil & gas companies in our coverage universe.


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Crude oil remains one of the primary global sources of energy, and we believe will likely remain the primary energy source for years to come. We also, however, believe that fundamental supply and demand equations only partially account for current commodity pricing, and volatility in commodity pricing. While we should pay heed to Mr. Voltaire telling us: “Once the people begin to reason, all is lost”, our analysis indicates that we could expect commodity prices to pull back from recent highs, during or even after summer; before continuing to rise in the longer term. This could partially impact equity pricing in the short term, creating opportunistic investing windows. Exhibit 9: WTI Oil Price Source: Bloomberg, Raymond James Ltd. We currently calculate US$70 per WTI barrel as the cost, after tax, to produce a significant marginal barrel, such as Alberta’s oil sands or West Africa’s deep water oil, with a 15% to 20% IRR. This still leaves, compared to current spot pricing, close to US$70 per WTI barrel in “premiums”, including changes in weather forecasts, issues in the Middle East and Nigeria, political instability in parts of the Former Soviet Union, the use of oil as a financial instrument, and so forth. A 5% daily change in crude oil pricing is almost accepted as the norm in the current environment.


Q1 08A Q2 08E Q3 08E Q4 08E 2008ECurrent Strip $97.86 $117.68 $126.21 $126.45 $117.05RJ Oil $97.86 $117.65 $120.00 $120.00 $113.88

Q1 09E Q2 09E Q3 09E Q4 09E 2009ECurrent Strip $126.81 $126.47 $126.33 $125.60 $126.30RJ Oil $130.00 $130.00 $130.00 $130.00 $130.00

Q1 08A Q2 08E Q3 08E Q4 08E 2008ECurrent Strip $8.64 $10.92 $12.34 $12.70 $11.15RJ Gas $8.64 $10.95 $11.00 $10.00 $10.15

Q1 09E Q2 09E Q3 09E Q4 09E 2009ECurrent Strip $13.08 $10.75 $10.81 $11.22 $11.46RJ Gas $7.50 $7.50 $7.50 $7.50 $7.50

* Current Strip Prices are as of May 16, 2008** Actual Strip is the average of futures prices on the expiration days*** Actual RJ is our estimate of average spot prices

RJ Crude Oil Price Estimates

RJ Natural Gas Price Estimates

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Source: Raymond James Ltd., Herold, Oil & Gas Journal As such, predicting the short term price of crude oil has become more of a guessing game than actual economics, and we do not claim an ability to predict day to day crude oil pricing. We do, however, note that falling OECD oil demand could drive, in our view, a short term pullback in oil prices. Longer term, we still believe that price trends remain driven by the supply and demand equation. Exhibit 11: Commodity Forecasts Source: Raymond James Ltd., Bloomberg


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Please refer to the Raymond James Energy Stat of the Week dated June 2, 2008 for additional details on our current commodity pricing assumptions. Long term demand growth We expect global energy demand to continue to rise over the next decade. We also view oil as being the most polyvalent source of energy available. In its latest ‘World Energy and Economic Outlook’, the U.S. Energy Information Administration (EIA) estimates that global liquid energy consumption is expected to increase to 118 million barrels per day in 2030, with most of the growth coming from the non‐OECD region. Non‐OECD oil consumption, reflected by China and India as proxies, is five to ten times lower, per capita, than OECD countries such as the USA, the UK and Japan. Assuming continued economic development by these nations, it is easy to foresee a situation where the per capita oil demand could double, or even triple from current levels, as was demonstrated by South Korea as it underwent economic growth. Two and a half billion people (India and China alone) doubling their oil annual oil consumption, would, in our view, more than account for a potential reduction by the OECD nations. Exhibit 12: Oil Consumption Per Capita Source: BP, United Nations, Raymond James Ltd.


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In addition to growth in demand, oil, on the supply side, is getting harder to find and harder to produce. From the early 1990s to early 2000, approximately 2,000 to 2,200 active rigs, on an annual basis, were able to grow global reserves by an average 1.2% per year, and production by approximately 2.5% per annum. Since 2003, the average annual global reserve and production growth have dropped to 0.5%, although rig count during that same period has increased by over 50%. Exhibit 13: Reserve Additions Source: Baker Hughes, BP, Raymond James Ltd. So in summary, while we are using significantly more drilling days (a 50% increase in active rig over four years), yoy reserve growth is a third of what it was in 2003, while production increases per rig are also lower.

Initiating Research Coverage

We are initiating on the following international oil & gas companies: Addax Petroleum (AXC‐TSX, OUTPERFORM), Bankers Petroleum (BNK‐TSX, STRONG BUY), Gran Tierra Energy (GTE‐TSX/GTE/AMEX, MARKET PERFORM), Pacific Rubiales Energy (PEG‐TSX, STRONG BUY), Solana Resources (SOR‐TSXV, OUTPERFORM), WesternZagros (WZR‐TSXV, OUTPERFORM).


Risks

International oil & gas companies within our research universe are subject to a range of risks, including, but not limited to: environmental risk, political risk, operational risk, financial risk, hedging risk, commodity price fluctuation risk, and currency risk. Any difference between our oil & gas price forecasts and realized commodity prices will likely have an impact on our earnings and valuation estimates for the international oil & gas companies in our research coverage universe. Oil & Gas operations are inherently complex and exposed to a number of risks, most of which are beyond the company’s control. These include: environmental compliance issues; personal accidents; production problems; availability of labour and equipment, and interruption due to inclement weather conditions, road closures, and/or local protests. Other risks include, but are not limited to: uncertainties surrounding capital and operating costs; aging equipment and facilities which could lead to increased costs; actions taken by host governments; and changes in fiscal regimes.


JUNE 16, 2008 INTERNATIONAL OIL & GAS PRODUCERS



RATING & TARGETRATINGTarget Price (6-12 mths)Closing PriceTotal Return to Target 32%

MARKET DATAMarket Capitalization ($mln) 8163Current Net Debt ($mln) 1119Enterprise Value ($mln) 9282Shares Outstanding (mln, f.d.) 157Avg Daily Dollar Volume (3mo, mln) 0.4352 Week Range $55.21 / $29.22

KEY FINANCIAL METRICSFY-Dec 31 2007A 2008E 2009ECFPS $8.49 $13.97 $16.46P/CFPS 6.2x 3.8x 3.2xCFPS - 1Q $1.70 $3.01 $4.04CFPS - 2Q $1.85 $3.59 $4.12CFPS - 3Q $2.15 $3.54 $4.20CFPS - 4Q $2.72 $3.82 $4.09NAVPS $68.55P/NAV 77%Revenue ($mln) $3,412 $5,941 $7,810Yield (%) 1%

Commodity AssumptionsWTI (US$/bbl) $72 $113 $130HHub (US$/mmbtu) $7.12 $10.00 $7.50Exchng Rate (US$/C$) $0.94 $1.00 $1.00ProductionOil (kbbl/d) 126 145 165Nat. Gas (mmcf/d) 0 0 0Total (boe/d) 126 145 165

EBITDA ($mln) 2,412 4,633 5,708Net Debt/ CF 0.9x 0.3x -0.1x* All Figures in C$

COMPANY DESCRIPTION


52.45

Addax is an international oil & gas company with operations in Africa and the Middle East. The company is currently producing in excess of 140,000 bopd, from 447 million barrels of 2P reserves. Addax operates the majority of its blocks. In addition, the company has exposure to 2.2 billion barrels of prospective oil resources, and 2.4 Tcf of contingent gas

OUTPERFORM 269.00

Addax Petroleum Corp. AXC-TSX

Initiating Coverage: Perfection Achieved: Striving for Excellence

Event

We are initiating research coverage on Addax Petroleum Corp. (Addax) with an OUTPERFORM rating and a C$69.00 per share target price.

Action

We are recommending Addax as a core holding for international oil & gas portfolios.

Analysis

Addax is a very well established international oil & gas company, currently strategically focused on West Africa, as well as the Middle East. We believe an OUTPERFORM rating is warranted on Addax for two compelling reasons. First, from a mathematical standpoint, the potential return to our target price offered by current valuations clearly places the stock in this category. A second, and more subjective reason, is that we view Addax as a cornerstone holding in any international oil & gas portfolio. We remain unaware, after extensive investigation, of any other international oil & gas companies offering investors the same compelling risk/reward strategy. Mainly, a reserve base capable of sustaining production rates of 140,000 to 150,000 barrels of oil per day over the next four to five years; a geopolitically savvy and technically proven management team; exploration exposure to a potential 2,200 million barrels of oil; and over 2.4 trillion cubic feet of contingent gas present on the company’s Nigerian blocks.

Valuation

We currently value Addax on the basis of a risked sum‐of‐the‐parts NAV, which includes an NPV (DCF, 10% after tax) of booked reserves, as well as a geological risk adjusted NPV (DCF, 10% after tax) of the company’s exploration portfolio. We calculate a risked sum‐of‐the‐parts NAV of C$68.55 per share on Addax. On an un‐risked basis, we currently calculate a NAV in excess of C$300 per share. In addition, we point out the proverbial maraschino cherry on the sundae, mainly the 2.4 Tcf of gas on the company’s Nigerian blocks, not captured in any of our above NAV calculations.

RJ Equity Research │ Page 2 of 39

Table of Contents

Investment Highlights......................................................................................4 Stock Valuation and Recommendation ...........................................................5 Reserves Growth ............................................................................................8 Production Growth........................................................................................10 Company Profile ...........................................................................................11 Operations ....................................................................................................14 Cameroon.....................................................................................................26 Kurdistan Region of Iraq................................................................................27 Appendix ......................................................................................................32 Risks.............................................................................................................38


Exhibit 1: Addax Petroleum Corporate Summary

Addax Petroleum Corporation (AXC‐TSX, L)Company Summary Shares & Listing InformationOverview: Shares & capitalization:Company name Addax Petroleum Corporation Shares outstanding ‐ basic (M) 155.6Ticker AXC Shares outstanding ‐ fully diluted (M) 156.5Exchange TSX, LSE Market capitalization (C$M) $8,163.4Rating OUTPERFORM Enterprise value 2007E ($M) $9,282.4Current share price* C$52.45 Key shareholders*:12‐month target price C$69.00 AOG Holdings BV 41%Total projected return (incl. dividends payable) 32% Management & Directors 4.1%

Goodman & Company, Investment Counsel Ltd. 1.1%* as at Jun 09, 2008 Blackrock Group Limited 1.4%

Properties Resources (Dec 31, 2007) (MM Bbl)Area Other/Details Reserves (WI) Proved Probable 2P 3PNigeria Nigeria 154 109 263 349OML 123 ‐‐> Current production Gabon 79 30 109 128OML 126 ‐‐> Current production Kurdistan 0 75 75 103OML 124 ‐‐> Current production Total 233 213 447 580Okwok ‐‐> Development play Risked Potential Resources Low Best HighOML 137 & OPL 291 ‐‐> Exploration/Dev plays Nigeria 155 178 202Gabon Gabon 37 51 68Panthere NZE ‐‐> Current production Cameroon 28 32 37Maghena ‐‐> Current production Deep Water 414 476 541Etame ‐‐> Current production Total 738Remboue ‐‐> Current production F&D costs ($/boe) $11.29 $8.23Awoun ‐‐> Development play Recycle ratio 4.8x 6.6xEpaemeno, Iris & Themis Marin, Ibekelia, Kiarsseny ‐‐> Exploration plays RLI (Yrs) 4.4 4.0 8.5 11.0CameroonNgosso, Iroko ‐‐> Exploration plays Key Operating and Financial DataKurdistan Year end: Dec. 31 2006A 2007A 2008E 2009ETaq Taq ‐‐> Exploration/Dev plays PRODUCTION:Valuation Crude oil (kb/d) 90 126 145 165Year end: Dec. 31 2006A 2007A 2008E 2009E Natural gas (mmcf/d) 0.0 0.0 0.0 0.0P/CF 9.0x 6.2x 3.8x 3.2x Total prod. (kboe/d) 90 126 145 165EV/CF 11.2x 7.0x 4.3x 3.6x % Natural gas 0% 0% 0% 0%P/E 30.8x 16.9x 6.6x 5.8x Y/Y growth per share 4% 39% 15% 14%Target P/CF 11.9x 8.1x 4.9x 4.2xOther Parameters FINANCIAL STATEMENTS:EV/BOED $64,238 Revenues ($mln) $2,029 $3,412 $5,941 $7,810EV/BOE (2P) $20.78 Royalty ($mln) $389 $586 $934 $1,717EV/BOE (Reserves + Resources) $7.04 Operating Expenses ($mln) $204 $314 $323 $340Raymond James NAVPS (C$/Sh) $68.55 Income Tax ($mln) $784 $1,251 $2,799 $3,671Commodity Price Assumptions 2007 2008E 2009E LT Net Income ($mln) $243 $482 $1,243 $1,407Brent oil (US$/b) $72.66 $112.84 $130.00 $130.00 Operating Cash Flow ($mln) $829 $1,319 $2,174 $2,562NYMEX gas (US$/mmbtu) $7.12 $10.00 $7.50 $7.50Operating Net Back estimates CFPS ‐ basic $5.80 $8.49 $13.97 $16.46

2006A 2007A 2008E 2009E CFPS ‐ fd $5.80 $8.46 $13.38 $15.77Sale price $63.40 $72.94 $113.56 $123.12 EPS ‐basic $1.70 $3.10 $7.99 $9.04Royalties $11.84 $12.71 $17.89 $28.53 EPS ‐ fd $1.70 $3.09 $7.65 $8.66Opex $6.20 $6.81 $6.19 $5.64 Capex ($mln) $953 $1,225 $1,615 $1,500Pre Tax Net Back $45.35 $53.42 $89.47 $88.95 Net Debt (surplus) ($mln) $826 $1,224 $734 ($328)

Net debt/cash flow 1.0x 0.9x 0.3x (0.1x)Tax $23.85 $27.14 $53.59 $60.99Post Tax Net Back $21.50 $26.28 $35.88 $27.95Production profile (WI, Reserve Blowdown) Management & Directors

Name PositionExecutive ManagementJean Claude Gandur CEO Ex AOG exec, Philipp, SigmoilJames Pearce COO Ex 30 yrs ChevronMichael Ebsary CFO Ex Total, BMO, ScotiaBoard representatives:Peter Dey Chairman Ex Morgan StanleyJean Claude Gandur CEO Ex. AOG exec, Philipp, SigmoilBrian Anderson Non‐exec Ex Shell, Chairman AndersonJames Davie Non‐exec Ex RBCStephen P de HeinrichNon‐exec AOG Exec, ex Samax, CarpathianGerry Macey Non‐exec Ex EnCana, PanCanadianAfolabi Oladele Non‐exec Ex NNPC

All values are in US$ unless otherwise stated.

Source: Company Reports, Raymond James Ltd., Bloomberg, Capital IQ

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Investment Highlights

“Pleasure in the job puts perfection in the work.” – Aristotle Addax is an established international oil & gas company, currently focused on West Africa and the Middle East. Consistently delivering impressive yoy production, reserves and cash flow growth, we view Addax’s management team as continuing to, very successfully, create value from the company’s assets. A decade of 35% annual growth translated into 140,000 bopd production. Since inception a decade ago, Addax has delivered over 35% in annual production growth, one of the most impressive, in our view, growth stories of the Canadian international oil & gas sector. For 2008, we are expecting the company to produce 145,000 bopd, a 15% increase over last year’s 126,000 bopd. Note that our above estimate does not include potential production from the Taq Taq field in Kurdistan, which could add another 3,000 bopd to our annual average forecast. 447 million barrels of oil reserves. Addax’s reserve growth story reads very similar to its production increases. For 2007, the company reported a 26% yoy organic reserve increase, most of which came via drill bit additions. While we currently model annual production increases for each of the next five years, we note that Addax’s 447 million barrels of oil reserves reflect 8.5 years of reserve life at current production levels. We, in addition, believe that the company has the ability to, at a minimum, sustain its current production levels as a plateau into mid 2011. Managed by a technically proven, geopolitically savvy team. We like Addax’s management team. With their extensive international oil and gas experience, combined with a solid understanding of local politics in the company’s areas of operations, we view this team as the perfect complement to the company’s asset base. C$2.2 billion in technically ‘low risk’ cash flow estimated for 2008. Addax’s current production is from technically ‘easy to produce’ fields, translating into a low risk (technical) 2008E cash flow from operations of C$2.2 billion. In the longer term, we estimate that the company could sustain and increase this cash flow just by blowing down current 2P reserves. As such, under Addax’s current enterprise valuation of C$9 billion, and assuming a long term oil forecast of US$130 per barrel of WTI oil, we believe, for the longer term investor, that there is limited downside in investing in Addax at current levels, with significant upside to be had through potential reserve and/or production increases.

Annual production growth of 35% for past decade leading to 140,000 bopd+ of current production

Managed by a top tier team

C$2.2 billion in 2008E cash flow

447 million barrels of reserves


2.2 billon barrels of exploration potential in prolific basins. Addax has identified in excess of 2.2 billion barrels of exploration potential it intends to target over the next three years. While we currently model an average geological chance of success (COS) of 5% for this exploration in our NAV calculations, Netherland Swell and Associates (NSAI) estimate it at 33%, and Addax delivered 77% in 2007. A repeat of the company’s 2007 exploration and appraisal drilling success rate could thus translate into 1.7 billion additional barrels of discovered oil by 2010. This would equate to a potential fourfold increase in the company’s booked reserves. Near term catalysts. We believe the following near term catalysts could create additional value for current Addax shareholders:

Results from Nigeria, Cameroon, Gabon and Kurdistan exploration wells during all of 2008;

Potential spudding of a JDZ well in 4Q08, with results in 1Q09; Debottlenecking of Gabon production, via “new” export line; Potential for gas monetization agreements in Nigeria; Potential production from Kurdistan in 2H08; Opportunity drilling of JDZ well in 3Q08; Potential growth by acquisition.

Risks to investment thesis and target price are listed in the Risks section.

2.2 billion barrels of exploration potential

With a 77% discovery rate in 2007


Stock Valuation and Recommendation

We have prepared an NPV (DCF, 10% after tax) summary for Addax’s assets in West Africa and the Middle East, based on blowing down the company’s booked reserves. As part of our NAV calculation on Addax, we also provide NPV (DCF, 10% after tax) calculations on the company’s exploration potential of 2.2 billion barrels of oil. We calculate a risked sum‐of‐the‐parts NAV of C$10,670 million, or C$68.55 per share (fd) for Addax. Exhibit 2: Risked Contingent Net Asset Value Summary

WI Reserves/Resources Unrisked NPVUnrisked NPV Risking Risked NPVRisked NPVmm Barrels US$ million Per share US$ million Per share

OML 123 and OML 124 185 US$3,670 US$23.58 100% US$3,670 US$23.58OML 126 and OML 137 70 2,089 13.42 100% 2,089 13.42Okwok 8 264 1.70 100% 264 1.70Maghena 39 767 4.93 100% 767 4.93Panthere NZE 37 989 6.36 100% 989 6.36Rmboue 2 39 0.25 100% 39 0.25Etame Marin 13 145 0.93 100% 145 0.93Awoun 19 474 3.05 100% 474 3.05Taq Taq 75 1,042 6.70 100% 1,042 6.70Reserve based NAV 447 9,480 60.91 9,480 60.91

2008E net cash/(debt) (US$734) (US$4.72) 100% (US$734) (US$4.72)

Reserves net asset value US$8,745 US$56.19 100% US$8,745 US$56.19Reserves net asset value (C$) C$8,745 C$56.19 100% C$8,745 C$56.19

Taq Taq upside US$1,042 US$6.70 5% US$52 US$0.33Nigeria Exploration upside 807 18,500 118.86 5% 925 5.94Gabon Exploration upside 136 2,975 19.12 5% 149 0.96Cameroon Exploration upside 100 2,172 13.95 5% 109 0.70Deep Water Exploration upside 1204 13,801 88.67 5% 690 4.43Exploration upside 2246 38,490 247.30 1,925 12.37

Net asset value US$47,236 US$303.49 US$10,670 US$68.55Net asset value (C$) C$47,236 C$303.49 C$10,670 C$68.55

Source: Company Reports, Raymond James Ltd.

A core, reserved backed NAV of C$56.19 per share

With an additional C$247 per share in longer term exploration potential


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Given the continued volatility in commodity pricing, we are providing investors with valuation sensitivities for our risked NAV per share (fd) on Addax under different long term oil prices and different discount rates. Exhibit 3: NAV Sensitivity

Source: Raymond James Ltd. Note that current market valuations appear to be pricing Addax on the basis of the company’s booked reserves under US$120 per barrel long term WTI (10% DCF, blowdown case). In addition to this reserve value, current valuations offer investors a free option on 2.2 billion barrels of potential oil, 2.4 TCF of contingent gas resources, and a history of accretive growth. We consider Addax a must own core holding in an International Oil and Gas portfolio. Exhibit 4: Addax Value Creation Source: Company Reports, Raymond James Ltd.


Reserves Growth

Addax continues to deliver year‐over‐year reserve growth from its expanding asset base. Exhibit 5: Addax Property Breakdown

Country Asset 2007 Oil 2007 YE Addax Operator Contingent Resources Prospective OilProduction 2P Reserves Working Gas Associated Liquids ResourcesMbbld/d MMbbl Interest Bcf MMbbl (Unrisked)

MMbbl Nigeria

OML 123 55.9 161.4 100% AXC 1000 28 401OML 124 7.4 23.4 100% AXC 381 22 82OML 126 41.3 52.4 100% AXC 106 2 250OML 137 ‐ 17.1 100% AXC 926 25 74Okwok ‐ 8.4 40% AXC 2 ‐ ‐Sub‐total 104.5 262.7 2415 77 807

CameroonNgosso ‐ ‐ 60% AXC ‐ ‐ 100Sub‐total ‐ ‐ ‐ ‐ 100

GabonOnshore 15 96.3 Various Various ‐ ‐ 34.9Offshore 6.4 13.4 Various Various ‐ ‐ 100.7Sub‐total 21.4 109.6 ‐ ‐ 135.6

Kurdistan Region of IraqTaq Taq* ‐ 74.6 45% TTOPCO ‐ ‐ ‐Sub‐total ‐ 74.6 ‐ ‐ ‐

Deep Water Gulf of GuineaOPL 291 ‐ ‐ 73% AXC ‐ ‐ 477.4JDZ (Blocks 1, 2, 3 & 4) ‐ ‐ Various AXC/Various ‐ ‐ 726.6Sub‐total ‐ ‐ ‐ ‐ 1,204 TOTAL 125.9 446.9 2,415 77 2,246

Notes: * Assumes government back‐in exercised

Source: Company Reports, Raymond James Ltd. Going forward, Addax aims to substantially grow its discovered reserves through exploration activities, which it considers a core business activity. Having reviewed the company’s growth strategy, we describe it as a “three pronged cyclical approach.” Cyclical, as each component feeds into the next. The strategy involves the acquisition of new prospective exploration acreage, followed by the identification of prospective resources through seismic studies, culminating with drilling prospects to potentially prove up reserves. For 2008, Addax plans on drilling 14 currently identified prospects, targeting 420 million barrels (120 million on a risked basis) of potential resources.


Although exploration outcome is binary, Addax’s extensive range of exploration targets is statistically significant, allowing for the potential discovery of 120 million barrels in 2008. As such, and accounting for depletion from our 2008E production forecast of 145,000 bopd, we anticipate that organic exploration success could increase Addax’s reserves by 15 to 20% at year end. By 2010, the company intends to have drilled the majority of its current inventory of 80 prospects, potentially adding in excess of 2,200 billion barrels to its current 447 million barrels of reserves. Addax is also budgeting for the acquisition of 600 km of 2D, and 2,000 km2 of 3D seismic data this year, aimed at increasing its prospective resource base from the current 2,246 million barrels of oil. In the longer term, management plans on carrying out two to three seismic surveys per year, aimed at adding to its prospect inventory. In addition to this organic growth focus, Addax’s CEO has expressed the possibility of future accretive acquisitions, but only at the ‘right’ price point. While specific details of potential expansions have not been provided, we expect the company would maintain its current modus operandi through any new ventures. It is our view that any future expansion could take the form of corporate transactions, such as Pan Ocean in 2006, asset acquisitions/farm‐ins, such as the JDZ block 1 deal, or asset awards, such as the recent Iroko exploration license in Cameron. Given this team’s successful track record in value generation from all three types of transactions, we would expect any future growth to be accretive to investors in Addax. In the longer term, areas that come to mind are parts of the Former Soviet Union (FSU) such as Azerbaijan and Turkmenistan; still offering ‘open market’ type petroleum contracts, as well as relatively under‐developed and under‐explored acreage. In addition, we also believe significant growth potential is achievable from the company’s extensive exploration acreage. Management has also expressed the potential for near term (2008) potential corporate acquisitions, indicating ongoing discussions.


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2005A 2006A 2007A 2008E 2009E 2010E 2011E 2012E 2013E 2014E 2015E

Barrels per day (000s)

Kurdistan

Gabon

Nigeria

Production Growth

For 2008, we are expecting the company to produce 145,000 bopd, a 15% increase over last year’s 126,000 bopd. Note that our above estimate does not include potential production from the Taq Taq field in Kurdistan, which could add another 3,000 bopd to our annual average forecast. While we expect relatively minor production growth from Nigeria in 2008 and 2009, we are forecasting significant growth from Gabon over this period. For 2009, we are currently forecasting total company production of 165,000 bopd. In the longer term, we believe Addax is positioned to deliver close to 200,000 bopd production by 2010/2011. In addition, pending resolution of the petroleum export situation in Kurdistan, analysis of the Taq Taq field indicates potential production of 150,000 bopd (gross) by 2011. Combining all this, we believe that Addax’s stars are aligned for exposure to potential production (working interest) of almost 300,000 bopd in four to five years. Exhibit 6: Addax Production Profile Source: Company Reports, Raymond James Ltd.


100%, indirect

Addax Petroleum Corporation

Addax Petroleum Corporation Holdings

Addax Petroleum Overeseas Ltd. (BVI)

Addax Petroleum Services Ltd. (Isle of Man)

Addax Petroleum (Nigeria Offshore Ltd. (Nigeria)

Addax Petroleum International Ltd.

(Isle of Man)

45% Taq Taq Operating Company Limited (BVI)

Addax Petroleum Exploration (Nigeria) Ltd.

(Nigeria)

Addax Petroleum Mauritius Limited (Mauritius)

Addax Petroleum Development (Nigeria) Ltd.

(Nigeria)

Addax Petroleum NZE Inc. (Gabon)

Addax Petroleum Maghena Inc. (Gabon)

Addax Petroleum Etame Inc. (BVI)

Company Profile

“In a harsh desert, not even jackals can survive; only addax and fennecs are found there these animals were created by God to remind man of his own limits.” – Sidati Ag Scheik

Addax is a successful international oil and gas company, focused on leveraging management’s technical expertise and extensive network of contacts into value generation from its assets. Addax shares currently trade on both the Toronto Stock Exchange and the London Stock Exchange under the symbol AXC. The corporate and capital structures of the company are illustrated below. We have also included a list of Addax’s top ten institutional shareholders. Exhibit 7: Addax Corporate Structure



(M)Common Shares Outstanding 155.6Share based comp 0.9Shares O/S ‐ fully diluted 156.5Market Capitalization 8,163

Holders SharesBLACKROCK GROUP LIMITED 1.4%GOODMAN & CO INVESTMENT 1.1%MCLEAN BUDDEN LIMITED 0.9%JPMORGAN ASSET MANAGEMENT 0.6%FIDELITY MANAGEMENT & RESEARCH 0.5%OPPENHEIMERFUNDS INCORPORATED 0.5%FIRST CANADIAN MUTUAL FUNDS 0.5%CARMIGNAC GESTION 0.4%LORD ABBETT & COMPANY 0.4%DWS INVESTMENT SA 0.4%

Exhibit 8: Market Capitalization and Top 10 Holders Source: Bloomberg, Raymond James Ltd.

History

In 1994, the Addax and Oryx Group (AOG), a private petroleum and mining company, founded the predecessor to Addax to focus on oil and gas opportunities in West Africa. In 1998 the company acquired a 100% interest in Oil Mining Licenses (OML) 123 and 124, as well as OML 126/137 in Nigeria. In 2002, the company expanded its West African operations by acquiring a 60% interest and operatorship in Cameroon’s Ngosso offshore block. A third West African country was added in early 2004, via a 42.5% interest in the Tullow operated offshore Gabon Kiarsseny block. By farming into the Taq Taq block in Kurdistan (Northern Iraq), Addax entered the Middle East in 2005. Addax Petroleum Corporation was also incorporated under the Canada Business Corporations that same year. It listed it shares on the Toronto Stock Exchange the following year. In 2006, Addax significantly expanded its asset base through the following acquisitions: a 72.5% interest in OPL 291 (high impact Nigerian deep water exploration block), a 40% interest in Nigeria’s Okwok shallow water discovery, interests in JDZ blocks 2, 3 and 4 (high impact deep water exploration), and expansion for the Gabon assets via the corporate acquisition of Pan‐Ocean Energy. In 2007, the company acquired a 50% interest and operatorship of the Epaemeno block onshore Gabon, as well as a 40% interest in JDZ block 1. Addax has also recently signed a PSC for the Iroko exploration license offshore Cameroon.


Leadership team

We like the management at Addax; the team has a proven international oil and gas track record. Management has an extensive history of successfully operating in the company’s major project areas in West Africa and the Middle East. The management team at Addax includes the following: Jean Claude Gandur, President, CEO and Director, has been active in the oil & gas industry for over 33 years, including tenure with Phillip Brothers. Prior to founding Addax through the Addax and Oryx Group, he was the Managing Director for Sigmoil Resources N.V., and Kaines SA. Mr. Gandur also served as the Republic of Congo’s Honourary consul in Geneva for 10 years. We view Mr. Gandur’s close ties with several African nations as a key to Addax’s continued success in the region. Mr. Gandur is a graduate of the University of Lausanne (Law). James Pearce, COO, has held various managerial as well as technical roles with Chevron over the past 30 years, including responsibility for the company’s Nigerian deep‐water operations. Mr. Pearce is a graduate of the California Institute of Technology (Ph.D in Mechanical Engineering). He also holds two US patents. Michael Ebsary, CFO, joined Addax from Elf (now Total), where he was the Senior Manager, Project Finance responsible for financings in emerging markets, particularly in Nigeria, Chad and Cameroon. Prior to Elf, Mr. Ebsary held finance positions with the Bank of Nova Scotia and the Bank of Montreal. Jeff Schrull, Corporate GM Exploration Addax Petroleum, has been with Addax for over 2 years, leading the company’s exploration operations. Prior to Addax, he held various domestic and international oil & gas engineering, operations and senior management positions for close to 20 years, including Chevron’s Exploration and New Ventures Manager for Nigeria Mid Africa. Mr. Schrull is a graduate of Texas A&M (M.Sc. in Geophysics). Henry Legarre, Technical Manager ‐ Middle East, has over 20 years of oil & gas experience. The majority of his career was with Chevron, in various global leadership and technical roles. Academically, Mr. Legarre has extensive publications in geologic modeling, production geology, carbonate and clastic stratigraphy, geochemistry, and reservoir characterization.


Operations

The company is currently focused on two main operational areas: The West Coast of Africa, and the Kurdistan region of Northern Iraq. The Middle East focus is on developing and monetizing significant exploration success on the Taq Taq field, as well as exploration activities on the Kewa Chermila block. The African projects encompass cash flow from current production and continued development of existing oil fields, as well as a mix of low risk and high impact exploration plays. Exhibit 9: Addax Area of Operations

Source: Company Reports

Nigeria and JDZ

Nigeria, a West African country, is bordered by Benin to the west, Chad and Cameroon to the east, the Gulf of Guinea (Atlantic) to the south, and Niger to the north. With a population of almost 140 million people, reportedly the most populous country in Africa, and a GDP (2007) of US$126.7 billion (US$2,200 per capita) the country remains one of the richest in Western sub Saharan Africa. Following almost three decades of military rule, Nigeria transitioned to a multiparty democracy in 1999. President YarʹAdua, in power since 2007, follows two terms (1999‐2006) by president Obasanjo. Nigeria continues to face longstanding ethnic and religious tensions, including militants fighting along ethnic and religious lines. This violence has led to 900,000 barrels of oil, close to a third of Nigeria’s total production capacity, to be shut in during early 2008, mainly from the western Niger delta.


The Nigeria‐São Tomé and Príncipe Joint Development Zone (JDZ) was agreed to in 2001. It is offshore Nigeria and São Tomé and Príncipe, and is jointly administered by the two countries. Any revenue generated from the area would be shared between the two countries. São Tomé and Príncipe, one of Africa’s smallest nations, is a series of islands that lay offshore Western Africa. Following independence in 1975, the country transitioned to free elections in 1991. The award of the first JDZ licenses in 2004, as well as the recent oil discovery in the area has translated into some economic recovery for the country. Real GDP growth exceeded 6% in 2007, as a result of increases in public expenditures and oil‐related capital investment. Addax’s current Nigerian/JDZ portfolio consists of a 100% interest in OML123, 124, 126 and 137, a 72.5% interest in OPL 291, a 38.3% interest in the Okwok field, a 40% interest in JDZ block 1, a 14.33% interest in JDZ block 2, a 15% interest in JDZ block 3, and a 33.3% interest in JDZ block 4. Exhibit 10: Nigeria Properties



Geologically, Addax’s Nigerian properties are located in the prolific Niger Delta Basin, part of one of the most prospective petroleum provinces in the world. Situated in the Gulf of Guinea (Atlantic), the basin extends over approximately 75,000 km2, with up to 10 km of sedimentary thickness. Shales in the Akata and the Agbada formations are considered to be the most likely source rocks, or “kitchen”, for the basin. These formations, in addition to the Benin, were deposited during the opening of the South Atlantic (separation of Africa from South America). Several geological factors have contributed to the prolific nature of this basin. As with any petroleum basin, three key components need to act in concert to deliver good prospectivity. The presence of source rock, good reservoir, and some type of trapping mechanism all have to be present. With over 50 billion barrels of oil reported as discovered to date, the presence of a kitchen in the Niger Delta is hard to dispute. In addition to excellent reservoir properties, Niger Delta producing zones tend to be stacked, increasing the potential to add reserves through the discovery of new fields, or new reservoirs on previous discoveries. As for trap, this Delta complex contains extensive structures, including several four‐way closure anticlines, creating a very efficient trapping mechanism for regional oil and gas fields. We do, however, note that while extensive in number, these traps – or structures – are limited in areal extent and thus, size. While this limits the potential to discover elephant fields, it does increase the chances of finding new fields in previously explored blocks. While the basin is mainly oil prone, gas reservoirs are also present, including high levels of associated gas.


Exhibit 11: Niger Delta Geology

Source: Ministry of Energy – Equatorial Guinea

OML 123

OML 123, initially awarded to Ashland (Marathon) in 1973, was acquired by Addax in 1998. This block remains Addax’s main producing area in Nigeria. Covering 367 km2, OML 123 is located in shallow waters off the coast of Nigeria. Following the transition from Ashland, Addax upgraded production facilities, installed a new FPSO (Knock Adoon) in 2006, and developed new fields on the block, leading to substantial increases in production from the block. Specifically, OML 123’s production was increased from under 8,000 bopd in 1998 to a 2007 average rate of 56,000 bopd. Production from the block, averaging 29° API, is sold as Antan crude and is priced at a slight discount to Brent.


For 2008, we currently model production from the block at 67,000 bopd, at the mid point of the company’s guidance of 64,000 to 69,000 bopd. In the longer term, and excluding any potential discoveries from the block, we expect production levels to remain flat into mid 2010, with production reducing at 25% per annum thereafter. Enter the company’s exploration prospects. With at least 10 targets identified to date, the company has the potential to maintain the current 65,000 bopd production plateau well into the next decade. Specifically, in addition to the 161 million barrels of reserves (2P) booked at the end of 2007, Netherland Swell & Associates Inc. (NSAI), a third‐party engineering firm, has evaluated OML 123 as potentially containing undiscovered (un‐risked) resources of 401 million barrels of oil (110 million barrels, risked) net to Addax (best estimate case). As an aside, while NSAI, based on the geo‐scientific work carried out on OML 123 to date, assigns a one in four COS to this potential resource base, we note that Addax’s historical exploration success is closer to 80% on this block. In addition to the oil resources, NSAI has identified one trillion cubic feet of gas (best case estimate) on OML123. While this estimate reflects discovered gas, the resource is classified as contingent pending award of a PSC covering rights to the gas, as well as identification of a commercial market for the resource. Note that Addax is currently negotiating with the Nigerian government for PSC gas rights, and is also investigating the commercialization of this resource.

OML 126

While OML 126 was also acquired from Ashland in 1998, production from this offshore Niger Delta 722 km2 block is from greenfield developments. In addition to developing the legacy Okwok discovery, Addax has discovered and developed the Nda field on the block. OML 126’s production is currently processed via a 50,000 bopd capacity FPSO (Sendje Berge) and sold as Okwori Blend (35° to 38°API), at a slight premium to Brent. For 2008, we currently model production from the block at 36,000 bopd, at the upper end of the company’s current guidance of 32,000 to 37,000 bopd. Given that OML126’s potential has historically been under‐estimated – 2007 average production came in 5% higher than Addax’s upper guidance number – we would not be surprised were the company to beat its guidance, as well as our production estimates, for 2008. In the longer term, and excluding any potential discoveries from the block, we expect production to decline by 12% per annum as of 2009. Note, however, that similar to production, reserves from OML126 have been under‐booked in the past. Specifically, significantly better than expected reservoir performance at Nda led to significant upwards revision of the field’s reserves at year end 2007. In addition, NSAI estimates potential un‐


risked prospective resources of 250 million barrels of oil (37 million risked) on the southern half of the block. We currently calculate that each additional four million barrels of oil discovery could extend plateau production by an extra year. Addax is also currently planning to acquire 3D seismic on the northern half of block later this year, with exploration drilling currently planned for 2009. Given the company’s general, as well as block specific, track record, we do expect to see additional reserve upside from OML126 over the next couple of years. In addition to associated gas present on the block, NSAI has also identified over 100 billion cubic feet of contingent gas on OML126.

OML 124

Covering 300 km2, OML124 is unique in two ways. It is Addax’s smallest producing property, as well as the company’s only onshore Nigerian asset. The block is covered under the same PSC as OML123. OML 124’s production (23° to 48°API) is currently processed via Addax’s Izombe Flow Station. The crude is then sold via the coastal Brass River terminal at a slight premium to Brent. For 2008, we currently model production from the block at 8,000 bopd, at the lower end of the company’s guidance of 7,000 to 10,000 bopd. While we believe the field is capable of producing 10,000 bopd, we believe our lower production forecast is warranted given the potential for export disruptions from the Brass River Terminal due to potential militant activity in the area. In the longer term, and excluding any potential discoveries from the block, we expect production to decline by 15% per annum as of 2009. NSAI has identified 82 million barrels of prospective resources (16 million risked basis) from several mapped prospects on the block. Addax currently plans on drilling two of these later this year. In the event of discoveries, our calculations indicate the potential to increase the block’s production to 12,000 bopd by 2010. In addition to OML124’s associated gas, NSAI has also identified over 380 billion cubic feet of contingent gas on the block. As part of potential plans to monetize this gas, Addax is currently investigating the construction of an LPG facility adjacent to the Izombe flow station.

OML 137

Acquired in 1998, this 849 km2 exploration and appraisal stage block lies adjacent to OML126, in shallow to intermediate Nigerian waters. The block is also covered under the same PSC as OML126. Having booked its first reserves, 17 million barrels of oil (2P) on the block in 2007, Addax currently plans on establishing a new offshore production hub on OML137. Specifically, the company is currently targeting first oil from the Ofrima north discovery by late 2009/early 2010. We currently model first oil production in 2010, with an average rate of 14,000 bopd.


In addition to the booked 2P reserves, NSAI currently assigns 925 billion cubic feet in contingent gas (best estimate case) to the block, and a potential 74 million barrels of undiscovered oil resources (14.6 million risked). We do not, pending official government award of rights to the gas, model gas production from this block. Based on the recent Nigeria LNG proposal for two additional LNG trains for the Bonny facility, we do view OML137 gas as an excellent feedstock for these trains, given its location, in close proximity to the GTS‐3 pipeline, also known as the Offshore Gas Gathering System, feeding the Bonny plan.

Okwok field

Awarded to Oriental Energy, an indigenous Nigerian firm, as part of the Nigerian marginal field program earlier this decade, the Okwok field has 8.4 million barrels of oil reserves (2P). Under an agreement with Oriental, Addax currently owns a 40% working interest in the field. As part of this agreement, Addax, as technical advisor, will operate the field. Two recent appraisal wells produced medium to light oil (23° to 48°API), at flow rates of up to 1,220 bopd per well. While the field remains at the engineering stage, the close proximity of this field to OML 123 could lead to potential production being processed on the Knock Adoon FPSO. We are currently forecasting first oil from this field for 2009, with peak production of 9,000 bopd (gross), declining at 15% per annum.

Deep water blocks

Addax currently has over 1,743 net km2 highly prospective deep water exploration acreage offshore Western Africa. In Nigeria, Addax currently has a 72.5% interest in the 1,287 km2 (gross) OPL 291 block. Based on 2D seismic acquired to date over the majority of the block, Addax has identified two prospects estimated by NSAI as potentially containing 477 million barrels of undiscovered oil (163 million risked). Following 3D seismic acquisition scheduled for this year, the company plans on drilling an exploration well next year. While the 34% geological COS assigned by NSAI to this resource could be interpreted as aggressive, we note that the prospects lie on trend with the Agbami field, one of the largest single discoveries in deepwater West Africa. Note that we currently model a very conservative 5% COS, in line with new play exploration COS numbers, for this block in calculating our risked NAV on Addax. In the JDZ, Addax currently has the following working interests: 40% in block 1, 14.33% in block 2, 15% in block 3 and 38.305% in block 4. It also has operatorship of block 4. Combined, the blocks add 527 km2 (net) to Addax’s deep water exploration portfolio. Including the Obo discovery on block 1, and based on extensive 2D and 3D seismic coverage, NSAI currently estimates un‐


risked potential prospective resources of 727 million barrels (313 million risked) of oil net to Addax’s interest from prospects on the blocks. While the average 43% COS attributed by NSAI to this potential resource can be considered as aggressive for exploration plays, it can easily be supported by current geo‐scientific information on the blocks. Specifically, Addax has seismically identified a meandering channel system running ENE to WSW along the four blocks, with the Obo‐1 discovery confirming the presence of a working hydrocarbon system (source and migration) along this channel. While trap and seal for each prospect can only be fully confirmed through drilling, analysis of public information provided by Addax indicates good closure on most of the blocks prospects, including the potential for four‐way dip closure on some. In addition, reservoir sands targeted by the partners are proven as being very productive in the basin, limiting reservoir risks. Exhibit 12: Potential Meandering Channel in Deep Water, Nigeria

Source: Company Reports As further support for the NSAI COS, RPS Group (RPS‐LSE, not rated), in a separate and independent competent person’s report executed for Afren (AFR‐AIM, not rated) assigned a 56% COS for the three main prospects in block 1.


Exhibit 13: Joint Development Zone (JDZ)

Source: Company Reports With the current economics of developing deep water projects requiring proven reserves of 150 million to 200 million barrels or more per producing facility (typically an FPSO), and given the ‘small’ average prospect size (38 million barrels of potential recoverable oil) on the blocks, we believe Addax and its partners will have to develop any discoveries in clusters. With most of the block 1 prospects, including the Obo discovery, within a 20‐25 km radius of each other, ‘cluster type’ development would be feasible in the event oil is discovered in several of the mapped structures. Similarly, each of blocks 2, 3 and 4 contain prospect clusters that could potentially be developed from a single FPSO. Addax has contracted the deep water drill ship Aban Abraham to drill up to 10 wells on the blocks. While the first target, Kina prospect on block 4 is expected to spud in late 2008, note that the Aban Abraham’s time of arrival on location could be delayed to mid‐2009. To address this, as well as accelerate exploration on the blocks, Addax and its partners are actively trying to secure a drilling slot on a ‘rig of opportunity’ passing through the region later this year.

Gabon

Gabon, a West African country, is bordered by Gulf of Guinea (Atlantic) to the west, Congo (Republic) to the east and south, and Cameroon and Equatorial Guinea to the north. With a population of almost 1.5 million people and a GDP (2007) of US$10.3 billion (US$13,800 per capita), the country is one of the most prosperous, per inhabitant, of Western sub Saharan Africa. Following independence in 1960, Gabon has only had two presidents including current president Bongo, in power for four decades. Natural resources, combined with strong French military and monetary support, have made Gabon one of the richest (per capita), and more stable countries, in the region.


Exhibit 14: Gabon Properties

Source: Company Reports Geologically, Addax’s Gabonese properties, with one exception, are located in the Gabon Basin, which covers most of the country’s coast/near coast areas. While the Etame Marin offshore block lies within the Congo Basin, this basin is geologically very similar to the Gabon Basin. Similar to the Niger Delta, the Gabon and Congo Basins were formed during the opening of the South Atlantic (separation of Africa from South America). A striking difference though is the presence of a salt layer, creating the pre‐salt and post‐salt sedimentary sequences. Shales in the Kissenda and Melania formations are considered to be the most likely source rocks, or “kitchen”, for the pre‐salt section. Source rocks for the post‐salt are more widespread, and tend to be localized. These include the Madiela, Cap Lopez, Azile and Anguille formations.


Addax’s current Gabon portfolio consists of a 92.5% interest in the Maghena and Panthere NZE licenses, a 90% interest in the Remboué license, a 40% interest in the Awoun license, a 31.4% interest in the Etame Marin license, a 40% interest in the Ibekelia block, a 51.33% interest in the Iris Marin, a 42.5% interest in the Kiarsseny license and a 50% interest in the Epaemeno license.

Etame Marin

Addax currently has a 31.4% interest in the Vaalco Energy (EGY‐NYSE, not rated) operated Etame Marin offshore PSC. Covering 3,074 km2, the block is located in shallow to medium depth waters off the coast of Gabon, and contains two producing fields (Etame and Avouma). The block also contains an undeveloped discovery (Ebouri). Etame Marin’s production (36°API) is currently processed on a central FPSO, the Petróleo Nautipa, and sold as Etame Crude, at a slight discount to Brent. We currently model production from the block at 6,500 bopd for 2008 and 2009, in‐line with Addax’s current guidance. Note that production declines from the Etame and Avouma fields should be compensated by production start‐up on Ebouri later this year. Excluding any potential discoveries from the block, we expect production to decline by 15% per annum as of 2009. Note, however, that Vaalco and Addax intend to drill three identified prospects on the block by the end of 2009. We currently calculate that each additional 1.5 million barrels of oil discovery could extend plateau production by an extra year. NSAI estimates potential un‐risked prospective resources of 42 million barrels of oil net to Addax (18 million risked) on Etame Marin.

Maghena

Maghena, initially awarded to Pan Ocean in 1997, was acquired by Addax via the corporate acquisition of Pan Ocean. With current production rates of approximately 20,000 bopd (gross), this block remains Addax’s main producing area in Gabon. Covering 657 km2, Maghena is located onshore Gabon. Addax currently runs Maghena, as well as neighbouring Panthere NZE, production via a 30,000 bopd central processing facility (CPF). Production from the block is sold via the Total (FP‐Fr, not rated) operated Coucal facility at a slight discount to Brent. While the current 30,000 bbl/d export capacity is adequate for current production, Addax is in the process of expanding it to 50,000 bopd to allow for future planned production increase. We currently expect completion of this expansion by the end of 2008. For 2008, we currently model production from the block at 18,000 bopd. For 2009, we expect a slight production increase to 19,000 bopd. In the longer term, while NSAI does not currently attribute any potential resources, other than


booked reserves, to the block, the planned 2008 infill 2D seismic program on the block has the potential to identify new prospective resources.

Panthere NZE

The 657 km2 Panthere block, located onshore Gabon, includes the Obangue (on production) and Autour (under appraisal) fields. We currently model 2008E production of 9,500 bopd from the block and 16,000 bopd for 2009.

Remboue

The 130 km2 Remboué block is currently Addax’s smallest asset in Gabon. The block currently produces 700 bopd (gross) from the Remboué field. For 2009, we currently model production of 700 bopd, with the lack of yoy decline attributed to well workovers currently planned on the field. In the longer term, we expect the company to blow down the remaining 1.8 million barrels of 2P reserves, while limiting capital expenditures on this field.

Awoun

Covering 1,112 km2 , the Shell operated Awoun block contains the Tsiengui West, Koula and Damier oil fields. Located onshore Gabon, the block is adjacent to Addax’s Maghena area. The block is at the development stage. For 2009, we are modeling production of 6,000 bopd from the field, net to Addax’s working interest. In addition to the 19 million barrels (2P) of booked reserves on the block, NSAI estimates a potential 31 million barrels of undiscovered resources net to Addax’s working interest.

Exploration blocks

Addax currently has a 50% interest, along with operatorship, in the Epaemeno block onshore Gabon. Having reprocessed legacy 2D seismic data on this 1,340 km2 block, Addax currently plans to carry out a 2D infill seismic program during 2008. Pending results of this work, any prospective structures could be drilled as early as 2009. Kiarsseny was farmed into during 2004. While the 5,443 km2 block contains three oil discoveries, two appraisal wells drilled to date indicate sub‐commercial reservoirs. Tullow (TLW‐LSE, not rated), as part of the minimum exploration commitment on the block, is planning to drill a well in 2009. With the current exploration term expiring in March 2010, failing a discovery on the 2009 exploration well, we anticipate that Addax could relinquish part, or even all, of the block. NSAI currently estimates a potential of 24 million barrels of undiscovered oil net to Addax’s interest from the block.


The Iris Marin and Ibekelia shallow water blocks respectively cover 611 km2 and 678 km2. These two blocks are operated by Sterling Energy (SEY‐AIM, not rated), although Addax is in the process of obtaining operatorship of the Iris Marin block. On Iris Marin, Addax plans to spud the Charlie prospect in 3Q08. Sterling currently estimates potential recoverable reserves of 21 million bbls from this prospect. In addition, the block partners, pending interpretation of the recently acquired high resolution 2D seismic, could potentially drill a second prospect on Iris in 2008. NSAI currently estimates 15 million barrels of risked prospective resources net to Addax’s interest. Sterling is currently negotiating the conversion of the Ibekelia TEA into a PSC. Addax does not currently expect any activity on this block for 2008.

Cameroon

Cameroon is bordered by Gulf of Guinea (Atlantic) to the west, Nigeria to the north, Chad and the Central African Republic to the east and south, and Equatorial Guinea, Gabon and the DRC to the south. Cameroon has a population of 18 million people and a GDP (2007) of US$20.9 billion (US$2,300 per capita). Following its creation in 1961, Cameroon has enjoyed stability under both presidents Ahidjo (1961‐1981) and Biya (1981 to date). We do note the territorial dispute with Nigeria in the 1990s over the oil‐rich Bakassi peninsula was resolved in 2006 when Nigeria ceded sovereignty of Bakassi to Cameroon. Exhibit 15: Cameroon Properties Source: Company Reports


Addax’s two blocks are located in the Rio Del Rey Basin, the eastern extension of the Niger Delta Basin. The main difference with the Nigerian Basin is sedimentation thickness, which thins as the basin extends towards its eastern edge on the Cameroon volcanic line. Shales in the Akata and the Agbada formations are considered to be the most likely source rocks, or “kitchen”, for the basin. These formations were deposited during the opening of the South Atlantic (separation of Africa from South America). All of the current producing fields in the basin are from Agbada formation sands. Addax’s current Cameroon portfolio consists of a 100% interest (subject to a 30% government back‐in right) in the Iroko license, as well as a 60% interest in the Ngosso license.

Ngosso

Addax currently has a 60% interest and operatorship in the Ngosso block, located offshore Cameroon. Covering 474 km2, the block has several legacy hydrocarbon discoveries. NSAI estimates the block to contain a potential 100 million barrels of undiscovered resources (32 million risked). Addax currently plans on drilling two explorations wells in 2008, followed by a minimum of one well in 2009. As an aside, we note that currently identified prospects on the block lie on trend with several other regional fields, including Addax’s own on OML123 in Nigeria. While this does not preclude unsuccessful exploration wells, it does add a level of certainty to the program, reflected in the one in three COS assigned by NSAI to the prospective resources.

Iroko

Addax recently acquired a 100% interest in Cameroon’s offshore Iroko block. Covering 15.75 km2, this shallow water block lies adjacent to Addax’s OML123 in Nigeria. Addax expects to drill the first exploration well on the block later this year.

Kurdistan Region of Iraq

Iraq is bordered by Iran to the west, Saudi Arabia and Kuwait to the south, Turkey to the north, and Syria and Jordan to the east. Having gained independence in 1932, Iraq was a Hashemite monarchy until 1958, followed by a decade of military coups which culminated in the ‘reign’ of Saddam Hussein from 1979‐2003. In 2005, following the 2003 invasion by a US‐led coalition, Iraq was divided into federal regions. Kurdistan, governed by the Kurdistan


Regional Government (KRG) is one of the federally recognized1 autonomous regions within Iraq, and includes the areas of Suleimaniah, Erbil and Dohuk. While the rest of Iraq remains prone to sectarian and anti‐US violence, Kurdistan continues to witness relative peace, leading to economic prosperity and growth. Exhibit 16: Kurdistan Properties

Source: Company Reports The Taq Taq and Kewa Chirmila blocks lie in the hydrocarbon rich Kirkuk Basin. This basin extends across the Zagros fold belt ranges from Iran, through Iraq, and into parts of Northern Syria. The Kirkuk Basin was formed during the Late Permian to Paleocene times, covering parts of what used to be the Tethys Ocean. Jurassic and Cretaceous ages shales and carbonates are considered the most likely hydrocarbon source rock, or “kitchen”, for this petroleum province. The Shiranish, the Jaddala, and the Fars formations, Cretaceous and Tertiary carbonates, represent the main hydrocarbon‐bearing reservoirs of the basin. Note that the wide range of reservoir porosities adds a layer of complexity to field developments as well as reservoir modeling. As for _____________________________ 1 Iraq constitution, article 113


trap, the basin contains some giant, but simple, faulted anticlines, typically identified via surface expressions, creating a very efficient trapping mechanism for regional oil and gas fields. In addition to the above structural traps, stratigraphic components are also present in some regional fields. In addition to oil, the basin is also home to several gas fields. Exhibit 17: Kurdistan Geology

Source: WesternZagros


Taq Taq

Covering 951 km2, the block includes the Taq Taq oil discovery, as well as the Kewa Chirmila prospect. Addax currently has, through the revised Taq Taq PSC signed with the KRG in February 2008, a 45% working interest (subject to a 9% back in right by the government) on the block. As we except the KRG to exercise this option, all our forecasting and models are based on a 36% interest in the field. The Taq Taq oil field is a surface visible anticline, 60 km northeast of one of the world’s largest oilfields, mainly the Kirkuk field. In addition to three legacy wells, including the 1958 discovery well, Addax and its partner (Genel Eenrji) have drilled and tested six appraisal wells targeting the Shiranish, Kometan and Qamchuga formations on the structure. With flow rates ranging between 16,170 and 37,560 bopd, these wells confirm the potential for excellent productivity from the Taq Taq reservoir sands. Addax has also acquired close to 300 km2 of 3D seismic on the field, as well as 170 Km of 2D lines, allowing Addax’s reservoir engineering team to estimate the field’s OOIP at between 550 million to 1,200 million barrels of oil. Note that this wide OOIP range is mainly due to the extensive variations in reservoir porosity (a regional theme), in addition to variability in the oil water contact across the field. In order to narrow the OOIP range, Addax, through ongoing interpretation of the 3D seismic, reservoir modeling work, and other studies, aims to address current uncertainties in porosity estimations as well as oil water contacts. Note that the field’s 75 million barrels (net) 2P reserves, as estimated by NSAI at year end 2007, reflect the low end of Addax’s OOIP range. It is our understanding that NSAI has modeled the reservoirs under a fracture porosity only assumption (0.3% porosity), while the Addax team estimates also account for up to 8% matrix porosity in parts of the field, as assessed through log and core data, as well as production tests. As such, while we currently use the company’s booked 2P reserves in our core NAV calculations, we note that the ongoing reservoir work allows for a potential doubling of booked reserves on the field. Going forward, Addax plans to drill a minimum of two additional wells on Taq Taq this year. TT‐10, the next well to be drilled, in addition to appraising the Shiranish, Kometan and Qamchuga formations, is also aimed at testing the shallower Pilaspi and deeper Jurassic and Triassic formations. In parallel, Addax plans to commence implementation of a full field development plan in 2008, including potential production and sale of 10,000 bopd (gross) from the field in 2H08. For 2009, plans include the potential sale of an additional 20,000 bopd from the field. In the longer term, pending final approval by the KRG and Iraq’s federal government, it is our understanding that two export scenarios are being considered. A 60km pipeline to Kirkuk, tying into the Kirkuk‐Silopi‐Ceyhan and the Kirkuk‐Basra export lines, as well as a


Kurdistan Region 241km pipeline directly to Silopi in Turkey, where it would tie into the Silopi‐Ceyhan pipeline. The first line, with a potential completion date of year end 2009, is an Addax specific route, and would allow potential export by 2010. Note that this route would traverse parts of Sunni controlled Iraq, home to continued insurgent violence. The second route, while running through politically stable Kurdistan, if sanctioned by year end, would take longer. It could be completed by early 2012. Note that this route is a KRG regional initiative, rather than a Taq Taq specific line. The Kewa Chermila structure, identified via surface expression and 2D seismic, covers 15 km2 in areal extent at the south east edge of the block, the Koya lead, and deeper untested horizons on the Taq Taq field, all form the company’s near term exploration potential in Kurdistan. For 2008, the company plans on drilling Kewa Chirmila, as well as the deep Taq Taq horizons.


Appendix

Fiscal Regimes Addax’s Nigerian assets are currently governed by Production Sharing Contracts, under which produced oil is allocated to royalty oil, cost oil and profit oil. Note that the contractors are required to bear all upfront capital costs, which would then be recouped via the ‘Capital Cost Oil’ category. Similarly, the company’s Gabon assets are also subject to Production Sharing Contracts. In Kurdistan, the Taq Taq Revised Production Sharing Contract is based on a similar mechanism, where the contractors bear the exploration and development costs, and risks, for the fields. Production oil is then split into Royalty Oil, Cost Oil, Profit Oil and Tax Oil. Exhibit 18: Nigeria PSC Oil Allocation

Oil Revenue

Royalty Oil

Non‐Capital Cost Oil

Tax Oil

Capital Cost Oil

Profit Oil

NNPC

Addax Petroleum



Exhibit 19: Gabon PSC Oil Allocation

Oil Revenue

Royalty Oil

Non‐Capital Cost Oil

State

Addax Petroleum Capital Cost Oil

Profit Oil



Exhibit 20: Kurdistan PSC Oil Allocation

Total Oil Produced

Operations Oil

Net Available Oil

Cost Recovery Oilup to 80% of Net Availabe Oil

Operating Costs

Exploration Costs

Development Costs

Profit Oilremaining net available oil

Total Profit Oilsharing based on ʺRʺ factorslide range of 35%/65% to

16%/84%

Contractor KRG

Addax(45%)

Genel Energi(55*%)

Royalty Oil10% of total crude oil



US$ (mln) 2004 2005 2006 2007 2008E 2009EASSETSCurrent Cash and cash equivalents 4 7 36 32 492 1554 Accounts receivable 66 134 179 312 460 460 Inventories 17 63 121 129 159 159 Prepaid expenses 14 16 26 39 39 39

100 219 361 512 1150 2212

Partner loan receivable 0 0 21 21 21 21Future loan receivable 16 156 16 7 0 0Other assets 3 5 5 20 20 20Property, plant and equipment 498 487 2083 2706 3792 4746Goodwill 0 0 493 493 493 493

516 648 2618 3247 4326 5280617 867 2979 3759 5476 7492

LIABILITIES AND SHAREHOLDERSʹ EQUITYCurrent Accounts payable and accrued liabilities 143 160 364 545 519 519 Income taxes and royalties payable 121 204 510 33 351 954 Deferred revenue 3 1 3 10 8 8

267 365 878 588 878 1481

Asset retirement obligations 12 25 47 130 132 132Future income taxes 89 93 44 125 175 175Other long‐term liablilities 7 5 11 7 6 6Long‐term debt 65 80 830 950 1125 1125Convertible bonds 0 0 0 245 247 247

173 203 932 1457 1685 1685

Shareholdersʹ equityShare capital 20 20 739 758 759 759Convertible bonds 0 0 0 56 56 56Contributed surplus 0 0 20 38 54 59Retained earnings 157 278 410 862 2044 3452

177 298 1168 1714 2913 4326617 867 2978 3759 5476 7492

Financial Statements Exhibit 21: Balance Sheet Source: Company Reports, Raymond James Ltd.


US$ (mln) 2004 2005 2006 2007 2008E 2009EREVENUEPetroleum sales 524 1219 2029 3412 5941 7810Royalties 103 211 389 586 934 1717Net sales 421 1008 1640 2826 5007 6093Other income 2 5 12 4 1 0Total net revenue 422 1013 1652 2830 5008 6093

EXPENSESOperating 88 153 204 314 323 340General and administrative 18 33 27 31 33 32Depletion, depreciation and accretion 81 173 316 581 498 542Pre‐acquisition and other expenses 0 0 32 31 6 4Share‐based compensation 0 0 25 36 16 8Interest on long‐term debt 2 4 22 85 79 79Interest on convertible bonds 0 0 0 13 14 9Other Interest 1 1 0 0 0 0Foreign exchange (gain)/loss 0 0 ‐1 6 ‐4 1Total expenses 189 364 625 1097 966 1014

Income before provision for income taxesProvision for income taxes Current 140 349 541 1045 2384 3067 Future 30 94 242 206 415 604Net income 63 206 243 482 1243 1407

Cash Flow StatementUS$ (mln) 2004 2005 2006 2007 2008E 2009ECASH FLOWS FROM OPERATING ACTIVITIESItems not requiring outly of cash:Net Income 63 206 243 482 1243 1407 Future income taxes 30 94 242 206 415 604 Depletion and depreciation 81 173 316 581 498 542 Share‐based compensation 0 0 25 36 16 8 Foreign exchange 0 0 ‐1 6 ‐4 1 Other items ‐3 ‐5 4 8 6 0

171 468 829 1319 2174 2562

Changes in non‐cash working capital 56 ‐10 256 ‐450 ‐222 0

227 458 1085 869 1952 2562

CASH FLOWS USED IN INVESTING ACTIVITIESExpenditures on property, plant and equipment ‐314 ‐381 ‐953 ‐1225 ‐1615 ‐1500Other/Change in non‐cash working capital 0 0 ‐1448 ‐12 9 0

‐314 ‐381 ‐2401 ‐1237 ‐1606 ‐1500

CASH FLOWS FROM FINANCING ACTIVITIESProceeds from issuance of long‐term debt 62 122 830 1325 200 0Repayment of long‐term debt 0 ‐110 ‐80 ‐1205 ‐25 0Issue costs on long‐term debt 0 0 ‐8 ‐19 0 0Proceeds from issuance of converts (net of fees) 0 0 0 294 0 0Proceeds from share issue 0 0 713 0 0 0Distribution of earnings 0 0 ‐48 0 0 0Dividends paid ‐27 ‐85 ‐64 ‐29 ‐61 0

35 ‐74 1343 366 114 0

Net increase in cash and cash equivalents ‐52 3 28 ‐2 460 1062Cash and cash equivalents, beginning o f period 56 4 7 34 32 492Cash and cash equivalents, end of period 4 7 35 32 492 1554


Exhibit 22: Income & Cash Flow Statements









Exhibit 23: Commodity Forecasts Source: Bloomberg, Raymond James Ltd.


Risks

Competition

The oil & gas industry is highly competitive and the corporation competes with a substantial number of companies. There can be no assurance that such competitors will not substantially increase the resources devoted to the development and marketing of products and services that compete with those of Addax or enter markets that Addax is active in. In certain aspects of its business, Addax also competes with a number of small and medium‐sized companies, which may have certain competitive advantages.

Commodity Price Volatility

The corporation is subject to the fluctuations in oil, natural gas and other commodity energy prices. It is anticipated that the international oil & gas industry has an inherently high capital cost due to large construction projects. Nevertheless, changes in commodity prices could result in a decision by Addax to suspend or reduce operations because such operations are no longer economically viable. If production is not suspended or reduced during such period, the low differential between the price of the corporation’s end products and the cost of production could lower Addax’s revenues.

Reserve and resource risks

Addax currently provides third‐party reserves evaluation on its producing assets, and calculations remain dependent on long‐term oil pricing, geological assumptions made, and the companyʹs ability to produce said reserves.

Regulatory and Political

Addax’s operations are subject to a variety international laws, regulations and guidelines, including laws and regulations relating to health and safety, the conduct of operations, the protection of the environment and the manufacture, management, transportation, storage and disposal of certain materials used in operations. Changes to laws, regulations and guidelines due to environmental changes, unforeseen environmental effects, general economic conditions and other matters may cause adverse effects to operations. The companyʹs exploration, producing and potential properties are located in Nigeria, Cameroon, Gabon, the JDZ and Kurdistan. The companyʹs operations, financial results, and valuation could be adversely affected by events beyond its control taken by the current or future governments in those countries with respect to policy changes regarding taxation, regulation, and other business environment changes. While currently semi‐autonomous, Kurdistan remains part of Iraq, existing oil exploration and agreements potentially being impacted by political changes in that country. Similarly, some of the joint


venture partners on the JDZ Blocks 2, 3 and 4, as well as Nigeria’s OPL 291 have been the subject of official investigations regarding the award of said blocks. Note that we are unaware of any investigation of Addax on said blocks.

Environmental Liability

Addax is subject to various environmental laws and regulations enacted in the jurisdictions in which it operates. Including the governance of the manufacturing, processing, importation, transportation, handling and disposal of certain materials used in operations. Addax may become liable for damages against which it cannot adequately insure or against which it may elect not to insure because of high costs or other reasons. Addax may be required to increase operating expenses or capital expenditures in order to comply with any possible new restrictions or regulations.

Operating Risk and Insurance

Operational risks and hazards could expose Addax to substantial liability for personal injury, loss of life, business interruption, property damage or destruction, pollution and other environmental damages. While insurance coverage is expected to address all material risks to which it is exposed and is adequate and customary in its current state of operations, such insurance is subject to coverage limits and exclusions and may not be available for the risks and hazards to which Addax is exposed.

Additional Financing

In order to execute our discussed plans, the corporation may require a combination of additional debt and/or equity financing to support ongoing operations, to undertake capital expenditures or to undertake acquisitions or other business combination transactions. There can be no assurance that additional financing will be available to Addax when needed or on terms acceptable to Addax. Inability to raise financing to support ongoing operations or to fund capital expenditures or acquisitions could limit growth.

Currency Exchange Rate Risk

The revenue generated from the operations of Addax may be denominated in US dollars, or other international currencies so that fluctuations in the currency exchange rates may have an impact on the results of Addax.


JUNE 16, 2008





MARKET DATAMarket Capitalization ($mln) 1101Current Net Debt ($mln) (29)Enterprise Value ($mln) 1072Shares Outstanding (mln, f.d.) 600Avg Daily Dollar Volume (3mo, mln) 3.6252 Week Range $2.24 / $0.35

KEY FINANCIAL METRICSFY-Dec 31 2007A 2008E 2009ECFPS (C$) $0.05 $0.18 $0.45P/CFPS nm 12.0x 4.7xCFPS - 1Q 0.01 0.02 0.10CFPS - 2Q 0.01 0.04 0.10CFPS - 3Q 0.01 0.05 0.11CFPS - 4Q 0.02 0.07 0.14NAVPS $3.57P/NAV 59%Revenue ($mln) $62 $158 $320Yield (%) 0%

Commodity AssumptionsWTI (US$/bbl) $72 $113 $130HHub (US$/mmbtu) $7.12 $10.00 $7.50Exchng Rate (US$/C$) $0.94 $1.00 $1.00ProductionOil (bbl/d) 4,724 6,600 11,670Nat. Gas (mmcf/d) 0 2 6Total (boe/d) 4,763 6,850 12,670

EBITDA ($mln) 23 90 231Net Debt/ CF 0.9x -0.5x -0.6x* All Figures in C$

COMPANY DESCRIPTION


STRONG BUY 13.502.12

Bankers is an international oil & gas company with operations in Europe. The company is currently developing the Patos Marinza Albanian heavy oil field, reported as containing two billion barrels of OOIP.

Bankers Petroleum Ltd. BNK-TSX

Initiating Coverage: Mediterranean Blue Skies, Albanian Heavy Oil

Event

We are initiating research coverage on Bankers Petroleum Ltd. (Bankers) with a STRONG BUY rating and a C$3.50 per share target price.

Action

With our STRONG BUY rating, we are recommending Bankers to investors looking for international oil and gas assets with long term production and reserve growth potential, managed by a proven technical team; well versed in operating in the international arena. We are also recommending a yes vote to the proposed spin off of Bankers US.

Analysis

Bankers is an international oil and gas company geared towards creating value from long life petroleum assets. It is currently focused on monetizing the two billion barrels of Original Oil In Place (OOIP) estimated to be contained in Albania’s Patos Marinza heavy oil field. While the company also offers investors exposure to US shale gas plays, the company’s Board of Directors has recommended, pending shareholder approval, a proposal to spin off Bankers U.S. into a separate entity. It is our view that this spin‐off; by allowing Mr. Badwi (CEO) and his team to leverage their core heavy oil expertise into reserves and production value creation in Albania; will prove to be positive to Bankers shareholders in the long run. Operationally Bankers is guiding towards Albanian production of 20,000 bopd by 2010. While at first glance this fourfold production increase from current levels might be considered aggressive, Mr. Badwi and his team have an established track record of under promising and over delivering. We would not be surprised were the company to exceed this production target by the end of 2010. Furthermore, it is our view that a doubling, or even tripling, of the current 147 million barrels of booked oil reserves in Albania could be achieved over the next 36 months.

Valuation

Our target price on Bankers is based on a risked sum‐of‐the‐parts NAV calculation of C$3.57 per share inclusive of C$0.30 for the US. Our longer term analysis indicates a potential value of C$5.76 per share for the company.


Table of Contents

Investment Highlights......................................................................................4

Stock Valuation and Recommendation ...........................................................6

Reserves Growth ............................................................................................8

Production Growth........................................................................................10

Company Profile ...........................................................................................11

Operations ....................................................................................................13

Risks.............................................................................................................19


Exhibit 1: Bankers Petroleum Corporate Summary

Bankers Petroleum Ltd. (BNK: T, L)Company summary Shares & listing informationOverview:Company name Bankers Petroleum Ltd. Shares & capitalization:Ticker BNK Shares outstanding ‐ basic (M) 519Exchange TSX, AIM Shares outstanding ‐ fully diluted (M) 600Rating STRONG BUY Market capitalization (C$mln) $1,101Current share price* C$2.12 Enterprise value 2007E ($mln) $1,07212‐month target price C$3.50 Key shareholders*:Total projected return (incl. dividends payable) 65% Sprott Asset Management Inc. 15.7%

BlackRock Investment Management (UK) Limited 11.7%* as at Jun 09, 2008 Management & Directors 9.2%

Properties Resources (Dec 31, 2007) (Mln Boe)Area Other/Details Reserves Proved Probable 2P 3PAlbania Albania 51 96 147 241Patos Marinza ‐‐> Production US 3 6 9 12Kucova ‐‐> Development Total 54 102 156 253US RLI (Yrs) 21.5 40.9 62.5Ardmore/Arkoma Basin ‐‐> 24,000 acres (net) Raymond James NAVPS C$3.57Palo Duro ‐‐> 260,000 acres (net)Black Warrior ‐‐> 95,000 acres (net) Key Operating and Financial DataAppalachian ‐‐> 19,000 acres (net) Year end: Dec. 31 2006A 2007A 2008E 2009E

PRODUCTION:Valuation Crude oil (b/d) 3,490 4,724 6,600 11,670Year end: Dec. 31 2006A 2007A 2008E 2009E Natural gas (mcf/d) 0 232 1,500 6,000P/CF nm nm 12.0x 4.7x Total prod. (boe/d) 3,490 4,763 6,850 12,670EV/CF nm nm 11.7x 4.6x % Natural gas 0% 1% 4% 8%P/E nm nm 19.1x 6.0x Y/Y growth 107% 36% 44% 85%Target P/CF nm nm 19.9x 7.8xOther Parameters FINANCIAL STATEMENTS:EV/BOED $156,542 Revenues ($mln) $32 $62 $158 $320EV/BOE (2P) $6.87 Royalty ($mln) $4 $7 $20 $37Commodity Price Assumptions 2007 2008 2009 LT Operating Expenses ($mln) $12 $18 $28 $33Brent oil (US$/b) $73 $113 $130 $130 Income Tax ($mln) $3 $10 $14 $16NYMEX gas (US$/mmbtu) $7.12 $10.00 $7.50 $7.50 Net Income ($mln) ‐$2 ‐$2 $58 $185

Ops Cash Flow ($mln) $9 $24 $91 $232Albania Operating Net Back Estimates

2006A 2007A 2008E 2009E CFPS ‐ basic $0.02 $0.05 $0.18 $0.45Sale price $25.51 $35.73 $63.22 $69.10 CFPS ‐ fd $0.02 $0.05 $0.15 $0.39Royalties $3.02 $4.17 $7.93 $7.90 EPS ‐basic $0.00 ‐$0.01 $0.11 $0.36Opex $9.80 $10.46 $11.27 $7.06 EPS ‐ fd $0.00 ‐$0.01 $0.10 $0.31Sales & Transport $1.82 $2.41 $2.76 $1.89 Capex ($mln) $68 $66 $80 $150Pre Tax Net Back $10.87 $18.69 $41.26 $52.25 Net Debt (surplus) ($mln) $3 $21 ($50) ($132)

Net debt/cash flow 0.3x 0.9x (0.5x) (0.6x)Tax $2.30 $5.91 $5.52 $3.46Post Tax Net Back $8.58 $12.78 $35.74 $48.79

Management & DirectorsAlbania Production Profile Name Position

Executive ManagementAbdel (Abby) Badwi CEO Ex Rally EnergyRichard Wadsworth President Ex Premier Oil, Koch PetroleumDouglas Urch CFO Ex Rally EnergyBoard representatives:Robert Cross Chairman Ex Northern Orion ResourcesAbdel (Abby) Badwi CEO Ex Rally EnergyVictor Redekop Non‐exec Simmons Energy ServicesJonathan Harris Non‐exec Ex TribekaJohn Zaozirny Non‐exec Ex Canaccord CapitalEric Brown Non‐exec Meyers Norris PennyFord Nicholson Non‐exec Ex‐Nations Energy


Source: Company Reports, Raymond James Ltd., Capital IQ.

0

5,000

10,000

15,000

20,000

25,000

2005 2008E 2011E 2014E 2017E 2020E 2023E 2026E 2029E

BOPD


Investment Highlights Borrowing phraseology from Mr. Dennis Gartman, we consider the ideal investment as one with valuations growing “from the bottom left to the top right.” Having adhered to this rule since late 2007, we strongly believe Bankers will continue to be such an investment. We are initiating coverage of Bankers Petroleum Ltd. with a STRONG BUY rating and a target price of C$3.50 per share, which reflects our calculated risked sum‐of‐the‐parts NAV of C$3.57 per share for the company. Note that this includes a NAV of C$0.30 per share for the company’s US operations. We believe a STRONG BUY rating is justified given the upside potential our target price offers from current level. For longer term investors, our current analysis indicates a potential value of C$5.76 per share by 2010, further adding support to our strongly bullish view on this name. A very well suited, multi‐faceted management team. Bankers’ management team, strong with heavy oil engineering and development expertise – provided by the likes of Mr. Wadsworth (President) and Mr. Christensen (VP Development) – recently gained, through the addition of Mr. Badwi (CEO), Mr. McMurtie (VP Exploration), and Mr. Urch (CFO), additional heavy oil geological depth, as well as strong geopolitical experience. Prior to joining Bankers in 2007, Mr. Badwi et co were credited with transforming Rally Energy Corp; an Egyptian heavy oil story; into the proverbial “five bagger investment.” Specifically, following the implementation of a three year plan similar to the one recently proposed for Bankers, capital markets valuation on Rally Energy increased from C$1.50 per share in 2004 to a C$7.30 per share sale of the company in 2007. Executing a low risk development plan. Bankers recently unveiled a three year strategic development plan for Albania, the main focus of which is continuing to grow production through recompletion and re‐activation of legacy wells on Patos Marinza. The plan is also aimed at booking additional reserves, as well as growing production, from the fields through the application of infill vertical and horizontal drilling, as well as waterflood and thermal recovery techniques. Given the historical success achieved in re‐completing legacy wells, the widespread use of infill drilling in various global heavy oil basins, and management’s previous success with secondary and tertiary recovery techniques from heavy oil reservoirs (waterflood and thermal production), we believe this three year plan presents limited technological risks. This in turn should provide investors with the ability to continue monetizing this heavy oil asset.

Executing a low risk development plan

Well suited management


Creating value through heavy oil production and reserves growth. With over 147 million barrels in 2P reserves (gross) booked on Patos Marinza at year end 2007, Bankers has a good foundation to achieve its forecast production growth. In addition, with two billion barrels of Original Oil In Place (OOIP) on this asset, the company has significant room to improve on its current reserve base. It is our view that infill drilling, combined with waterflood and thermal production, could increase recovery factors, and thus ‘bookable’ reserves, from 7‐8% of Original Oil In Place (OOIP) currently. Using other global heavy oil fields as analogs, we note that recovery rates – thus booked reserves – of 20% or more have been achieved, including at Rally Energy’s fields in Egypt. While 6% of the Patos Marinza field is reported as having been previously produced, a 20% ultimate recovery rate still leaves room for doubling the current 2P booked reserves. In addition, Bankers also recently acquired 50% of the Kucova heavy oil field, with an option to acquire the remaining 50% by June 30, 2008. With an estimated 490 million barrels of OOIP, 6% of which is reported as previously produced, the Kucova field has the potential to add another 25 million to 75 million barrels (gross) in reserves. The company also has 45.8 Bcf of 2P gas reserves in the US. Refocusing the US shale gas play. Bankers’ management recently reaffirmed its strategic objective to remain focused on exploration and development activities in Albania. The company’s board has approved a proposal to restructure the US operations into a separate entity. It is our view that such a restructuring will prove to be positive to Bankers shareholders in the long run, as it would allow Mr. Badwi (CEO) and his team to leverage their core expertise of increasing reserves and production from heavy oil fields into value creation from the Albania assets. We are recommending that shareholders vote yes to this proposal. Near term catalysts. We believe the following near term catalysts could create additional value for current Bankers shareholders:

Announcement of the Kucova reserve base, as well as capital plans for the field by the end of 2008;

Continued production growth on a qoq and yoy basis; Preliminary results from a pilot cyclical steam injection project by

early 2009; Vote on proposed segregation of the US shale gas plays into a separate

entity by the end of June 2008. Risks to investment thesis and target price are listed in the Risks section.

Creating value through heavy oil production and reserves growth

Two billion barrels of Original Oil In Place on Patos Marinza, allows significant room for bookable reserves increases

Restructuring the US shale plays into a separate entity


WI Reserves/Resources Unrisked NPVUnrisked NPV Risking Risked NPVRisked NPVmm Barrels US$ million Per Share US$ million US$/Share

Patos Marinza 147 US$1,446 US$2.41 100% US$1,446 US$2.41Kucova 13 155 0.26 100% 155 0.26Tishomingo 8 157 0.26 100% 157 0.26Reserves NPV 167 1,758 2.93 1,758 2.93

Cash / (Net Debt) US$29 US$0.05 100% US$29 US$0.05

Reserves net asset value US$1,786 US$2.98 US$1,786 US$2.98Reserves net asset value (C$) C$1,786 C$2.98 C$1,786 C$2.98

Patos Marinza additional upside 98 US$1,175 US$1.96 20% 235 0.39Kucova additional upside 13 464 0.77 20% 93 0.15Palo Duro land* N.A 26 0.04 100% 26 0.04Arkoma land* N.A 1 0.00 100% 1 0.00

Unrisked net asset value US$3,453 US$5.76 $2,141 US$3.57Unrisked net asset value (C$) C$3,453 C$5.76 C$2,141 C$3.57

*land at US$100 per acre


We have prepared an NPV (DCF, 10% after tax) summary for Bankers’ reserves in Albania and the US. In addition, based on our assessment of the company’s three year plan, as well as review of the actual assets, we provide investors with NPV calculations on potential incremental reserves from the Patos Marinza fields, as well as the Kucova field recently acquired by the company. We also provide a land based value for the US assets not associated with any third‐party certified resources, based on recent land transactions on those plays. Exhibit 2: Risked Contingent Net Asset Value Summary Source: Company Reports, Raymond James Ltd.

We calculate a reserve based NAV of C$2.98 per share for Bankers


$90 $110 $130 $150 $170

5% C$3.74 C$4.69 C$5.64 C$6.59 C$7.54

10% C$2.42 C$2.99 C$3.57 C$4.15 C$4.72

12% C$2.09 C$2.58 C$3.06 C$3.55 C$4.03

15% C$1.73 C$2.11 C$2.50 C$2.88 C$3.26


Discoun

t rate

0

1

2

3

4

5

6

Reserves Patos Marinzaadditional upside

Kucova additionalupside

Palo Duro

C $ per Share

Given the continued volatility in commodity pricing, we are providing investors with valuation sensitivities for our risked NAV per share (fd) on Bankers under different long term oil prices and different discount rates. Exhibit 3: NAV Sensitivity Source: Raymond James Ltd.

We calculate a risked sum‐of‐the‐parts NAV of C$2,141 million, or C$3.57 per share (fd) for Bankers.

Exhibit 4: Bankers Value Creation


With an additional C$2.62 per share in longer term optionality


Reserves Growth

Since the acquisition of the Albanian assets in 2004, the company has been successful at adding shareholder value through production and reserve growth. The company has consistently added reserves on a year‐on‐year basis to its asset base in Albania. By year end 2007, the company’s 2P reserves from Patos Marinza were reported by RPS Energy, a third party reserves engineering firm, at 147 million barrels, up from 102 million barrels at the end of 2006. As such, in addition to the 6% of Original Oil in Place (OOIP) previously recovered from the field, the 2P reserves reflect recovery of additional 7‐8% of OOIP, for a total recovery rate of 13‐14% of OOIP. Note that the current reserves are based on continued re‐activations of legacy wells, as well as the recently announced infill drilling on the field. Specifically, the company plans on 84 successful new reactivations for each of 2008, 2009 and 2010, as well as drilling 68 vertical and 42 horizontal infill wells during this same timeframe. Exhibit 5: Potential Recovery Methods



2008 2009 2010New Reactivations 84 84 84Waterflood Reactivations 3 19 16Total Reactivation 87 103 100

Vertical Infill Drills 13 30 25Waterflood Drills 0 7 8Horizontal Drills 2 20 20Thermal Drills 8 0 32Total New Drills 23 57 85

Recovery rates of 20% or higher have been booked using steam injection on heavy oil reservoirs, with Rally Energy being the ultimate case in point. We even note that there is discussion, and evidence, that thermal EOR methods can lead to as high as 50‐ 60% recovery rates on OOIPi. Given the size of the prize; two billion barrels of OOIP on Patos Marinza and an additional 490 million barrels of OOIP on Kucova; Bankers recently started implementing a steam injection pilot project in Albania; geared towards increasing recovery rates from the Paros Marinza field. Exhibit 6: Production Growth Assumptions

Source: Company Reports, Raymond James Ltd. As part of this project, the company injected steam on a legacy well in late 2007, achieving an estimated oil production of over 150 bopd during the first few days of production, compared to prior production of seven bopd. Given that legacy wells on the field were not engineered for the high temperature required for thermal operations, and following on the encouraging results from this initial test well, eight new thermal wells are scheduled to be drilled in 2008. Allowing for an observation year, an additional 32 thermal wells could then be drilled in 2010. Using our base case of a 20% ultimate recovery rate, and accounting for the 6% of OOIP previously produced from the field, we estimate a potential remaining bookable reserve of 273 million barrels from the field – a potential 80% increase from the 147 million barrels currently booked. Similarly, assuming an ultimate recovery rate range of 15% to 20% on the Kucova field; and accounting for the previous production of 23.2 million barrels of oil, we estimate that potential remaining bookable reserves on that property could range up to 75 million barrels.

i Dr. Ali Suat Bagci, Institute of Petroleum Engineering, Herriot-Watt University


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Prod from old wells Reactivations Waterflood New Vertical New Horizontal Thermal

In the US, Bankers reported 45.8 Bcfe of booked reserves at the end of 2007.

Production Growth

In conjunction with growing reserves, Bankers has increased Albanian production from 600 bopd in 2004 to over 5,200 bopd currently. Based on our review of the company’s assets and development plans, we are currently forecasting an average production of 6,600 bopd from Albania for 2008, slightly lower than the RPS Energy estimate of 7,230 bopd. We also forecast a 2008 production exit of 2,500 mcf/d from the Ardmore basin shale gas play in the US. Exhibit 7: Bankers Production Profile

Source: Company Reports, Raymond James Ltd. In the US, the company is currently focused on a development program for its Tishomingo shale gas field in the Ardmore Basin. A 2008 capital program of $45.0 million has been established to drill, complete and tie in 30 wells in the Tishomingo gas field. In the Palo Duro shale play, we believe that additional consistent production has to be demonstrated before this shale gas play can be declared commercial on a more regional scale.


(M)Common Shares Outstanding 519Warrants 39Stock options 41Shares O/S ‐ fully diluted 600Market Capitalization ($mln) 1101

Holders SharesSPROTT ASSET MANAGEMENT INC. 15.7%BLACKROCK INVESTMENT MANAGEMENT (UK) LIMITED 11.7%CROSS ROBERT* 4.9%CAPITAL RESEARCH AND MANAGEMENT COMPANY 4.0%NICHOLSON, FORD GRANT** 3.1%REDEKOP, VICTOR*** 1.0%CIBC ASSET MANAGEMENT INC. 0.8%FRONT STREET CAPITAL 0.8%U.S. GLOBAL INVESTORS, INC. 0.3%SENTRY SELECT CAPITAL CORP. 0.2%

Notes: * Non‐Executive Chairman, Member of Audit Committee andMember of Corporate Governance Committee, ** Director, *** Director and Member of Compensation Committee

Company Profile

Bankers shares currently trade on both the Toronto Stock Exchange, and the AIM board under the symbol BNK. The corporate and capital structures of the company are illustrated below. Exhibit 8: Bankers Corporate Structure

Bankers Petroleum Albania Ltd.(Cayman Islands)

Privatco(Alberta)

BNK Petroleum Holdings Inc.(USA)

Bankers Petroleum Ltd.(British Columbia)

Bankers Petroleum (US) Inc.(USA)

100% 50% 100%

100%, indirect

Source: Company Reports, Raymond James Ltd. Exhibit 9: Market Capitalization and Top 10 Holders



The company was initially incorporated in Canada as Errington Gold Exploration in 1983. Following a name change to Bankers Petroleum Ltd. in June 2004, the company acquired the Patos Marinza assets in Albania. Specifically, Bankers was provided with a 24 month period to evaluate the Patos Marinza field and propose a plan of development to the Albanian government and state oil company. The evaluation plan was completed in 2005, and a plan of development (PoD) for re‐completing and/or re‐activating legacy wells on the fields was approved in 2006. Under the agreement, the company has the right to produce and sell oil for a period of 25 years with an option to extend for further five year increments. In March 2008, an Addendum to the PoD was presented to the Albanian government, focused on accessing additional reserves from the field through infill vertical and horizontal drilling, and waterflood and thermal recovery techniques. In 2005, Bankers expanded its geographic focus to the US, acquiring approximately 190,000 net acres of undeveloped leases in the Palo Duro Basin in Texas. By 2006, the company had increased its US shale gas land position to approximately 260,000 acres (net) in that basin. Subsequently, the company added 250,000 acres (net) of Shale Gas potential land in Texas, Oklahoma, New York, Mississippi and Alabama, bringing its total US land position to approximately 500,000 acres (net). In 1Q07 Bankers sold a 27% interest in part of its Palo Duro acreage to Palo Duro Energy.

Leadership Team

Having spent extensive time with the Bankers’ management team, including on location in Albania, we believe they are very well equipped to transform sustainable development success into production growth. In addition to a strong geological expertise with heavy oil reservoirs, the management team has extensive previous experience working on the Patos Marinza fields in Albania. We also consider this team to be one of the better equipped ones to manage geopolitical issues in their operational areas. The management team includes the following: Abby Badwi, CEO and Director, has 35 years of oil and gas exploration, development and production experience. Prior to Bankers, he held various technical and managerial positions in oil and gas operations in North America, South America, Asia and the Middle East, including the role of CEO at Rally Energy. Mr. Badwi is a registered professional geologist. Richard Wadsworth, President, has over 14 years of international as well as Canadian oil and gas experience. Prior to Bankers, he served as the Business Unit Manager for Premier Oil Plc in Albania. He has also led several heavy oil and shallow gas development for Koch Exploration Canada. Mr. Wadsworth is a graduate of the University of Calgary (Chemical Engineering).


Ian McMurtrie, VP Exploration, joined Bankers from Rally Energy, where he was the VP exploration from 2004 to 2008. Prior to Rally, he was directly involved in discovering and developing several petroleum fields throughout North America. Mr. McMurtrie is a registered professional geologist. Bob Petryk, VP Operations, has over 28 years of oil and gas industry experience in both international, as well as Canadian operations. Prior to Bankers, he held various engineering, operational and senior management positions including President and COO of a junior public oil company, as well as Senior Vice President for a large public oilfield services company. He is a registered professional engineer. Douglas C. Urch, CFO, has over 25 years of oil and gas experience. Prior to joining Bankers, he spent 7 years as the CFO of Rally Energy. Mr. Urch is a Certified Management Accountant (CMA) and holds a B.COM from the University of Calgary

Operations

The company is currently focused on two main operational areas: Heavy oil in Albania and Shale Gas in the US.

Albania

Albania, a Mediterranean rim European country, is bordered by Montenegro to the north, Greece, Serbia and Macedonia to the east, the Adriatic Sea to the west, and Greece to the south. With a population of approximately 3.6 million, and a GDP (2007) of US$11.2 billion (US$5,500 per capita) the country remains one of the poorest in Europe. Following 46 years of communism, Albania transitioned to a multiparty democracy during 1990‐1992. While this transition remains a work in progress, the Democratic Party’s victory in the 2005 general elections has led to renewed economic growth and reduction of crime and corruption. Specifically, Albania’s GDP grew by 5% in 2007, with inflation reported as low and stable. Bankers currently has a 100% working interest in the Patos Marinza heavy oil field, as well as 50% working interest in the Kucova heavy oil field, with an option to acquire the remaining 50% by the end of June 2008. Both fields are located in the Dures Basin in southern central Albania.


Exhibit 10: Bankers Petroleum Operations in Albania


Patos Marinza

The Patos Marinza oilfield, discovered in 1928, is located approximately 10 km from the city of Fier in Albania, and is estimated to contain two billion barrels of Original Oil In Place (OOIP). The main producing zones in the field are the Gorani, Driza and Marinza unconsolidated sandstone reservoirs, containing heavy oil at depths up to 2,000 metres. Assuming the application of western heavy oil production technology such as Progressive Cavity Pumps (PCP), engineered down spacing, and EOR methods, we strongly believe that ultimate recovery rates of 20% or higher are achievable from the majority of these sands.

Kucova

In January 2008, Bankers announced the acquisition of a 50% interest in Albania’s Kucova heavy oil field, via the acquisition of 50% of a private company (Privatco). Similar to the agreement on Patos Marinza, Privatco has the right, through the Kucova Agreement with AKBN and Albpetrol, to evaluate and redevelop the Kucova oilfield. Discovered in 1926, the Kucova field was initially developed in 1935, and is estimated to have produced close to 23.2 million barrels since then. Based on legacy reservoir modeling by DeGolyer and MacNaughton, done under


Canadian NI 51‐101 standards, Kucova is estimated to contain in excess of 490 million barrels of OOIP, including approximately six percent of which has been recovered to date. Located within the same petroleum basin as Patos Marinza, the Kucova heavy oilfield presents similar geological characteristics, including multiple stacked sandstone reservoirs. As part of the acquisition, Bankers has the option to acquire the remaining 50% interest in the Kucova oilfield by June 30, 2008. While we currently expect Bankers to exercise this option, we do not yet model 100% of the field into our NAV calculations. Going forward, the company plans on completing a technical evaluation of the field, results of which, including details of planned capital program and reserves assessment are expected by the end of 2008. US Bankers currently has exposure to four emerging US shale gas plays, mainly the Palo Duro, the Ardmore and Arkoma, the Appalachian and the Black Warrior Basins. Exhibit 11: Bankers Petroleum Operations in the U.S.



US$ ($000) 2004 2005 2006 2007 2008E 2009E

ASSETSCurrent Assets Cash and cash equivalents 15,665 13,529 6,329 3,560 72,983 155,434 Investments 831 ‐ ‐ 1,120 1,428 1,428 Accounts receivable 1,192 3,846 7,214 21,128 24,177 24,177 Crude oil Inventory 72 336 713 985 1,265 1,265 Deposits and prepaid expenses 486 1,016 1,121 1,601 1,116 1,116

18,245 18,726 15,377 28,394 100,969 183,420

Property, plant and equipment 4,827 38,120 122,653 175,901 240,737 362,98923,072 56,846 138,030 204,295 341,706 546,409

Current LiabilitiesOperating loans ‐ ‐ 4,772 15,805 16,780 16,780 Accounts payable and accrued liabilities 2,345 5,766 11,369 18,444 20,840 20,840 Current portion of term loan ‐ ‐ 125 3,750 3,750 3,750

2,345 5,766 16,266 37,999 41,370 41,370

Term loan ‐ ‐ 1,875 11,250 9,688 9,688 Asset retirement obligations ‐ ‐ 1,593 2,610 3,227 3,227 Future income tax liability 101 282 3,126 13,400 27,240 43,240

Share capital 20,956 53,204 116,696 136,513 194,807 194,807Warrants ‐ ‐ ‐ 2,539 2,794 2,794 Contributed surplus 593 2,014 4,456 8,308 13,053 17,053 Deficit 923‐ 4,421‐ 5,982‐ 8,324‐ 49,527 234,230

20,626 50,798 115,170 139,036 260,181 448,88423,072 56,846 138,030 204,295 341,706 546,409

In addition to the Tishomingo field, Bankers US holds 350,000 net acres of shale gas prospective land in three other plays. For the balance of 2008, the company expects to focus on developing the Oklahoma Woodford shale Tishomingo field. Note that we currently calculate an NPV (10% DCF) of approximately US$1.5 million per Bcf of shale gas resource. Exhibit 12: Balance Sheet



US$ ($000) 2004 2005 2006 2007 2008E 2009ERevenue Oil and gas revenue 4,033 13,709 31,586 62,105 158,490 319,576 Royalties 688 1,498 3,743 7,251 19,878 36,547 Interest 43 556 569 574 1,895 3,823

3,388 12,767 28,412 55,428 140,507 286,852

Expenses Operating 1,870 7,643 12,481 18,189 28,265 32,630 Sales and transportation 155 647 2,251 4,182 6,914 8,750 General and administrative 2,003 4,078 5,760 8,311 9,922 10,000 Interest and bank charges 182 ‐689 n.a. 4,096 280 n.a. Interest on term loan n.a. n.a. 68 1,244 2,601 3,022 Foreign exchange loss (gain) ‐127 570 ‐660 ‐1,300 1,048 n.a. Stock‐based compensation 329 1,823 2,327 3,405 4,397 4,000 Depletion, depreciation and accretion 93 2,011 4,902 9,369 15,696 27,747

4,505 16,083 27,129 47,496 69,124 86,149

Earnings (loss) before income taxes ‐1,116 ‐3,316 1,283 7,932 71,383 200,703

Future income tax expense 101 181 2,844 10,274 13,840 16,000 Net income (loss) for the period ‐1,217 ‐3,497 ‐1,561 ‐2,342 57,543 184,703

Cash provided by (used in)Operating activities Net income (loss) for the period ‐1,217 ‐3,497 ‐1,561 ‐2,342 57,543 184,703Items not involving cash Depletion, depreciation and accretion 93 2,011 4,902 9,369 15,696 27,747 Future income tax expense 101 181 2,844 10,274 13,840 16,000 Stock‐based compensation 329 1,823 2,327 3,405 4,397 4,000 Other 182 ‐689 n.a. 3,430 n.a. n.a.

‐512 ‐171 8,512 24,136 91,476 232,450

Change in non‐cash working capital 708 ‐3,859 ‐338 ‐6,480 ‐316 ‐ 196 ‐4,030 8,174 17,656 91,160 232,450

Investing activities Additions to property, plant and equipment ‐4,914 ‐31,216 ‐67,727 ‐65,703 ‐79,567 150,000‐ Purchase of Investments ‐831 1,520 n.a. n.a. n.a. n.a. Restricted Cash ‐1,144 1,144 n.a. n.a. n.a. n.a. Change in non‐cash working capital ‐774 n.a. 2,090 ‐1,111 ‐132 n.a.

‐7,663 ‐28,551 ‐65,637 ‐66,814 ‐79,699 ‐150,000

Financing activities Issue of common shares and warrants, net of share issue costs 19,275 31,590 43,491 22,356 58,549 n.a. Operating loans ‐65 n.a. 4,772 11,033 975 n.a. Term loan n.a. n.a. 2,000 13,000 ‐1,562 n.a.

19,210 31,590 50,263 46,389 57,962 n.a.

Increase in cash and cash equivalents 11,742 ‐992 ‐7,200 ‐2,769 69,423 82,450 Cash and cash equivalents, beginning of period 2,778 14,521 13,529 6,329 3,560 72,983 Cash and cash equivalents, end of period 14,521 13,529 6,328 3,560 72,983 155,434


Exhibit 13: Income and Cash Flow Statements









Fiscal terms The fiscal terms of Bankers Albanian block include a 1% government royalty, increasing to 5% (incremental sliding scale) following expenditure recovery. The company is also subject to a 70% over riding royalty, declining at 15% per annum, on taken over production. A 50% income tax (following depletion of the cost recovery pool) is also payable on net income. Exhibit 14: Commodity Forecasts

Source: Bloomberg, Raymond James Ltd.


Risks

Competition

The oil & gas industry is highly competitive and the corporation competes with a substantial number of companies. There can be no assurance that such competitors will not substantially increase the resources devoted to the development and marketing of products and services that compete with those of Bankers or enter markets that Bankers is active in.

Commodity Price Volatility

The corporation is subject to the fluctuations in oil, natural gas and other commodity energy prices. It is anticipated that the international oil & gas industry has an inherently high capital cost due to large construction projects. Nevertheless, changes in commodity prices could result in a decision by Bankers to suspend or reduce operations because such operations are no longer economically viable. If production is not suspended or reduced during such period, the low differential between the price of the corporation’s end products and the cost of production could lower Bankers’ revenues.

Reserve and resource risks

Bankers currently provides third‐party reserves evaluation on its producing assets, and calculations remain dependent on long‐term oil pricing, geological assumptions made, and the companyʹs ability to produce said reserves.

Regulatory and Political

Bankers’s operations are subject to a variety international laws, regulations and guidelines, including laws and regulations relating to health and safety, the conduct of operations, the protection of the environment and the manufacture, management, transportation, storage and disposal of certain materials used in operations. Changes to laws, regulations and guidelines due to environmental changes, unforeseen environmental effects, general economic conditions and other matters may cause adverse effects to operations. The companyʹs exploration, producing and potential properties are located in Albania and the USA. The companyʹs operations, financial results, and valuation could be adversely affected by events beyond its control taken by the current or future governments in those countries with respect to policy changes regarding taxation, regulation, and other business environment changes.



Bankers is subject to various environmental laws and regulations enacted in the jurisdictions in which it operates. Including the governance of the manufacturing, processing, importation, transportation, handling and disposal of certain materials used in operations. Bankers may become liable for damages against which it cannot adequately insure or against which it may elect not to insure because of high costs or other reasons. Bankers may be required to increase operating expenses or capital expenditures in order to comply with any possible new restrictions or regulations.

Operating Risk and Insurance

Operational risks and hazards could expose Bankers to substantial liability for personal injury, loss of life, business interruption, property damage or destruction, pollution and other environmental damages. While insurance coverage is expected to address all material risks to which it is exposed and is adequate and customary in its current state of operations, such insurance is subject to coverage limits and exclusions and may not be available for the risks and hazards to which Bankers is exposed.

Additional Financing

In order to execute our discussed plans, the corporation may require a combination of additional debt and/or equity financing to support ongoing operations, to undertake capital expenditures or to undertake acquisitions or other business combination transactions. There can be no assurance that additional financing will be available to Bankers when needed or on terms acceptable to Bankers. Inability to raise financing to support ongoing operations or to fund capital expenditures or acquisitions could limit growth.

Currency Exchange Rate Risk

The revenue generated from the operations of Bankers may be denominated in US dollars or other international currencies so that fluctuations in the currency exchange rates may have an impact on the results of Bankers.


JUNE 16, 2008






KEY FINANCIAL METRICSFY-Dec 31 2007A 2008E 2009ECFPS (C$) $0.10 $0.80 $1.76P/CFPS nm 8.3x 3.8xCFPS - 1Q -0.02 0.11 0.45CFPS - 2Q 0.05 0.15 0.45CFPS - 3Q 0.04 0.25 0.44CFPS - 4Q 0.03 0.30 0.43NAVPS $6.96P/NAV 95%Revenue ($mln) $32 $125 $229Yield (%) 0%

Commodity AssumptionsWTI (US$/bbl) $72 $113 $130HHub (US$/mmbtu) $7.12 $10.00 $7.50Exchng Rate (US$/C$) $0.94 $1.00 $1.00ProductionTotal (boe/d) 1,672 4,015 6,234

EBITDA ($mln) 19 105 204Net Debt/ CF -1.3x -0.7x -1.1x

COMPANY DESCRIPTION


6.62

Gran Tierra is an international oil & gas company with operations in South America. The company currently has production stage blocks in Colombia and Argentina, as well as exploration areas in Colombia, Argentina and Peru.

MARKET PERFORM 37.00

Gran Tierra Energy Inc. GTE-TSX | GTE-AMEX

Initiating Coverage: A Substantial South American Oil Company in the Making

Event

We are initiating research coverage on Gran Tierra Energy Inc. (Gran Tierra) with a MARKET PERFORM rating and a C$7.00 per share target price.

Action

We are recommending that investors seeking a growth oriented, well managed, South American focused international oil & gas junior keep Gran Tierra on their radar screen.

Analysis

With an asset base in Colombia, Peru, and Argentina, a ‘blue chip style’ management team, growing production, and extensive exploration acreage, we believe Gran Tierra offers long term upside associated with investing in international oil & gas, with potentially lower risk than some of its peers. Growing cash flow from Gran Tierra’s production combined with medium to low risk exploration potential offers the platform for building a substantial oil & gas company. Gran Tierra’s high impact exploration lands have the potential to transform the company, with the associated returns for current shareholders. While current valuations reflect a discount to our calculated risked NAV on Gran Tierra, market is offering close to a 60% premium to the company’s reserve based NAV (under our commodity assumptions), while it is valuing other international plays on the basis of par, or a slight premium, to reserves NAV. Our concern is that markets could adjust to a potential short term commodity pullback by re‐pricing Gran Tierra closer to reserve NAV. This in turn, leads to our MARKET PERFORM rating.

Valuation

We currently value Gran Tierra on the basis of a risked sum‐of‐the‐parts NAV, which includes an NPV (DCF, 10% after tax) of booked reserves, as well as a geological risk adjusted NPV (DCF, 10% after tax) of the company’s exploration portfolio. We calculate a risked sum‐of‐the‐parts NAV of C$6.96 per share on Gran Tierra. On an un‐risked basis, we currently calculate a NAV in excess of C$60.00 per share.


Table of Contents


Stock Valuation and Recommendation ...........................................................5 Reserves Growth ............................................................................................7 Production Growth..........................................................................................8 Company Profile .............................................................................................9 Operations ....................................................................................................12 Colombia ......................................................................................................13 Argentina ......................................................................................................22 Peru ..............................................................................................................24 Appendix ......................................................................................................29 Fiscal Regimes..............................................................................................31 Risks.............................................................................................................32


Exhibit 1: Gran Tierra Corporate Summary

Gran Tierra Energy Inc.Company Summary Shares & Listing InformationOverview:Company name Gram Tierra Energy Inc. Shares & capitalization:Ticker GTE Shares outstanding ‐ basic (M) 100.0Exchange TSX Shares outstanding ‐ fully diluted (M) 122.3Rating MARKET PERFORM Market capitalization (C$mln) $662Current share price* C$6.62 Enterprise value 2007E ($mln) $63712‐month target price C$7.00 Key shareholders*:Total projected return 6% U.S. Global Investors, Inc. 4.5%

Greywolf Capital Management LP 2.1%* as at Jun 09, 2008 Management & Directors 9.7%

Properties Resources (Dec 31, 2007) (Mln Boe)Area Other/Details Reserves Proved Probable 2PColumbia Argentina 2 1 4Chaza ‐‐> Production Columbia 6 6 11Guayuyaco ‐‐> Production Total 8 7 15Santana ‐‐> ProductionArgentina ‐‐> Production RLI (Yrs) 5.4 4.8 10.2PeruBlocks 122 & 128 ‐‐> Exploration Key Operating and Financial Data

Year end: Dec. 31 2006A 2007A 2008E 2009EValuation PRODUCTION (WI):Year end: Dec. 31 2006A 2007A 2008E 2008E Columbia (b/d) 752 1,002 3,375 5,677P/CF nm nm 8.3x 3.8x Argentina (b/d) 535 669 639 556EV/CF nm nm 8.0x 3.6x Total prod. (boe/d) 1,287 1,672 4,015 6,234P/E nm nm 13.2x 4.9xTarget P/CF nm nm 8.8x 4.0x Y/Y growth 270% 30% 140% 55%Other ParametersEV/BOED $158,623 FINANCIAL STATEMENTS:EV/BOE (2P) $42.58 Revenues ($mln) $12 $32 $125 $229NAVPS C$6.96 Operating Expenses ($mln) $4 $10 $14 $18Commodity Price Assumptions 2007 2008 2009 LT Income Tax ($mln) $1 $0 $20 $20Brent oil (US$/b) $73 $113 $130 $130 Net Income ($mln) ‐$6 ‐$8 $50 $135NYMEX gas (US$/mmbtu) $7.12 $10.00 $7.50 $7.50 Ops Cash Flow ($mln) ‐$1 $10 $80 $176

Operating Net Back estimates CFPS ‐ basic ‐$0.01 $0.10 $0.80 $1.762006A 2007A 2008E 2009E CFPS ‐ fd ‐$0.01 $0.07 $0.65 $1.44

Sale price EPS ‐basic ‐$0.08 ‐$0.09 $0.50 $1.35 (net of royalties) $28.84 $59.31 $94.46 $110.55 EPS ‐ fd ‐$0.05 ‐$0.06 $0.41 $1.11Opex $10.11 $19.25 $10.22 $8.58 Capex ($mln) $18 $13 $47 $40Pre Tax Net Back $18.73 $40.06 $84.24 $101.97 Net Debt (surplus) ($mln) ($17) ($13) ($54) ($191)

Net debt/cash flow nm (1.3x) (0.7x) (1.1x)Tax $1.62 $0.54 $15.23 $9.66Post Tax Net Back $17.11 $39.52 $69.02 $92.31

Management & DirectorsProduction Profile Name Position

Executive ManagementDana Coffield President & CEO Ex EnCana (Middle East)Martin Eden CFO Ex Artumas Group Inc.Max Wei VP Operations Ex Shell CanadaBoard representatives:Jeffrey Scott Chairman Postell EnergyDana Coffield President & CEO Ex EnCana (Middle East)Walter Dawson Non‐exec Ex Saxon Energy ServicesVerne Johnson Non‐exec Ex Imperial OilNick Kirkton Non‐exec Ex KPMG


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Source: Company Reports, Raymond James Ltd., Capital IQ


Investment Highlights “Success is dependent on effort” – Sophocles

Tenfold reserve increase over two years. At year end 2007, Gran Tierra booked 11.4 million barrels of net 2P oil reserves (16.5 million barrels 3P), up from 0.7 million barrels at the end of 2005. Note that the 2007 year end reserves do not include the successful results from the Costayaco 2 and 3 appraisal wells. Based on our analysis of these results, we currently estimate the potential for an additional 15 to 30 million barrels on the Costayaco field in gross 2P reserves. Targeting significant production increase in 2008/2009. Following the above exploration value add, the company is focused on monetizing its assets over the next few years. Specifically, we currently model 2008E production of 4,015 bopd, a potential 145% increase over 2007. For 2009, we anticipate an additional yoy 55% production increase. Management team: “Been there, done that.” We believe in the team’s ability to deliver continued success. Each of Gran Tierra’s key technical team members has several decades of international oil & gas exposure. Having spent time with Gran Tierra’s management and technical teams as we reviewed the company’s operations, we were impressed by their depth of experience, as well as solid grasp of regional geology. A vision to grow into a “substantial international E&P company.” The company’s growth strategy involves growing production from current reserves, followed by identification of prospective resources – from existing or new – exploration acreage, drilling prospects to potentially prove up reserves, closing the cycle through the development of these new reserves. Low to medium risk exploration. Gran Tierra’s medium to low risk exploration assets in Colombian and Argentinean proven basins provide a steady growth foundation. High impact – game changing – exploration in Peru. The company has exposure to some very exciting, high impact, exploration acreage in Peru. While still a couple of years away from drilling, a discovery could transform Gran Tierra into a substantially larger organization than today.

Tenfold reserve increase in two years

An experienced management team…

145% production growth

…with a clear vision

Growth foundation via low risk exploration

Exposure to game changing high impact plays


Gran Tierra WI Reserves/Resources Unrisked NPV Unrisked NPV Risking Risked NPV Risked NPVInterest mm Barrels US$ million Per share US$ million Per share

Chaza 50% 9 $340 $2.78 100% $340 $2.78Guayuyaco 35% 1 42 0.34 100% 42 0.34Santana 35% 1 25 0.21 100% 25 0.21Palmar Largo 14% 1 5 0.04 100% 5 0.04Vinalar 50% 1 12 0.10 100% 12 0.10El Chivil 50% 1 10 0.08 100% 10 0.08Other Argentina 1 5 0.04 100% 5 0.04Reserve based NAV 15 440 3.59 100% 440 3.59

2008E net cash/(debt) US$54 US$0.44 100% US$54 US$0.44

Reserves net asset value US$494 US$3.87 US$494 US$3.87Reserves net asset value (C$) C$494 C$3.87 C$494 C$3.87

Chaza upside 14 $445 $3.63 5% $22 $0.18Azar upside 10 366 2.99 5% 18 0.15Putumayo A/B TEA upside 30 1,098 8.98 5% 55 0.45Argentina Exploration upside 15 143 1.16 5% 7 0.06Peru Exploration upside 300 5,100 42 5% 255 2.08Exploration upside 7,151 58 358 2.92

Net asset value US$7,645 US$62.49 US$851 US$6.96Net asset value (C$) C$7,645 C$62.49 C$851 C$6.96

Near term catalysts. We believe the following near term catalysts could create additional value for current Gran Tierra shareholders:

Costayaco field reserves update in 2H08; Exploration drilling in Colombia and Argentina in 2H08; Potential resource estimates in Peru in late 2008 or 2009.

We do, however, note that the recent share price appreciation on Gran Tierra could partially be pricing some of the above catalysts into the company’s current market value. Risks to investment thesis and target price are listed in the Risks section.


We have prepared an NPV (DCF, 10% after tax) summary for Gran Tierra’s assets in South America, based on blowing down the company’s reserves. As part of our NAV calculation on Gran Tierra, we also provide NPV (DCF, 10% after tax) calculations on the company’s exploration potential.

Exhibit 2: Risked Contingent Net Asset Value Summary



$0

$10

$20

$30

$40

$50

$60

$70

$80

Reserves ArgentinaExploration

upside

Chaza upside Azar upside PutumayoA/B TEAupside

PeruExploration

upside

C$ per Share

$90 $110 $130 $150 $170

5% C$6.81 C$7.44 C$8.08 C$8.71 C$9.34

10% C$6.02 C$6.49 C$6.96 C$7.43 C$7.89

12% C$5.79 C$6.21 C$6.63 C$7.05 C$7.47

15% C$5.50 C$5.86 C$6.22 C$6.58 C$6.95


Discount

rate

Given the continued volatility in commodity pricing, we are providing investors with valuation sensitivities for our risked NAV per share (fd) on Gran Tierra under different long term oil prices and different discount rates. Exhibit 3: NAV Sensitivity

Source: Raymond James Ltd. We calculate a risked sum‐of‐the‐parts NAV of C$851 million, or C$6.96 per share (fd) for Gran Tierra.

Exhibit 4: Gran Tierra Value Creation Source: Company Reports, Raymond James Ltd.

We calculate a core, reserve backed NAV of C$3.87 per share


0

24

68

1012

1416

18

2005 2006 2007

MMBO

Proved Probable Possible

Reserves Growth

Gran Tierra continues to deliver year‐over‐year reserve growth from its expanding asset base. Having acquired its initial assets with 0.7 million barrels of booked oil reserves (net) in 2005, the company exited 2007 with 11.4 million barrels of oil in net 2P reserves. This increase reflects a combination of acquisitions, as well as organic, reserve growth.

Exhibit 5: Reserves Growth


For 2008, in addition to potential exploration success, we currently anticipate an increase in booked reserves from the Costayaco field in Colombia. Specifically, we estimate that the incorporation of results from the two recent successful appraisal wells on the field could potentially add 15 to 30 million barrels in gross oil reserves. Going forward, Gran Tierra aims to substantially grow its discovered reserves through exploration activities. For 2008, the company plans on drilling a minimum of 3 of its 61 identified prospects and leads. Although exploration outcome is binary, Gran Tierra’s extensive range of exploration targets (61 currently identified) is statistically significant, allowing for the potential discovery of the company’s risked potential estimate, or 16 million barrels of oil, and 96 Bcf of gas. On an un‐risked basis, the company has seismically identified potential resources of 79 million barrels of oil and 336 BCF of gas. The company also holds close to a million net acres of land in Colombia, over 1.3 million net acres in Argentina, and over 3.4 million net acres in Peru. Note that the company’s total land position (6.1 million acres), covers an area half the size of Switzerland, or a fifth that of Alberta’s Athabasca Oil Sands.


Gran Tierra has; in our view; created a well balanced exploration portfolio. Low to medium risk exploration acreage in proven basins offers investors a long term growth platform. In addition, exposure to significant high impact exploration lands exponentially increases the exploration value adding potential. Having reviewed the limited available data on the company’s high impact lands in Peru; including ‘trendology’ with existing fields; the proposed geological model, as well as regional geologies, we believe that these blocks have the potential to add several hundreds of million barrels of oil resources from exploration activities. We currently model 300 million barrels of exploration potential from the company’s exploration assets in Peru, and assign these blocks a 5% COS. As an aside, we note that our 300 million barrels estimate is in line with the third party estimate of the potential oil on Pacific Rubiales’ (PEG‐TSX, STRONG BUY) neighbouring, and similar sized, blocks in Peru’s Marañon basin.

Production Growth

For 2008, we are expecting the company to produce 4,015 boed (wi), while for 2009, we are currently forecasting production of 6,234 boed (wi) from the company’s existing assets. Exhibit 6: Gran Tierra Production Profile

0

1,000

2,000

3,000

4,000

5,000

6,000

2008E 2009E 2010E 2011E 2012E 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

Barrels per day

Colombia Argentina

Source: Company Reports, Raymond James Ltd. While production, under current booked reserves, suggest a 5,750 boed production peak in 2010, we believe Gran Tierra is positioned to deliver over 10,000 bopd (net) production by 2010/2011 from its ongoing exploration and development work, including the recent Costayaco 2 and 3 wells.


Company Profile

Gran Tierra is a production and development stage international oil and gas company, currently focused on South America. The company has assets in Colombia, Peru and Argentina. The company’s shares trade on the Toronto Stock exchange, as well as the American Stock Exchange under the symbol GTE. The corporate and capital structures of the company are illustrated below. Exhibit 7: Gran Tierra Corporate Structure

Gran Tierra Energy Inc. (Nevada)

1203647 Alberta Inc Peru Branch

Gran Tierra Goldstrike Inc.

Gran Tierra Energy Inc.(Alberta)

PCESA(Ecuador)

Gran Tierra Argentina SA(Argentina)

Gran Tierra EnergyColombia Ltd

Colombia Branch



(M)Common Shares Outstanding 100Warrants 17Stock options 6Shares O/S ‐ fully diluted 122Market Capitalization ($mln) 662

Holders SharesU.S. GLOBAL INVESTORS, INC. 4.5%DAWSON, WALTER 2.5%GREYWOLF CAPITAL MANAGEMENT LP 2.1%SCOTT, JEFFREY 6.6%COLLFIELD DANA 5.3%ORUNESU, RAFAEL 5.3%WEI, MAX 5.1%HART, JAMES 5.1%SMITH, NADINE 5.0%JOHNSON, VERNE 4.5%

Exhibit 8: Market Capitalization and Top 10 Holders Source: Capital IQ, Raymond James Ltd.

Leadership team

We believe in the team’s ability to deliver continued success. Each of Gran Tierra’s key technical team members has several decades of international oil & gas exposure. Dana Coffield, President, CEO, and Director, came to Gran Tierra with a proven track record in international oil & gas operations. His last position prior to Gran Tierra was VP Middle East Business Unit for EnCana. He has also held various managerial as well as technical roles with Alberta Energy Company, and Arco International. Mr. Coffield is a graduate of the University of South Carolina (M.Sc. and PhD in Geology), as well as the Colorado School of Mines (B.Sc. in Geological Engineering). Max Wei, VP Operations, joined Gran Tierra in May 2005. Prior to that, he was EnCana’s Team Leader for Qatar and Bahrain operations. In addition, he has held positions with Shell, Imperial Oil, Bechtel, Occidental Petroleum and Marathon in far reaching corners of the globe, including South America. Mr. Wei is a graduate of the University of Alberta (B.Sc. in Petroleum Engineering).


Martin Eden – CFO, joined the company from Artumas Group, where he was also the CFO. Mr. Eden has over 26 years of accounting and finance experience in the domestic and international energy industry, including as CFO of Chariot Energy, Assure Energy, Kyrgoil Corporation and Geodyne Energy. Mr. Eden was also Finance Manager of Nexen’s Yemen operations. He is a graduate of Birmingham University (B.Sc. in Economics) as well as Brunel University (MBA). Edgar Dyes – President, Gran Tierra Energy Colombia, was previously the COO of Argosy Energy’s general partner. He has over 20 years of hands‐on Colombian oil & gas experience. Prior to that, Mr. Dyes held various technical and managerial positions with Union Texas Petroleum, Quintana Energy Corporation, Jackson Exploration, CSX Oil and Gas, and Garnet Resources. In addition to Colombia, he has worked in the United Kingdom, Germany, Indonesia, Oman, Brunei, Egypt, Somalia, and Ecuador. Mr. Dyes is a graduate of the Stephen F. Austin State University (Business).


Country Asset Gran Area StatusTierra GrossInterest 000ʹs acres

ColombiaSantana 35% 1.1 ProducingGuayuyaco 35% 52.4 ProducingChaza 50% 80.2 ProducingTalora 20% 108.3 ExplorationRio Magdalena 100% 144.7 ExplorationMecaya 15% 74.1 ExplorationAzar 40% 51.6 ExplorationPutumayo West A 100% 570.0 ExplorationPutumayo West B 100% 109.0 ExplorationSub‐total 1,191.4

ArgentinaPalmar Largo 14% 341.5 ProducingEl Vinalar 50% 248.3 ProducingChivil 100% 62.5 ProducingIpaguazu 100% 43.2 Non‐producingNacatimbay 100% 36.6 Non‐producingValle Morado 93% 49.9 Non‐producingSurubi 100% 90.7 ExplorationSanta Victoria 100% 1,033.6 ExplorationSub‐total 1,906.3

PeruBlock 122 100% 1,217.7 ExplorationBlock 128 100% 2,218.4 ExplorationSub‐total 3,436.1TOTAL 6,533.8

Operations

Gran Tierra currently has interests in 19 E&P contracts; nine in Colombia, eight in Argentina, and two in Peru. Exhibit 9: Gran Tierra Property Breakdown Source: Company Reports, Raymond James Ltd.


Peru Exploration

ArgentinaExploration and Production

ColombiaExploration and Production

Exhibit 10: Gran Tierra Operations Source: Company Reports, Raymond James Ltd.

Colombia

Colombia, the only South American country with both a Pacific and a Caribbean coastline, is bordered by Venezuela to the northeast, Brazil to the southeast, Ecuador and Peru to the south, and Panama to the northwest. With almost 45 million people, it is one of the most populous countries in South America. Colombia has substantial oil reserves and is a major producer of gold, silver, emeralds, platinum and coal. Its 2007 GDP (PPP) was approximately US$ 320.4 billion (US$ 7,200 per capita). The Colombian economy has experienced positive growth over the past five years, with a 6.5% GDP real growth rate in 2007. A 40‐year conflict between the government and insurgent and paramilitary groups fueled by drug‐related crime remains one of the country’s major problems, impacting parts of the country’s hydrocarbon producing basins. Some of the ongoing issues also include high unemployment and funding new exploration to offset the country’s declining oil production. Colombia’s president, Alvaro Uribe, elected in 2002, is in his second term in the office. He is credited for reducing the activities of anti‐government armed groups.


Exhibit 11: Colombian Basins

Source: ANH Gran Tierra’s Colombian blocks lie in the Putumayo and Magdalena Basins. The Magdalena Basin, comprised of the Lower, Middle and Upper Magdalena Basins, runs along the Andean mountain range (Cordillera Occidental, Cordillera Central, and Cordillera Oriental), extending from the Caribbean Sea in the north, to the Ecuadorian border in the south. The basin was formed during the Cretaceous to Oligocene (Tertiary) times. Stacked Paleogene sands (Paleocene, Eocene, Oligocene, and Miocene), such as the Lisama, Esmeraldas‐La Paz, Cienaga de Oro, and Colorado‐Mugrosa formations represent the main hydrocarbon‐bearing reservoirs of the basin.


These reservoirs have good porosity (15‐20%) and permeability (20‐600 millidarcies). Cretaceous age shales (Umir and La Luna formations) , as well as Miocene shales (Lower Porquero formation), are the most likely hydrocarbon source rock, or kitchen, for this petroleum province. As for trap, the basin’s association with the Las Monas Fault (NE‐SW compressional wrenched thrust) has created several anticlines, including the La Cira/Infantas field (close to one billion barrels of oil produced to date). The basin also contains stratigraphic traps. Magdalena oil is of good quality, between 30° to 52° API, and very low sulfur content. The Caguán ‐ Putumayo Basin runs from the Ecuadorian/Peruvian border in the south, to the Eastern Cordillera foothills in the north. Similar to the other Colombian Basins, the Putumayo was formed during the Cretaceous to Oligocene (Tertiary) times. Primary reservoir is the Caballos formation (Cretaceous), with average to good porosity (10‐16%) and low permeability (50 millidarcies). The Cretaceous Villeta shales provide excellent seal across the basin, while traps tend to be structural in nature, including fault‐related folds, and anticlines. Putumayo oil is light to medium (30° API). Exhibit 12: Colombia Properties Source: Company Reports


Gran Tierra’s current Colombian portfolio consists of a 50% interest in the Chaza block (subject to up to a 10% Net Profits Interest overriding royalty) , a 35% interest in the Santana and Guayuyaco blocks (subject to a 2% overriding royalty, and a 2.5% conditional overriding royalty), a 40% interest in the Azar block (subject to up to a 10% Net Profits Interest overriding royalty), a 15% interest in the Mecaya (subject to up to a 10% Net Profits Interest overriding royalty), a 100% interest in the Putumayo A and B technical evaluation areas (TEA), a 100% interest in the Rio Magdalena block (subject to a 30% government back‐in right), and a 20% interest in the Talora block. Exhibit 13: Putumayo



Chaza

Located in the Putumayo Basin, the Chaza block was awarded under an ANH contract, with the exploration phase due to expire in 2011, and the production phase lasting until 2032. Gran Tierra has a 50% working interest, as well as operatorship of the 80,242 acres block, with Solana Resources (SOR:TSX, OUTPERFORM) holding the other 50% interest. Following the successful Costayaco 1 exploration well in 2Q07, the partners drilled and tested two additional appraisal wells on the field (Costayaco 2 and Costayaco 3). Having flow tested up to 5,906 bopd from separate formations; the Costayaco‐1 well is currently producing 3,500 bopd (gross). The Costayaco 2 well tested in excess of 6,000 bopd from several formations, while Costayaco 3 flowed at up to 2,543 bopd. The company is in the process of preparing Costayaco 2 for long term production and testing. Note that field production remains constrained by oil trucking capacity limitation. Specifically, production is currently trucked to a production battery at Uchupayaco, with road conditions limiting trucking to 3,500 bopd. To debottleneck this, the partners are in the process of building a 25,000 bopd pipeline from Costayaco to Uchupayaco to replace trucking operations. While this line is scheduled for completion by 3Q08, production from the field will remain constrained by the Santana‐Orito pipeline capacity allocation for Costayaco, limited to 6,000 bopd (gross) downstream of Uchupayaco. To address this, the partners are currently investigating the twinning of the Santana‐Orito line. We currently expect a final decision regarding capacity to be reached following determination of the actual field size, potentially by the end of 2008. This would allow a possible in service date for the line by the end of 2009. In the short term, there exists the possibility to truck 3,000 to 4,000 bopd of production from Santana to Orito, potentially increasing production from the field to 10,000 bopd (gross) in 2H08. For our reserves blowdown assumption, we currently model production from the block at 4,750 bopd (gross) for 2008, including potential production from Costayaco 2 later this year. In the longer term, and excluding potential production from the ongoing Costayaco 4, and the planned Costayaco 5, 6 and 7 wells, we currently model 9,500 bopd for 2009, with production reducing at 15% per annum thereafter.


Exhibit 14: Putumayo Infrastructure

Source: Solana Resources The company’s reservoir engineering firm, Gaffney, Cline & Associates (CGA), estimates the field’s 2P reserves at 9 million barrels of oil net to Gran Tierra’s working interest (post government royalty, excluding third party overriding royalty), mainly based on results from Costayaco‐1. DeGolyer and MacNaughton, the third party reservoir engineering firm used by Solana (SOR‐TSXV, OUTPERFORM), currently estimates 9.3 million barrels of oil for a 50% working interest on the field (net of government royalty), in line with the CGA estimates. As with all geological data, reservoir modeling, we believe, will always be a mix of pure science, and some art. As such, given that neither numbers account for the Costayaco 2 and Costayaco 3 test results, we believe using the higher reserves of 9.3 million barrels of oil in our calculations can easily be supported. Specifically, based on our analysis of the Costayaco 2


and Costayaco 3 test results, mainly confirming the oil/water contact in the lower Caballos formation we currently estimate potential additions of 15 to 30 million barrels (gross) to the field in the next engineering reserve reports. In addition, no evidence of an oil/water contact has yet been identified in the shallower T Sandstone zone. To date, the only certainty is that the oil/water contact in this shallower zone is further out than the Costayaco 1, 2 and 3 radius. As such, while unable to estimate ultimate potential reserves from this zone, we expect them to be significantly higher than reported at year end 2007, with ultimate size depending on the location of the oil/water contact. Exhibit 15: Costayaco Field

Source: Solana Resources


In addition to the ongoing Costayaco 4, the partners currently plan on drilling Costayaco 5, 6 and 7 later this year.

Santana and Guayuyaco

Located in the Putumayo Basin, the Santana and Guayuyaco blocks fall under older Ecopetrol contracts. The 1,119 areas Santana block has production from four fields (Linda, Mary, Miraflor and Toroyaco), with a production contract due to expire in 2015, at which time the area will revert to Ecopetrol. We currently view the block at the mature/decline stage. We currently model production at 350 bopd (net) from the block, declining by 10% per annum. We don’t anticipate the company to dedicate development capex to this field, although we do factor in regular maintenance capex in our NAV calculations. The 52,366 acres Guayuyaco block is currently covered by an Ecopetrol production contract, expiring in 2027. Gran Tierra currently has a 35% interest, along with operatorship, in the block. The block currently contains two oil discoveries, the Guayuyaco and the Juanambu fields. The Guayuyaco field, discovered in 2005, currently has two wells on production while the Juanambu field, discovered in 2007, is producing from one well. We currently are forecasting 550 bopd (net) from the block in 2008 production to the company’s interest. Note that the partners are planning on drilling at least one additional producer on Juanambu in 2008. The Juanambu field is connected, via a spur line to the adjacent Toroyaco facility, from where crude is exported via existing infrastructure. In the longer term, the partners could drill two prospects currently identified on the block, mainly the Verdeyaco and the Floresta.

Exploration

In addition to the above producing assets, Gran Tierra currently has an interest in six Colombian exploratory stage blocks. In the Putumayo Basin, the company has 100% interest in the Putumayo A and B, TEAs, a 40% interest in the Azar block, and a 15% interest in the Mecaya block. In the Magdalena basin, Gran Tierra currently has a 100% interest (subject to a 60% farmout and 30% Ecopetrol back in) in the Rio Magdalena block, as well as a 20% interest in the Talora block.


Putumayo A and B TEAs were awarded to Gran Tierra in July 2007. The Putumayo A TEA includes a commitment to 400 Km of seismic reprocessing on the 570,000 acres block, and expires in August 2008. Under the agreement, the company has the preferential right to apply for an ANH exploration and exploitation contract on the area. The Putumayo B TEA includes a commitment for 100 Km of seismic reprocessing on the 109,000 acres block. The company is in negotiations with ANH to convert this TEA into an Exploration and Exploitation contract. Given the company’s farm‐out history in Colombia, we would not be surprised were Gran Tierra to farm out a portion of one, or both, of these blocks in the event of a successful conversion into an AHN contract. Azar – Gran Tierra currently has a 40% interest, and operatorship, of the Azar block in the Putumayo Basin. The company farmed into 80% of the 51,639 acres Azar block in 2006. Subsequently, 50% of its interest was farmed out to a third party. The exploration phase on this contract expires in 2012, although the partners have the right to sign a 24 year exploitation contract on any commercial discoveries. The block contains the Palmera‐1 discovery well, previously declared non‐commercial. The partners have budgeted for re‐entry of this well in 2Q08, in addition to one new exploration well in 4Q08. Note that 40 km2 of 3D seismic was recently acquired on the block. Mecaya – Gran Tierra currently has a 15% interest, as well as operatorship, in the Mecaya block in Colombia’s Putumayo Basin. The block covers 74,128 acres, and contains a legacy oil discovery, mainly the Mecaya‐1 well (flow tested 665 bopd in 1989). The company is in the process of divesting its interest in this block to a third party oil & gas company. Rio Magdalena – The company currently has a 100% interest in the 144,670 acres Rio Magdalena block. This block, governed by an Ecopetrol contract, has a non commercial oil discovery (Popa‐1, 60 bopd). The company recently entered into a farm‐in agreement on the block, where it intends to farm out 60% of the block. The Farm‐in partner has agreed to fund 100% of the last commitment exploration well on the block. In addition, Ecopetrol has the right to back into 30% of the license, potentially reducing Gran Tierra’s interest to 28%. Note that the production license on this block expires in 2030. Talora – The 108,334 acres Talora block is covered by an ANH exploration and exploitation contract, with the production phase due to expire in 2028. While the company currently has a 20% interest in the block, it has indicated its intent to apply to the government to have this interest assigned to a third party.


Argentina

Argentina, the second largest country in South America, borders Bolivia and Paraguay to the north, Brazil and Uruguay to the northeast, the Atlantic Ocean to the east and Chile to the west. The country was dominated by internal political conflicts and tensions between civilian and military groups until the mid‐1950s. Following the Peronist authoritarian rule after World War II and the military takeover in 1976, the country became a democracy in 1983. Argentina faced a severe economic crisis in 2001 culminating with the largest in history default on its foreign debt. Currency devaluation also followed the end of peso’s 1‐to‐1 peg to the US dollar. The economy is recovering since 2002 with approximately 9% average annual GDP growth, although high inflation remains a concern. Price freezes on electricity and natural gas rates have also led to restrictions on industrial use and blackouts in 2007. Argentina had a population of almost 40 million people in 2007. Its GDP (PPP) for the same year was US$ 523.7 billion (US$ 13,000 per capita). Exhibit 16: Argentina Properties Source: Company Reports


Gran Tierra’s current Argentinean portfolio consists of a 100% interest in the Surubi, Santa Victoria, Valle Morado, Ipaguazu, Ñacatimbay and Chivil blocks, a 50% interest in the Vinalar block, and a 14% interest in the Palmar Largo block. Given the currently onerous fiscal terms, mainly a withholding tax regime currently limiting realized oil sale prices to US$38 per barrel in Argentina, we do not expect the company to spend extensive near term capex in developing these assets. Exhibit 17: Surubi Block Potential Source: Company Reports

Vinalar, Chivil and Palmar Largo

Gran Tierra currently has three production stage blocks in Argentina’s Noroeste Basin. For 2008, the company has budgeted for 14 oil well workovers. For 1Q08, the Palmar Largo, Chivil, and Vinalar blocks produced 476 bopd of light oil (39 to 42 API), net to Gran Tierra. Note that this production was partially constrained due to poor road conditions in the region. For 2008, we currently model 545 bopd from Argentina net the company. Gaffney, Cline, and associates, Gran Tierra’s third party reservoir engineering firm, estimated the blocks to contain 3.1 million barrels of oil in 2P reserves (net) at the end of 2007.


Exploraton and development

In addition to the above producing assets, Gran Tierra currently has an interest in five exploration and development stage blocks in the Noroeste Basin. Gran Tierra intends on drilling the Proa‐1 prospect on the Surubi block by year end. Based on the structure’s close proximity to the Palmar Largo field, along with pronounced seismic amplitude anomalies, we consider this as a medium geological risk exploration well. For 2008, the company is also investigating the possibility of re‐establishing the gas production from the Valle Morado block. Gran Tierra is also budgeting for technical evaluations, along with potential prospect generation, on the Santa Victoria block.

Peru

Peru is bordered by Ecuador and Colombia to the north, Brazil and Bolivia to the east, Chile to the south and Pacific Ocean to the west. Its population of approximately 28 million people has seen the political system alternate between democracy and military dictatorship in the past. Although the country returned to a democratic leadership in 1980, it remains economically and politically divided. Between 2002 and 2006 the Peruvian economy grew by more than 4% per year, with a stable exchange rate and low inflation. With a 2007 GDP (PPP) of US$ 217.5 billion (US$ 7,600 per capita) and the GDP growth rate of 7.5%, underemployment and poverty remain high despite strong macroeconomic performance. With a small, elite group controlling most of the wealth and political power, almost 45% of the population lives below the poverty line. Exhibit 18: Marañon Basin Source: Perupetro


Gran Tierra’s Peru blocks lie in the frontier region of the Marañon Basin. The basin is located in Peru’s northeast, part of a larger 37 million acres regional basin extending from Peru to Colombia and Ecuador (Putumayo – Oriente – Marañon Basin). The basin was formed over a period of time ranging from the Late Permian/Early Triassic to the Tertiary (Eocene). While historical geological work shows approximately one billion barrels of Estimated Ultimate Recoverable (EUR) oil in the basin, recent joint studies by the governments of Canada and Peru indicate that “significant reserves may remain in [unexplored] parts of the basin.” Specifically, following a two year study earlier this decade, the basin was divided into two distinct regions (east and west), with a major “hinge” zone separating the two. The billion barrels of EUR identified to date are mainly located in the western region, while the new exploration activity, including Gran Tierra’s two blocks is focused on the eastern region. Cretaceous age formations (Chonta and Raya), as well as Triassic/Jurassic Pucará formations, are the most likely hydrocarbon source rock, or kitchen, for this petroleum province. Upper Cretaceous sands, such as Vivian, Chonta and Agua Caliente Formations, represent the main hydrocarbon‐bearing reservoirs of the basin, while Cretaceous shales provide most of the basin’s seals.


Exhibit 19: Marañon Basin Stratigraphy Source: Oil and Gas Journal


In addition, the basin contains structures too small to account for the amount of trapped oil, as well as well‐developed dry paleostructures. Given these findings, inconsistent with the historical geological basinal theories, the Peruvo‐Canadian study investigated other oil migration/trapping mechanisms in the basin, leading to a possibility that oil could have re‐migrated from older (breached or tilted) structures in the west to younger fields (structural or stratigraphic traps) in the eastern basin during Tertiary (Miocene) to the Quechua (Miocene to Recent) Orogeny (mountain building) tectonic events. Exhibit 20: Marañon Geological Model

Source: Company Reports From an exploration standpoint, we note the basin’s historical 42% COS is a good indicator for future prospectively.



Gran Tierra currently has a 100% Interest in blocks 122 and 128 in the Marañon Basin, covered by four exploration phases, with the last expiring in 2014. The blocks cover a combined 3.4 million acres, and are located in the eastern part of the basin, on the crest of the Iquitos Arch. Gran Tierra’s minimum work commitments include spending US$5 million per block on geo‐scientific work (aero magnetic‐gravity data, seismic, and exploratory drilling). Gran Tierra intends to carry out aero magnetic‐gravity campaigns in 2008, followed by seismic acquisition in 2009. As such, we do not anticipate any drilling on the blocks prior to 2010. Exhibit 21: Peru Blocks Source: Company Reports Given the neighbourhood of Gran Tierra’s leases, adjacent to ConocoPhillips, Occidental and Petrobras lands, we can safely state that the company continues to demonstrate its ability to “punch above its weight.” We view the ‘majors’ involvement in the basin as an indicator for potential fields in the hundred millions, or even billion, barrels range.


Exhibit 22: Balance Sheet$mln 2005 2006 2007 2008E 2009EASSETSCurrent assets Cash and cash equivalents 2.22 24.10 18.19 55.20 191.61 Restricted cash 0.40 ‐ ‐ ‐ ‐ Accounts receivable 0.81 7.38 10.69 22.88 22.88 Inventory 0.45 0.81 0.79 0.57 0.57 Taxes receivable ‐ 0.40 1.18 1.43 1.43 Prepaids 0.04 0.68 0.44 0.53 0.53 Deferred tax asset ‐ ‐ 0.22 0.99 0.99

Total Current Assets 3.92 33.37 31.51 81.60 218.01

Oil and gas properties Proved 8.31 37.76 44.29 68.01 68.01 Unproved ‐ 18.33 18.91 25.24 25.24

Total Oil and Gas Properties 8.31 56.09 63.20 93.26 93.26

Other assets ‐ 0.99 0.72 0.81 0.81

Total Property, Plant and Equipment 8.31 57.09 63.92 94.07 94.07

Long term assets Deferred tax asset 0.03 0.44 1.84 0.98 0.98 Taxes receivable 0.11 ‐ 0.53 0.53 0.53 Other long‐term assets Goodwill ‐ 15.01 15.01 15.01 15.01

Total Long Term Assets 8.45 72.54 81.29 110.58 110.58

Total Assets 12.37 105.91 112.80 192.18 328.59

LIABILITIES AND SHAREHOLDERSʹ EQUITYCurrent liabilities Accounts payable 1.14 6.73 11.33 18.02 18.02 Accrued liabilities 0.12 9.20 6.14 7.86 7.86 Derivative financial instruments ‐ ‐ 1.59 2.04 2.04 Current taxes payable ‐ 1.64 3.28 9.31 9.31 Deferred tax liability ‐ ‐ 1.11 0.74 0.74 Other ‐ 1.53 ‐ ‐ ‐

Total Current Liabilities 1.26 19.10 23.45 37.97 37.97

Long term liabilities ‐ 0.41 0.13 0.13 0.13 Deferred tax liability ‐ 7.15 9.23 15.99 16.00 Deferred remittance tax ‐ 2.72 1.33 1.48 1.48 Derivative financial instruments ‐ ‐ 1.05 1.30 1.30 Asset retirement obligation 0.07 0.33 0.80 0.90 0.90

Total Long Term Liabilities 0.07 10.62 12.55 19.80 19.81

Shareholdersʹ equity Common shares 0.04 0.10 0.10 0.11 0.11 Additional paid in capital 11.81 71.31 72.46 81.21 81.21 Warrants 1.41 12.83 20.75 17.80 17.80 Contributed Surplus ‐ 0.00 ‐ 1.48 2.49 Accumulated deficit (2.22) (8.04) (16.51) 33.82 169.20

Total Shareholdersʹ Equity 11.04 76.19 76.79 134.41 270.81

Total Liabilities and Shareholdersʹ Equity 12.37 105.91 112.80 192.18 328.59


Appendix


Exhibit 23: Income & Cash Flow Statements

$mln 2005 2006 2007 2008E 2009EREVENUE AND OTHER INCOME Petroleum sales 1.06 11.72 32.09 125.18 228.61 Interest ‐ 0.35 0.19 0.28 0.28

1.06 12.07 32.28 125.46 228.89 EXPENSES Operating 0.40 4.23 10.47 13.57 17.76 Depletion, depreciation and accretion 0.46 4.09 9.41 19.11 31.06 General and administrative 2.48 7.00 10.23 17.43 19.90 Liquidated damages ‐ 1.53 7.37 ‐ ‐ Derivative financial instruments ‐ ‐ 3.04 4.74 4.74 Foreign exchange (gain) loss (0.03) 0.37 (0.08) 0.06 0.06

3.31 17.22 40.45 54.90 73.51

GAIN BEFORE INCOME TAX (2.25) (5.15) (8.17) 70.55 155.38 Income tax (0.03) 0.68 0.29 20.22 20.00 NET GAIN (2.22) (5.82) (8.47) 50.33 135.38

Operating ActivitiesNet gain (2.22) (5.82) (8.47) 50.33 135.38 Non‐cash items Depletion, depreciation and accretion 0.46 4.09 9.41 19.11 31.06 Deferred tax (0.03) 2.54 (0.70) 7.76 8.00 Stock based compensation 0.05 0.26 0.81 1.95 2.00 Unrealized loss on financial instruments ‐ ‐ 2.65 0.69 ‐ Other Items (0.11) (1.64) 5.84 ‐ ‐

Net changes in non‐cash working capital (0.03) (0.25) (3.33) (1.49) ‐

Net cash provided by (used in) operating activities (1.88) (0.83) 6.21 78.35 176.44

Investing Activities Oil and gas property expenditures (8.71) (18.30) (13.43) (46.53) (40.00) Long term assets and liabilities ‐ ‐ (0.43) (0.03) (0.03) Other (0.40) (28.37) 1.01 ‐ ‐

Net cash used in investing activities (9.11) (46.67) (12.85) (46.56) (40.03)

Financing Activities Restricted cash ‐ (1.28) ‐ ‐ ‐ Proceeds from issuance of common stock 13.21 70.66 0.72 5.22 ‐

Net cash provided by financing activities 13.21 69.38 0.72 5.22 ‐

Net (decrease) increase in cash and cash equivalents 2.22 21.88 (5.91) 37.01 136.41 Cash and cash equivalents, beginning of period ‐ 2.22 24.10 18.19 55.20

Cash and cash equivalents, end of period 2.22 24.10 18.19 55.20 191.61



Exhibit 24: Commodity Forecasts






Source: Raymond James Ltd., Bloomberg



Fiscal Regimes

Colombian fiscal terms are divided into two contract styles. The older Ecopetrol association contracts, and the more recent ANH contracts. Under the association contracts, Ecopetrol, Colombia’s state oil company, has a back‐in right post discovery on all blocks. In addition, production is subject to up to a 20% government royalty. The newer ANH contracts eliminated the Ecopetrol back‐in right. Royalties under ANH contracts are based on a sliding scale, from 8% for production up to 5,000 bopd, up to 25% for production exceeding 600,000 bopd. In addition, a 30% windfall tax applies for fields producing in excess of 5 million barrels (total production). This tax is based on production in excess of the 5 million barrels threshold, and is referenced to WTI pricing. Under the RJ long term WTI assumption of US$130 per barrel, this equates to 24%. Income is also subject to a 33% corporate tax rate, as well as a 3.3% war tax for both contract types. Argentinean fiscal regimes include a 12% federal and a 1.5% provincial royalty on production, as well as a 35% income tax. In addition, the government recently introduced a new withholding tax, effectively limiting oil revenue at US$38 per barrel for Gran Tierra’s operations. In Peru, the company’s potential production would be subject to a 5‐20%, sliding scale royalty. Peruvian companies are also subject to a 30% income tax.


Risks

Competition

The oil & gas industry is highly competitive and the corporation competes with a substantial number of companies. There can be no assurance that such competitors will not substantially increase the resources devoted to the development and marketing of products and services that compete with those of Gran Tierra or enter markets that Gran Tierra is active in. Commodity Price Volatility

The corporation is subject to the fluctuations in oil, natural gas and other commodity energy prices. It is anticipated that the international oil & gas industry has an inherently high capital cost due to large construction projects. Nevertheless, changes in commodity prices could result in a decision by Gran Tierra to suspend or reduce operations because such operations are no longer economically viable. If production is not suspended or reduced during such period, the low differential between the price of the corporation’s end products and the cost of production could lower Gran Tierra’ revenues. Reserve and resource risks

Gran Tierra currently provides third‐party reserves evaluation on its producing assets, and calculations remain dependent on long‐term oil pricing, geological assumptions made, and the companyʹs ability to produce said reserves. Regulatory and Political

Gran Tierra’s operations are subject to a variety international laws, regulations and guidelines, including laws and regulations relating to health and safety, the conduct of operations, the protection of the environment and the manufacture, management, transportation, storage and disposal of certain materials used in operations. Changes to laws, regulations and guidelines due to environmental changes, unforeseen environmental effects, general economic conditions and other matters may cause adverse effects to operations. The companyʹs exploration, producing and potential properties are located in Colombia, Argentina and Peru. The companyʹs operations, financial results, and valuation could be adversely affected by events beyond its control taken by the current or future governments in those countries with respect to policy changes regarding taxation, regulation, and other business environment changes.



Gran Tierra is subject to various environmental laws and regulations enacted in the jurisdictions in which it operates. Including the governance of the manufacturing, processing, importation, transportation, handling and disposal of certain materials used in operations. Gran Tierra may become liable for damages against which it cannot adequately insure or against which it may elect not to insure because of high costs or other reasons. Gran Tierra may be required to increase operating expenses or capital expenditures in order to comply with any possible new restrictions or regulations. Operating Risk and Insurance

Operational risks and hazards could expose Gran Tierra to substantial liability for personal injury, loss of life, business interruption, property damage or destruction, pollution and other environmental damages. While insurance coverage is expected to address all material risks to which it is exposed and is adequate and customary in its current state of operations, such insurance is subject to coverage limits and exclusions and may not be available for the risks and hazards to which Gran Tierra is exposed. Additional Financing

In order to execute our discussed plans, the corporation may require a combination of additional debt and/or equity financing to support ongoing operations, to undertake capital expenditures or to undertake acquisitions or other business combination transactions. There can be no assurance that additional financing will be available to Gran Tierra when needed or on terms acceptable to Gran Tierra. Inability to raise financing to support ongoing operations or to fund capital expenditures or acquisitions could limit growth. Currency Exchange Rate Risk

The revenue generated from the operations of Gran Tierra may be denominated in US dollars or other international currencies so that fluctuations in the currency exchange rates may have an impact on the results of Gran Tierra.


JUNE 16, 2008






KEY FINANCIAL METRICSFY-Dec 31 2007A 2008E 2009ECFPS (C$) $0.13 $1.73 $3.53P/CFPS nm 6.2x 3.0xCFPS - 1Q nm 0.18 0.72CFPS - 2Q 0.02 0.45 0.79CFPS - 3Q 0.03 0.54 0.87CFPS - 4Q 0.09 0.56 1.15NAVPS $17.00P/NAV 63%Revenue ($mln) $84 $635 $1,167Yield (%) 0%

Commodity AssumptionsWTI (US$/bbl) $72 $113 $130HHub (US$/mmbtu) $7.12 $10.00 $7.50Exchng Rate (US$/C$) $0.94 $1.00 $1.00Production (WI)Oil (bbl/d) 9,905 20,525 28,181Nat. Gas (mmcf/d) 0 48 60Total (boe/d) 9,905 28,567 38,181

EBITDA ($mln) 41 352 886Net Debt/ CF -2.9x -0.4x -0.7x* All Figures in C$

COMPANY DESCRIPTION


STRONG BUY 117.0010.71

Pacific Rubiales is an international oil & gas company with operations in South America. The company currently has production stage blocks in Colombia, as well exploration areas in Peru.

Pacific Rubiales Energy Corp. PEG-TSX

Initiating Coverage: El Maestro Colombiano

Event

We are initiating research coverage on Pacific Rubiales Energy Corp. (Pacific Rubiales) with a STRONG BUY rating and a C$17.00 per share target price.

Action

We are recommending Pacific Rubiales as an investment in an extremely well managed, and connected, growth oriented South American independent E&P company.

Analysis

On the heels of its recent merger with Pacific Stratus, the company has transformed into Colombia’s largest independent oil and gas company. Going forward, we expect Pacific Rubiales to continue on this growth path, potentially becoming one of South America’s largest independent oil & gas firms. In addition to C$10.65 per share (fd) in reserve backed NAV, Pacific Rubiales currently offers investors exposure to over C$107 per share (fd) in potential upside. The reserve base NAV is underpinned by 208 million barrels of oil equivalent (working interest) reserves, and backed by a ‘proven’ management team, with a depth of regional technical and geopolitical experience. While the bulk of the potential upside is based on the company’s vast exploration potential in Peru, C$7 per share (Rubiales and La Creciente pipelines and extensions) only require management to deliver on project execution, and contract ‘negotiations’.

Valuation

We currently value Pacific Rubiales on the basis of a risked sum‐of‐the‐parts NAV, which includes an NPV (DCF, 10% after tax) of booked reserves, as well as a geological risk adjusted NPV (DCF, 10% after tax) of the company’s exploration portfolio. We calculate a risked sum‐of‐the‐parts NAV of C$17.00 per share on Pacific Rubiales.


Table of Contents


Stock Valuation and Recommendation ...........................................................5 Reserves Growth ............................................................................................8 Production Growth..........................................................................................9 Company Profile ...........................................................................................10 Operations ....................................................................................................13 Colombia ......................................................................................................13 Peru ..............................................................................................................30 Appendix ......................................................................................................33 Fiscal Regimes..............................................................................................35 Risks.............................................................................................................36


Pacific Rubiales (PEG: TSX)Company summary Shares & listing informationOverview:Company name Pacific Rubiales Energy Corp. Shares & capitalization:Ticker PEG Shares outstanding ‐ basic (M) 201.3Exchange TSX Shares outstanding ‐ fully diluted (M) 270.4Rating STRONG BUY Market capitalization (C$M) $2,156Current share price* C$10.71 Enterprise value 2007E ($M) $2,03412‐month target price C$17.00 Key shareholders*:Total projected return (incl. dividends payable) 59% Goodman & Company, Investment Counsel Ltd. 6.7%

Columbia Wanger Asset Management, L.P. 6.0%* as at Jun 9, 2008 Management & directors 1%

Properties Resources (Dec 31, 2007) (MM Bbl)Area Other/Details Reserves Proved Probable 2PColumbiaRubiales ‐‐> Production Total 136 72 208La Creciente ‐‐> ProductionGuama ‐‐> Production RLI (Yrs) 13.1 6.9 20.0Queifa ‐‐> ExplorationArauca ‐‐> Exploration Key Operating and Financial DataPeru ‐‐> Exploration Year end: Dec. 31 2006A 2007A 2008E 2009E

PRODUCTION (WI):Valuation Crude oil (b/d) 9,905 20,525 28,181Year end: Dec. 31 2007A 2008E 2009E Natural gas (mmcf/d) 0 48 60P/CF nm 6.2x 3.0x Total prod. (boe/d) 9,905 28,567 38,181EV/CF nm 5.8x 2.8x % Natural gas 0% 28% 26%P/E nm nm 5.8x Y/Y growth 188% 34%Target P/CF nm 9.8x 4.8xOther ParametersEV/BOED $71,214 FINANCIAL STATEMENTS:EV/BOE (2P) $9.77 Revenues ($mln) $84 $635 $1,167Raymond James NAVPS (C$/Sh) C$17.00 Operating Expenses ($mln) $33 $228 $272

Income Tax ($mln) $5 $32 $160Commodity Price Assumptions 2007 2008 2009 LT Net Income ($mln) $18 $0 $281Brent oil (US$/b) $73 $113 $130 $130 Ops Cash Flow ($ln) $44 $349 $715NYMEX gas (US$/mmbtu) $7.12 $10.00 $7.50 $7.50

CFPS ‐ basic $0.13 $1.73 $3.53Operating Net Back Estimates CFPS ‐ fd $0.13 $1.29 $2.64

2007A 2008E 2009E EPS ‐basic $0.05 $0.22 $1.83Sale price (net of royalties) $62.38 $70.32 $98.64 EPS ‐ fd $0.05 $0.16 $1.37Opex $8.90 $12.50 $10.87 Capex ($mln) $36 $305 $344Pre Tax Net Back $53.48 $57.82 $87.76 Net Debt (surplus) ($mln) ‐$126 ‐$154 ‐$525

Net debt/cash flow (2.9x) (0.4x) (0.7x)Tax $3.42 $3.50 $13.51Post Tax Net Back $50.06 $54.32 $74.25

Blowdown Production Profile (net) Management & DirectorsName PositionExecutive ManagementRonald Pantin CEO Ex PDVSA ServicesJose Francicso Arata President Ex Coalcorp Mining Inc.Carlos Perez CFO Ex Petrolago, S.A.Board representatives:Serafino Iacono Co Chairman Ex Coalcorp Mining Inc.Miguel de la Campa Co Chairman Ex Coalcorp Mining Inc.Ronald Pantin CEO Ex PDVSA ServicesJose Francicso Arata President Ex Coalcorp Mining Inc.Neil Woodyer Non‐exec Endeavour FinancialGerman Efomovich Non‐exec South American businessmanAugusto Lopez Non‐exec Ex Bavaria, S.A.Miguel Rodrigues Non‐exec Ex. Astra Fund and Incofin, Inc.Jose Efromovich Non‐exec South American businessmanJohn Zaozirny Non‐exec McCarthy Tetrault LLPAll values are in US$ unless otherwise stated.

0

10,000

20,000

30,000

40,000

50,000

60,000

2008 2009 2010 2011 2012 2013 2014 2015 2016

BOED

Exhibit 1: Pacific Rubiales Corporate Summary

Source: Company Reports, Bloomberg, Capital IQ, Raymond James Ltd.


Investment Highlights “A good decision is based on knowledge and not [just] on numbers” –Plato

Pacific Rubiales, an intermediate, mainly Colombian focused, South American oil and gas company, offers investors growing cash flow from both oil and gas fields, and a substantial exploration base, all managed by one of the most experienced and connected teams in the region. 2008E net production of 25,000 boed. We are expecting Pacific Rubiales to deliver close to 25,000 boed, on average, of net production this year. For 2009, we currently model net production in excess of 32,000 from the company’s existing blocks. In the longer term, Pacific Rubiales’ current asset base has the potential to deliver over 70,000 boed in net production by late 2010. 208 million barrels of reserves. Pacific Rubiales reserves reflect 20 years of reserve life at current production levels. We, in addition, believe that the company has the ability to; at a minimum; sustain 45,000 boed production into mid 2011. Managed by a technically proven, geopolitically savvy team. We like Pacific Rubiales’ management team. With their extensive South American oil and gas experience, combined with a solid understanding of local politics in the company’s areas of operations, we view this team as the perfect complement to the company’s asset base. Current market valuation backed by company’s reserves. Pacific Rubiales’ current market valuation reflects the company’s booked reserves under current commodity pricing. C$7 per share in low technical risk upside. In addition to the reserve backed valuation, we calculate C$7.13 per share in potential upside from a potential extension of the Rubiales contract post 2016, as well as construction of an export line on La Creciente. This additional value is based on management continuing to deliver on their project execution and ‘negotiations’ abilities. 1.8 billon barrels of exploration potential in prolific basins. Pacific Rubiales has identified in excess of 1.8 billion barrels of exploration potential it intends to target over the next few years.

25,000 net boed for 2008E

Managed by a top tier team

Valuation backed by reserves

1.8 billion barrels of exploration potential

208 million barrels of reserves


Near term catalysts. We believe the following near term catalysts could create additional value for current Pacific Rubiales shareholders:

La Creciente A‐2, B‐1 and C‐1 exploration well results (2Q, 3Q and 4Q08);

Guama exploration results in 4Q08 or 1Q09; Quifa 1 and 2 exploration results in 1H09; MN‐2 exploration results in 2H08; Arauca 1 and 2 exploration results in 1H09; Potential award of new Colombian blocks in 2008/2009; Potential approval of higher production rates on Rubiales; Completion of Rubiales export line expected for 3Q09; Decision on La Creciente export expected by end of 2008.



We have prepared an NPV (DCF, 10% after tax) summary for Pacific Rubiales’ assets. As part of our NAV calculation on the company, we also provide NPV (DCF, 10% after tax) calculations on the company’s exploration potential in Colombia and Peru. We currently assign US$50 per acre in land value for blocks without prospective resource estimates. As the company progresses in geotechnical evaluation on said blocks, our intent is to replace the land based value by a resource NAV estimate. While recent Colombian land farm‐out deals have been in excess of US$100 per acre, we have opted to use a more conservative US$50 per acre in our models.

We calculate a NAV of C$10.65 per share for Pacific Rubiales’ reserves

With an additional C$107.61 per share in potential upside


WI Reserves/Resources Unrisked NPVUnrisked NPV Risking Risked NPVRisked NPVmm Barrels US$ million Per Share US$ million Per Share

Rubiales 121 US$2,138 US$7.91 100% US$2,138 US$7.91La Creciente* 84 502 1.86 100% 502 1.86Guaduas/Mauritia Norte /Rio Ceibas/Puli 3 116 0.43 100% 116 0.43

Reserves NPV 208 2,757 9.77 2,757 10.19

Cash / (Net Debt) US$122 0.45 100% US$122 US$0.45

Reserves net asset value US$2,879 US$10.65 US$2,879 US$10.65Reserves net asset value (C$) C$2,879 C$10.65 C$2,879 C$10.65

Rubiales upside (170,000 bopd) 21 US$357 1.32 10% US$36 US$0.13Rubiales upside (contract extention) 105 1,203 4.45 10% 120 US$0.45La Creciente A + D pipeline upside* 608 367 1.36 10% 37 US$0.14La Creciente exploration upside* 80 477 1.76 10% 48 US$0.18Quifa exploration upside 89 1,581 5.85 10% 158 US$0.58Arauca exploration upside 69 1,220 4.51 10% 122 US$0.45Moriche land value** N.A 1 0.00 100% 1 US$0.00Jagüeyes land value** N.A 3 0.01 100% 3 US$0.01Peru Exploration upside 1405 23,890 88.35 5% 1,195 US$4.42

Net asset value US$31,979 US$118.26 US$4,598 US$17.00Net asset value (C$) C$31,979 C$118.26 C$4,598 C$17.00

*6:1 mcf per boe** land value, $50 per acre

Exhibit 2: Risked Contingent Net Asset Value Summary Source: Company Reports, Raymond James Ltd.

We calculate a risked sum‐of‐the‐parts NAV of C$4,598 million, or C$17.00 per share (fd) for Pacific Rubiales.


$90 $110 $130 $150 $170

5% C$17.29 C$19.11 C$20.93 C$22.74 C$24.56

10% C$14.20 C$15.60 C$17.00 C$18.40 C$19.80

12% C$13.32 C$14.59 C$15.86 C$17.12 C$18.39

15% C$12.24 C$13.34 C$14.44 C$15.54 C$16.64


Discount

rate

0

20

40

60

80

100

120

140

Reserves Rubialesupside(170,000bopd)

Rubialesupside(contractextention)

La CrecienteA + Dpipelineupside*

La Crecienteexplorationupside*

Quifaexplorationupside

Araucaexplorationupside

PeruExploration

upside

C$ per Share

Exhibit 3: NAV Sensitivity

Source: Raymond James Ltd. Given the continued volatility in commodity pricing, we are providing investors with valuation sensitivities for our risked NAV per share (fd) on Pacific Rubiales under different long term oil prices and different discount rates. Exhibit 4: Pacific Rubiales Value Creation

* 6:1 mcf per boe Source: Company Reports, Raymond James Ltd.


Reserves Growth

Pacific Rubiales continues to deliver year‐over‐year reserve growth from its expanding asset base. Going forward, in addition to potential exploration success, we anticipate the potential for an increase in booked reserves from the Rubiales and La Creciente fields in Colombia. On Rubiales, a successful contract prolongation past the current 2016 expiry date, combined with an extension of the areal field extent (based on ongoing appraisal drilling), has the potential to double Pacific Rubiales’ reserves from this field. Based on data provided by the company’s third party reservoir engineer, Petrotech, the Rubiales field is estimated to contain close to 3 billion barrels of Original Oil In Place (OOIP), 120.9 million barrels of which were booked as 2P reserves to the company’s working interest (217 million gross) at the end of 2007. Given the excellent productivity of the Rubiales reservoir (good permeability and porosity), and using other regional, and global, heavy oil fields as analogs, we estimate that this field has the potential to ultimately produce significantly more than the currently booked reserves. At this stage, assuming the successful application of western heavy oil production technology, we strongly believe that ultimate recovery rates of 20% or higher are achievable from the majority of the Rubiales field, potentially giving the field an Estimated Ultimate Recovery of close to 550 million barrels. In addition, we believe in the potential for the field’s areal extend to be larger than currently mapped. The company is in the process of drilling several delineation wells on Rubiales. Results from the latest of these wells, RB‐53 and RB‐14, indicate the potential for converting Possible reserves from parts of the field into Proven and Probable. Exhibit 5: Rubiales Field Potential Extensions Source: Company Reports


0

10,000

20,000

30,000

40,000

50,000

60,000

2008E 2009E 2010E 2011E 2012E 2013E 2014E 2015E 2016E

BOED

On La Creciente, Petrotech reports the La Creciente A field’s 2P reserves at 506 Bcf of gas. The block also contains the La Creciente D gas field, estimated to contain 52 Bcf of gas on a 2P basis. While the La Creciente A field is estimated to contain 640 Bcf of gas on a 2P basis, only 506 Bcf are “bookable” as reserves given the current export pipeline constraints. As such, development approval of a resolution to this issue (new export line) could lead to an “immediate” 20% increase in booked reserves from the field. Pacific Rubiales also has exposure to 2 billion boe of seismically identified exploration potential on its Colombian and Peruvian exploration blocks. Pacific Rubiales has also indicated its intent to bid in ongoing 2008 Colombian bid rounds, targeting heavy oil, as well as conventional blocks. While we do not include any value from potential acquisitions into our NAV calculations, we anticipate that the company will be successful in obtaining one or more new blocks this year. Specifically, the recently completed merger with Pacific Stratus has given the company the required size, and operational depth, to, in our view, successfully bid in these Colombian rounds.

Production Growth

Since entering Colombia in 2007, Pacific Rubiales’ management team has delivered significant production increases, both organically as well as via acquisitions. For 2008, we are expecting the company to produce 25,000 boed (net of royalties), more than doubling last year’s average production. For 2009, we are currently forecasting net production of 32,000 boed from the company’s existing assets. Exhibit 6: Pacific Rubiales Production Profile Source: Company Reports, Raymond James Ltd.


** Currently owned 100%, but a 65% interest will be issued to Ecopetrol


Pacific Rubiales Energy Corp.

(British Columbia)

Lenar Corp.(Panama)

Petro Rubiales Corp.

(Panama)

Major International

Oil, S.A. (Panama)

Rubiales Holdings Ltd.(Cayman Islands)

Pacific Stratus International Energy

Ltd.(British Columbia)

** Oleoducto de los Llanos Orientales

S.A.(Panama)

Pacific & Rubiales Energy Trading Corp. Panama

Oleoducto de los Llanos

Orientales S.A.(Colombian Branch)

Petro Rubiales Corp.

(Colombian Branch)

Major International Oil, S.A.(Colombian Branch)

Tethys Petroleum

Ltd.(Colombian Branch)

Meta Petroleum

Ltd.(Colombian Branch)

Quifa Petroleum

Company Ltd.(Colombian Branch)

Pacific Ventures C.A.

(Venezuela)

Pacific Stratus Energy

Colombia Ltd. Sucursal (Colombia)


Sucursal del Peru

Pacific Stratus

Energy Peru Ltd.

(Panama)


Colombia Ltd.

Solaris AVV

(Aruba)

Quifa Petroleum

Company Ltd.(Cayman Islands)

Meta Petroleum

Ltd.(Cayman Islands)

Pacific Stratus

Energy Peru Ltd.

(Panama)

OilTradingExportSales

100% 100% 100% 100%

100%

100% 100% 100% 100% 100% 100%

100%100%100%100%100%100%100%100%100%

33%

33%

34%

Off‐Shore

ColombiaVenezuelaPeru

While we currently model a production peak of 55,000 bopd (net) under our reserve blowdown scenario, we believe Pacific Rubiales is positioned to deliver close to 80,000 bopd in net production by 2011, in the event it can negotiate a production increase/extention on Rubiales, as well as construct an export pipe for La Creciente.

Company Profile

Pacific Rubiales is an intermediate international oil and gas company, currently focused on South America. The company has assets in Colombia’s Llanos, Putumayo, and Magdalena Basins, as well as in Peru’s Marañon and Ucayalí Basins. The company’s shares trade on the Toronto Stock exchange (symbol PEG). The corporate and capital structures of the company are illustrated below. We have also included a list of the company’s top ten institutional shareholders. Exhibit 7: Pacific Rubiales Corporate Structure


(M)Common Shares Outstanding 201Warrants 51Stock options 18Shares O/S ‐ fully diluted 270Market Capitalization 2156

Holders SharesGOODMAN & COMPANY, INVESTMENT COUNSEL LTD. 6.7%COLUMBIA WANGER ASSET MANAGEMENT, L.P. 6.0%OPPENHEIMERFUNDS, INC. 4.5%JPMORGAN ASSET MANAGEMENT U.K. LIMITED 2.3%TD ASSET MANAGEMENT, INC. 1.6%ACUITY INVESTMENT MANAGEMENT INC. 1.2%MFC GLOBAL INVESTMENT MANAGEMENT 1.8%U.S. GLOBAL INVESTORS, INC. 1.1%DRIEHAUS CAPITAL MANAGEMENT LLC 1.1%FIDELITY MANAGEMENT & RESEARCH COMPANY 0.6%

Exhibit 8: Market Capitalization and Top 10 Holders

Source: Capital IQ, Raymond James Ltd. Pacific Rubiales’ predecessor was initially established as a mining company. In 2007, the company entered Colombia via a series of acquisitions, including the Rubiales field, and changed its name to Petro Rubiales Energy Corp. In 2008, the company acquired; or more realistically merged with, Pacific Stratus, renaming itself Pacific Rubiales Energy Corp. Leadership Team The management team at Pacific Rubiales is unique in that all team members are South American nationals, firmly entrenched in the region’s petroleum industry. This team’s solid grasp of regional geology, extensive development experience, and understanding of local geopolitics form a required precursor to transform Pacific Rubiales into a significant Colombian, and Latin American, oil & gas player. Ronald Pantin, CEO and Director, has over 20 years of South American oil & gas experience, including as President of Petróleos de Venezuela (PDVSA) Services. He has also served as President of Enron Venezuela, as well as in various technical and managerial roles with Maraven, a PDVSAʹs affiliate.


Jose Francisco Arata, President and Director, has over 25 years of South American mineral and oil exploration experience, including the founding of Pacific Stratus, Coalcorp Mining, and Bolivar Gold Corp. Carlos Perez, CFO, has close to 30 years of oil & gas industry experience. Prior to joining Pacific Rubiales, he held various executive and senior positions with Venezuelan energy firms, including Petrolago, Venegas, and PDVSA. Mr. Perez is a Certified Public Accountant. Luis Andres Rojas, Sr. VP Production, has close to 30 years of South American oil & gas experience. Prior to joining Pacific Rubiales, he held various technical and managerial positions with PDVESA, including President of PDVESA Intevep (R&D) and VP of PDVSA. Mr. Rojas is a Petroleum Engineer. Marino Ostos, Sr. VP New Areas, has over 30 years of oil & gas experience, mainly focused on exploration in fold and thrust belts, which are commonly found in South America. In addition to founding Litos, a Venezuelan oilfield services company, Dr. Ostos was also on the board of directors of Fairfield Industries in Venezuela. Dr. Ostos is a graduate of the Central University of Venezuela (B.Sc. in Geological Engineering) and of Rice University, Texas (PhD). Jairo Lugo, Sr. VP Exploration, has 25 years of experience in the South American oil & gas industry. Dr. Lugo’s strategic expertise lies in Basin analysis, as well as prospect evaluation.


Country Asset Pacific StatusRubialesInterest

ColombiaRubiales 40.00% ProducingPiriri 50.00% ProducingGuaduas 90.60% ProducingRio Ceibas 27.27% ProducingPuli‐B 50.00% ProducingLa Creciente 100.00% ProducingJagüeyes 3433‐A 100.00% ExplorationMoriche 80.00% ExplorationGuama 100.00% ExplorationQuifa 60.00% ExplorationArauca 95.00% TEATacacho 100.00% TEA

PeruBlock 135 100.00% ExplorationBlock 137 100.00% ExplorationBlock 138 100.00% ExplorationDoima 50.00% ExplorationOrtega 50.00% Exploration

Operations

Pacific Rubiales currently has interests in 12 oil & gas blocks in Colombia, and three in Peru. The company operates all but two of its blocks, a key attribute in a ‘good’ international oil & gas player. Exhibit 9: Pacific Rubiales Operations Source: Company Reports, Raymond James Ltd.

Colombia

Colombia, the only South American country with both a Pacific and a Caribbean coastline, is bordered by Venezuela to the northeast, Brazil to the southeast, Ecuador and Peru to the south, and Panama to the northwest. With almost 45 million people, it is one of the most populous countries in South America. Colombia has substantial oil reserves and is a major producer of gold, silver, emeralds, platinum and coal. Its 2007 GDP (PPP) was approximately US$ 320.4 billion (US$ 7,200 per capita). The Colombian economy has experienced positive growth over the past five years, with a 6.5% GDP real growth rate in 2007. A 40‐year conflict between the government and


insurgent and paramilitary groups fueled by drug‐related crime remains one of the country’s major problems, impacting parts of the country’s hydrocarbon producing basins. Some of the ongoing issues also include high unemployment and funding new exploration to offset the country’s declining oil production. Colombia’s president, Alvaro Uribe, elected in 2002, is in his second term in the office. He is credited for reducing the activities of anti‐government armed groups. Exhibit 10: Colombian Basins

Source: ANH


Pacific Rubiales’ blocks lie in the Putumayo, Llanos, and Magdalena Basins. The Magdalena Basin, comprised of the Lower, Middle and Upper Magdalena Basins, runs along the Andean mountain range (cordillera occidental, cordillera central, and cordillera oriental), extending from the Caribbean sea in the north, to the Ecuadorian border in the south. The basin was formed during the Cretaceous to Oligocene (Tertiary) times. Stacked Paleogene sands (Paleocene, Eocene, Oligocene, and Miocene), such as the Lisama, Esmeraldas‐La Paz, Cienaga de Oro Formation, and Colorado‐Mugrosa formations represent the main hydrocarbon‐bearing reservoirs of the basin. These reservoirs have good porosity (15‐20%) and permeability (20‐600 millidarcies). Cretaceous age shales (Umir and La Luna formations) , as well as Miocene shales (Lower Porquero formation), are the most likely hydrocarbon source rock, or kitchen, for this petroleum province. As for trap, the basin’s association with the Las Monas Fault (NE‐SW compressional wrenched thrust) has created several anticlines, including the La Cira/Infantas field (close to one billion barrels of oil produced to date). The basin also contains stratigraphic traps. Magdalena oil is of good quality, between 30° to 52° API, and very low sulfur content. The Caguán ‐ Putumayo Basin runs from the Ecuadorian/Peruvian border in the south, to the Eastern Cordillera foothills in the north. Similar to the other Colombian Basins, the Putumayo was formed during the Cretaceous to Oligocene (Tertiary) times. Primary reservoir is the Caballos formation (Cretaceous), with average to good porosity (10‐16%) and low permeability (50 millidarcies). The Cretaceous Villeta shales provide excellent seal across the basin, while traps tend to be structural in nature, including fault‐related folds, and anticlines. Putumayo oil is light to medium (30° API). The Llanos Basin runs from the Colombian‐Venezuelan border in the northeast, to Eastern Cordillera in the southwest. The basin was formed during Triassic to Cretaceous times. The Carbonera and Mirador sandstones (Paleogene) are known to be excellent reservoirs in the basin. In addition, certain Cretaceous sands have also shown good reservoir quality in the Llanos. These reservoirs have good porosity in the east of the basin (30%), decreasing to average porosities in the west (10%). The majority of the basin’s oil is heavy (10° to 12° API), although much lighter oil is also found (42° API). Most discovered fields in the basin have been found in structural traps (Fault related), although stratigraphic traps (pinchouts, paleohighs, and channels) are considered prospective.


Exhibit 11: Pacific Rubiales Fields

Source: Company Reports Pacific Rubiales’ Colombian portfolio consists of a 40% interest in the Rubiales, a 50% interest in the Piriri and the Puli, a 90.6% interest in the Guaduas, a 27.27% interest in the Rio Ceibas, an 80% interest in the Moriche, a 60% interest in the Quifa, a 95% interest in the Arauca, a 100% in interest in the Jagues, and a 100% interest in the La Creciente, the Guama, and the Tacacho.


Rubiales With current production (gross) of over 30,000 bopd, we view the Rubiales field as the ‘backbone’ of Pacific Rubiales growth strategy. Located in Colombia’s Llanos Basin, this heavy oil field lies over two separate blocks, mainly the Rubiales and the Piriri, covering a combined 140,603 acres. The blocks are covered by an association contract, set to expire in 2016, at which time the field would revert to Ecopetrol. While the company currently has a 40% interest in the Rubiales, and a 50% interest in the Piriri, Pacific Rubiales net “take” from the field is 36%. This accounts for a 20% royalty (from gross field production) payable to Ecopetrol, as well as the field’s 55:45 production split between the Rubiales and the Piriri blocks. Petrotech, estimates the field to contain 270 million barrels in gross 2P oil reserves (121 million barrels to Pacific Rubiales’ working interest). Initially discovered in 1982, the Rubiales field was declared non‐commercial given prevailing oil prices at the time. The field was taken over by Meta Petroleum in 2002 and was producing 18,500 bopd (gross) when Petro Rubiales acquired Meta in 2007. The main producing zone in the field is the Carbonera formation, a Lower Tertiary Sandstone, containing heavy oil (12.5° API) at depths of 730 to 900 metres. Given the field’s very active bottom aquifer drive, well productivity can range as high as 10,000 barrels of fluid per day, although the bottom water does lead to high water cuts; exceeding 80% for some mature wells. Similar to Canada’s oil sands, we describe this field as a “water plant, with oil as the byproduct.” For 2008, given the local pipeline infrastructure limitation, we model gross production from the field at 38,500 bopd. Field production is currently constrained by two limiting factors, the unavailability of an export pipeline, and limited water handling capacity at the Central Processing Facility (CPF). Pacific Rubiales currently trucks its production to its owned and operated plant at Guaduas. Production is then blended, using light oil or Naphtha into Rubiales blend for export.


Exhibit 12: Rubiales Export Route

Source: Company Reports The company expects, by 3Q08, to start building an export pipeline to Cusiana, with an estimated in service date of 3Q09. This pipeline would tie into existing infrastructure (OCENSA pipeline that transports oil to the Covenas export terminal), allowing the company to export all of its Rubiales production. The OCENSA pipeline currently has over 250,000 bbl/d of spare capacity. As part of this project, the company expects to build a diluent blending facility at Rubiales, where purchased diluent (Naphtha) will be blended with the Rubiales crude into Rubiales blend.


This proposed pipeline is a 65:35 JV between Ecopetrol and Pacific Rubiales. Estimated to cost up to US$450 million, this 230 KM pipeline will have an initial capacity of 160,000 bopd, although this could be expanded to 260,000 bopd via additional pumping stations. We expect the pipeline to reduce transportation costs significantly from close to US$20 per barrel currently. The company expects to fund 75% of the pipeline costs from debt, and its share of the balance from working capital. In addition, while not included in any of our above valuations, we believe this pipeline, when completed, could give the company some leverage in negotiating an extension to the Rubiales contract, an interest in other regional heavy oil blocks, or both. We currently model Rubiales blend (18.5° API) pricing at an 18% discount to WTI on the global market. Note that the company is currently selling all of its crude production on the open market. As Rubiales production ramps up, the company’s export capacity will be limited to 18,000 bopd net (50,000 gross) of Rubiales crude between 3Q08, until completion of the Rubiales export line. The balance could be sold locally as bunker fuel or equivalent. We model local sales of Rubiales heavy oil at a 45% discount to WTI. For 2009, we currently forecast production of 55,000 bopd from the field. In the longer term, we currently model peak production of 126,000 bopd (gross) from the field in 2010, declining until contract expiry in 2016. Note that our assumptions are based on blowing down the company’s current reserves from the field.


0

20,000

40,000

60,000

80,000

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140,000

160,000

180,000

2008E 2009E 2010E 2011E 2012E 2013E 2014E 2015E 2016E

BOED

Rubiales base case Rubiales upside case

Exhibit 13: Rubiales Production Profile

Source: Company Reports, Raymond James Ltd. Although current plans and approvals are for 126,000 bopd plateau production, up to 170,000 bopd (gross) could potentially be achieved from the field as of 2011. While this is management’s preferred scenario, this remains subject to negotiations with Ecopetrol. Note that both cases would include developing the field using well clusters, including four horizontal and one vertical well per “pad.” The company would, for both scenarios, have to increase both oil and water handling capacities on the field. Given the limited contract length (2016 expiry), the company is in the process of securing a third, in addition to two currently under contract, drilling rig for the proposed development plan. While the Colombian rig market remains tight, we believe that management’s strong regional relationships will allow them to secure a third drilling rig.


Phase Completion Added Water Cummulative Added Oil Cummulative Added CummulativeDate Capacity Water Capacity Capacity Oil Capacity Total Cost Total Cost

(KBWPD) (KBWPD) (KBOPD) (KBOPD) (M$ US) (M$ US)1 May‐08 200 340 8 40 110.0 110.02 Oct‐08 100 440 10 50 44.7 154.73 Jan‐09 100 540 10 60 44.7 199.34 Oct‐09 800 1,340 70 130 219.7 419.0

Exhibit 14: Rubiales Development Plan

Source: Company Reports, Raymond James Ltd. In addition to facilities and pipeline expansion, the Rubiales master plan calls for drilling up to 348 wells to increase production to 170,000 bopd (300 wells in case of 126,000 bopd production). All in, inclusive of pipeline costs, the Rubiales cost requirement is estimated at US$ 1.5 billion until contract expiry in 2016.

La Creciente

Pacific Rubiales currently has a 100% interest in the La Creciente block. The 68,094 acres block, located in the Magdalena Basin, was awarded to the company, by ANH, in 2004. The exploration phase of the agreement runs for 65 months, while the production phase is for 24+10 years. Following award, the first exploration well, LCA‐1, drilled in 2006, discovered the La Creciente A field. Three additional appraisal wells (LCA‐2, LCA‐3 and LCA‐4) were drilled on this structure. Current production from the block, at 40 mmcf/d, is limited by export infrastructure availability on the Guapaje–Corozal regional pipeline. For 2008, we currently model average production of 47.5 mmcf/d from the block. Specifically, we expect production to reach 60 mmcf/d by 3Q, and remain flat thereafter.


0

20

40

60

80

100

120

140

160

2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

Mmcf/d

La Creciente base case La Creciente upside

Exhibit 15: La Creciente Production Forecast

Source: Company Reports, Raymond James Ltd. In the longer term, and pending full evaluation of the 2008 appraisal, and exploration, activities on the block, we believe production from the La Creciente discoveries could be ramped up to at least 150 to 200 mmcf/d. Based on published information on the La Creciente wells drilled to date, we calculate the potential for close to 150 mmcf/d of production from current wells. Additional gas discoveries on the block could further increase our estimated production plateau. While the company has initiated front end work on a potential 35 Km gas export pipeline to the Caribbean, final details remain pending the company’s 2008 exploration, appraisal and testing program on the block. Given that the company has initiated front end work on this pipe, we would not be surprised by a potential in service date as early as 3Q09. Gas sales in Colombia are semi‐regulated. As such, while the company is able to sell its La Creciente gas at a premium to market, this is still substantially lower than global prices. Pacific Rubiales currently sells 35 mmcf/d at US$4.95 per mmbtu (versus the regulated price of US$3.99 per mmbtu), although this sales contract expires at the end of July 2008. Based on our evaluation of the local gas market, we expect that the company could sell any additional gas for a minimum of US$4.30 per mmbtu under the current environment. In the event of gas export, the company believes gas could replace fuel oil or diesel in regional power generation. Note that these fuels are currently selling, on the


global market, at US$85 per barrel for fuel oil (equating to US$14 per mmcf) and US$145 per barrel of diesel (equating to US$24 per mmcf). We do, however, anticipate that the company will continue domestic sales of some form, potentially as high as current levels into the future. While this might not make perfect sense from a purely financial standpoint, we believe it would help maintain the excellent geo‐social and geopolitical relationships the company’s management currently enjoys in Colombia. This in turn, in our view, would definitely be value adding for Pacific Rubiales shareholders in the longer term.

Guaduas

Pacific Rubiales has a 90.6% interest in the Guaduas block, located in the Magdalena Basin. This 30,665 acres block contains the Guaduas field, discovered in 1996. The field, at year end 2007, was estimated to contain 3.05 million barrels of oil in 2P reserves. The field currently produces from highly fractured Cretaceous Limestone (Cimarrona Formation). While this leads to productive wells, it also adds a layer of complexity to reservoir modeling and field development. Going forward, we currently model production of 1,100 bopd from the field for 2008. Following the completion of the two development wells scheduled for 2009, we expect production to increase to 1,500 bopd. The 18.5° API crude produced from the field is currently exported, along with the Rubiales crude currently blended at the Guaduas facilities. Following the expected completion of the Rubiales pipeline in 2009, the Guaduas production facility will have close to 20,000 bopd of excess processing capacity, which could potentially be leased out, to a third party crude producer. Based on historical regional averages, we anticipate that the company could charge a US$2 to US$2.50 per barrel processing fee for the use of this facility. While we do not, pending official confirmation of such contracts, model any potential revenues from such operations (post 3Q09), this potential revenue would equate to an additional US$14 million per year.


Mauritia Norte /Rio Ceibas/Puli Pacific Rubiales, respectively, has an 80%, a 27.27%, and a 50% interest in the Mauritia Norte, Rio Ceibas and Puli fields. The first lies in the Llanos Basin, while the later two are located in the Magdalena Basin. At the end of 2007, the fields were estimated to contain reserves of, net to Pacific Rubiales, 1.1 million barrels of oil. For 2008, we model production of 2,200 bopd from these fields. In the longer term, we anticipate the potential for one to two years of plateau production at current rates, followed by 10 to 15% annual production declines thereafter.

Exploration

In addition to the above producing assets, Pacific Rubiales currently has an interest in several Colombian and Peruvian exploratory stage blocks. In Colombia, it has an 80% interest in the Moriche, a 100% interest in the Jagueyes, a 60% interest in the Quifa a 100% interest in the La Creciente, and a 100% interest in the Guama blocks. The company also has a 100% interest in the Arauca and Tacacho Technical Evaluation Areas (TEA). La Creciente. In addition to the La Creciente A and D gas discoveries, Pacific Rubiales has identified seven exploration prospects at the La Creciente block. These structures are mainly faulted blocks, defined on seismic (2D, 3D or both), and estimated to contain a potential total of 800 Bcf of recoverable gas on an un‐risked basis. On a risked basis, this equates to 271 Bcf of gas. While the average COS for the block is 27%, we do note the company’s recent exploration success rate on the block of 66% (two discoveries on three exploration wells). As such, a repeat of recent performances in future La Creciente exploration could increase Pacific Rubiales total booked gas reserves by 500 Bcf. We do, however, note, given the current pipeline limitation on the block, that any future discoveries would be deemed non‐commercial, thus non bookable as reserves, pending completion of a larger export system.


Recoverable Chance of RiskedGas Resources Success Gas Resources

Prospects (Bcf) (Bcf)B 160 35% 56C 125 45% 56.25F 180 28% 50.4G 101 40% 40.4H 47.5 24% 11.4I 83 29% 24.07J 103 22% 22.66

Total 799.5 261.18

Exhibit 16: La Creciente Exploration Prospects Source: Company Reports, Raymond James Ltd. For 2008, in addition to the La Creciente A‐2 and E‐1 wells drilled earlier this year, the company plans to drill three additional exploration wells on the block by year end. Specifically, LCB‐1, LCG‐1, and LCC‐1 in 3Q08. Exhibit 17: La Creciente

7



Quifa – The 377,419 acres Quifa TEA lies in Colombia’s Llanos Basin, surrounding the Rubiales field. Following the company’s last two exploration wells, Quifa‐3 and Quifa‐4, which did not encounter any commercially viable hydrocarbon accumulations, the company re‐interpreted existing 2D seismic on the block, in addition to acquiring 200 Km of new 2D lines. Based on this information, two prospects and three leads were identified, with the prospects mapped as containing a potential resource up to 149 million barrels of recoverable oil net to the company’s interest on the block. With an exploration well costing approximately US$1.1 million, we view this block as a low cost, high impact exploration play. We therefore expect to see one, or both of these structures drilled by 2009. Exhibit 18: Prospects in the Quifa Block Source: Company Reports


Moriche – Pacific Rubiales has an 80% interest in the 30,797 acres Moriche block, located in Colombia’s Llanos Basin. In addition to the Mauritia Norte field, discovered in early 2007, Pacific Rubiales has identified five additional prospects on the block, based on the initial interpretation of recent 3D seismic data. As with most Llanos structures, these prospects appear to be faulted blocks, of relatively small areal extent. While Petrotech expects to release prospective resource estimates on the block by the end of July 2008, we do not anticipate large resources to be mapped. Based on regional geology, as well as available data, we do not expect total oil potential from these structures to exceed 5 million barrels each of recoverable oil. Pacific Rubiales plans on drilling two exploration wells on this block later this year. Exhibit 19: Moriche Block Prospects



Guama – Pacific Rubiales has a 100% interest in the 216,130 acres Guama block, located in Colombia’s Magdalena Basin. Located next to the company’s La Creciente block, we view the Guama block as prospective, mainly as it contains the legacy Ligia‐1 discovery, which tested gas, and light oil, during a short test almost two decades ago. The block also lies on trend with several regional oil & gas fields. Following the acquisition of 255 Km of new 2D seismic, and the reprocessing of 300 Km of legacy 2D data; which fulfilled exploration commitments on the block until October 2008; Pacific Rubiales has identified four exploration prospects on the block. We currently expect the company to drill two exploration wells on the block in 2008 (2Q08 and 3Q08), fulfilling the commitments for the second exploration phase on this contract. Petrotech, the company’s third part reservoir engineering firm expects to release prospective resource estimates on the block by the end of July 2008. Exhibit 20: Guama Block Prospects



Arauca – Pacific Rubiales has a 100% interest, subject to a 5% overriding royalty on production to Free Traders Group, in the 726,470 acres Arauca TEA, located in Colombia’s Llanos Basin, on the border with Venezuela. Given its location, adjacent to one of Colombia’s largest oil fields (Caño Limón), and neighbouring Venezuela’s Guafita and Victoria fields we consider this block as highly prospective. As an aside, the Caño Limón field, discovered in 1983, has been reported to contain close to 1.5 billion barrels of recoverable oil, with individual wells flowing as high as 20,000 bopd. Awarded in March 2007, the first exploration phase on the TEA runs until September 2008. To date, the company has reprocessed 2,000 Km of 2D seismic on the block, fulfilling part of its minimum phase one exploration commitments. Based on this work, the company has mapped eight exploration prospects. Petrotech currently estimates that these structures could contain a total of 112 million barrels of prospective resources on an un‐risked basis (gross).

Exhibit 21: Arauca Prospectivity

COSProspect Type P90 P50 P10 Mean

MMbbl MMbbl MMbbl MMbblT‐A Antithetic Faulted Block 5.5 12.1 25.7 14.4 33.6%Pz‐A Paleozoic Inverted Structure 4.6 29.8 170.7 68.4 9.7%Pz‐B Paleozoic Inverted Structure 2.3 15.4 86.2 34.6 2.5%Pz‐C Paleozoic Inverted Structure 0.8 4.9 25.6 10.4 9.7%Pz‐D Paleozoic Inverted Structure 0.7 4.1 22.4 9.1 9.7%Pz‐E Paleozoic Inverted Structure 0.3 2.1 12.1 4.8 9.7%Pz‐F Paleozoic Inverted Structure 1.4 11.1 72.8 28.4 9.7%Pz‐G Paleozoic Inverted Structure 5.0 32 179 72.0 9.7%

Total 20.6 111.5 594.5 242.2

Unrisked Undiscovered Oil Resources


Pacific Rubiales currently plans on drilling two exploratory wells, at a cost of US$3 to US$4 million each, on this block in 4Q08. We expect that at least one of these will target the shallower tertiary structure, given that the bulk of the Caño Limón oil is contained in the Tertiary Mirador formation. Given the proximity of the Caño Limón‐Covenas export pipeline to the block, we anticipate that potential discoveries on Arauca could easily be booked as reserves. While the block is very prospective, its location, along the border with Venezuela, adds a layer of security risks to the company’s operation. Although we don’t expect this to preclude the company from continuing to engage in exploration, and potentially production, operations, militant activities could delay said operations. We also note that the Caño Limón to Covenas export pipeline, which could potentially be used to export discoveries from the Arauca block, has been breached numerous times.


Tacacho – In January 2008, Pacific Rubiales was awarded a 100% interest in the 1,480,060 acres Tacacho TEA, located in Colombia’s Putumayo Basin, on the border with Ecuador. The block lies approximately 100 Km from several oil and gas fields in the Putumayo, as well as on trend with Ecuadorian oil fields. The company is currently committed to the acquisition of 100 Km of new 2D seismic, along with the reprocessing of 640 Km of legacy 2D data, and a 4,400 km aero‐magneto‐gravimetric survey. Petrotech expects to release prospective resource estimates on the block by the end of July 2008. While the block is very prospective, its location, along the border for Ecuador, adds a layer of security risks to the company’s operations. Although we don’t expect this to preclude the company from continuing to engage in exploration, and potentially production, operations, militant activities could delay said operations. Jagüeyes – In February 2008, Pacific Rubiales was awarded a 100% interest in the 53,128 acres Jagüeyes TEA, located in Colombia’s Llanos basin. The block is surrounded by oil and gas discoveries. The company is currently committed to the acquisition of 112 km2 of new 3D seismic for the first 8 month exploration phase. In the event Pacific Rubiales opts to extend the exploration phase on this block (10+12+12 months options), commitments are for one exploratory well to be drilled per exploration phase, at an estimated cost of US$5 million per well. Petrotech expects to release prospective resource estimates on the block by the end of July 2008

Pipelines

In addition to the above production and exploration stage blocks, Pacific Rubiales has a 100% interest in the Guaduas‐La Dorada pipeline (“OGD”) and minority interests in two trunk oil pipelines, Oleoducto de Colombia (“ODC”) and Oleoducto Alto Magdalena (“OAM”).

Peru

Peru is bordered by Ecuador and Colombia to the north, Brazil and Bolivia to the east, Chile to the south and Pacific Ocean to the west. Its population of approximately 28 million people has seen the political system alternate between democracy and military dictatorship in the past. Although the country returned to a democratic leadership in 1980, it remains economically and politically divided. Between 2002 and 2006 the Peruvian economy grew by more than 4% per year, with a stable exchange rate and low inflation. With a 2007 GDP (PPP) of US$ 217.5 billion (US$ 7,600 per capita) and the GDP growth rate of 7.5%, underemployment and poverty remain high despite strong macroeconomic performance. With a small elite controlling most of wealth and political power, almost 45% of the population lives below the poverty line.


Exhibit 22: Marañon Basin Source: Perupetro Pacific Rubiales’ Peru blocks lie in the frontier region of the Marañon and Ucauali basins. The basins are located in Peru’s northeast, part of a larger 37 million acres regional basin extending from Peru to Colombia and Ecuador (Putumayo – Oriente ‐‐ Marañon basin). They were formed over a period of time ranging from the Late Permian/Early Triassic to the Tertiary (Eocene). While historical geological work shows approximately one billion barrels of Estimated Ultimate Recoverable (EUR) oil in the Marañon basin, recent joint studies by the governments of Canada and Peru indicate that “significant reserves may remain in unexplored parts of the basin.” Specifically, following a two year study earlier this decade, this basin was divided into two distinct regions (east and west), with a major “hinge” zone separating the two. The billion barrels of EUR identified to date are mainly located in the western region, while the new exploration activity, including Pacific Rubiales’ blocks is focused on the eastern region. Cretaceous age formations (Chonta and Raya), as well as Triassic/Jurassic Pucará formations, are the most likely hydrocarbon source rock, or kitchen, for this petroleum province. Upper Cretaceous sands, such as Vivian, Chonta and Agua Caliente Formations, represent the main hydrocarbon‐bearing reservoirs of the basin, while Cretaceous shales provide most of the basin’s seals.


In addition, the basin contains structures too small to account for the amount of trapped oil, as well as well‐developed dry paleostructures. Given these findings, inconsistent with the historical geological basinal theories, the Peruvo‐Canadian study investigated other oil migration/trapping mechanisms in the basin, leading to the possibility that oil could have re‐migrated from older (breached or tilted) structures in the west to younger fields (structural or stratigraphic traps) in the eastern basin during Tertiary (Miocene) to the Quechua (Miocene to Recent) Orogeny (mountain building) tectonic events. From an exploration standpoint, we note the basin’s historical 42% COS is a good indicator for future prospectivity.


Pacific Rubiales currently has a 100% interest in blocks 135 and 137 in the Marañon Basin, and block 138 in the Ucayali Basin. The blocks are covered by four exploration phases, and the option to convert oil discoveries into 30 years agreements (40 years for gas). The blocks cover a combined 4.7 million acres, and are estimated to contain a potential 1,405 million barrels of prospective oil resources (mean basis). Pacific Rubiales’ minimum work commitments on block 135 include aeromagnetic and gravimetric surveys, remote (satellite) sensing, as well as interpretation of legacy data. In the event the company opts to enter into a second phase on the block, work commitments would include 400 km of new 2D seismic and the drilling of an exploratory well. Phases three and four would require one exploratory well each. On block 137, phase one commitments include a report on the remote sensing and 200 km of new 2D seismic. Each of phases two, three and four would require the company to commit to drilling one exploratory well per phase. For block 138, the compilation of a technical report of all the existing data covers commitments for Phase one. Phase two would include 300 km of new 2D seismic, while each of Phases three and four would require the drilling of one exploratory well per phase.


$mln 2007 2008E 2009EASSETSCurrent assetsCash and cash equivalents 141 154 524Accounts receivable 24 58 58Inventories 2 19 19Prepaid expenses 6 5 5Future Income tax 0 8 8Other 0 0 0

173 244 614

Property, plant and equipment 611 1,695 1,775Restricted cash 0 14 14Investments and other assets 0 11 11Other 6 0 0

617 1,720 1,800790 1,964 2,414

LIABILITIES AND SHAREHOLDERSʹ EQUITYCurrentAccounts payable and accrued liabilities 24 74 74Current portion of long‐term debt 15 1 0Other 0 0 0

39 76 75

Long‐term debt 8 7 7Future income tax 167 425 0Asset retirement obligation 1 11 11Minority interest 0 0 0Other 0 0 0

176 442 17

Shareholdersʹ equityShare capital 453 1,118 1,118Contributed surplus 107 186 186Accumulated other comprehensive income 0 0 0Retained earnings 14 87 683Other 0 54 335

575 1,446 2,322790 1,964 2,414

Appendix

Exhibit 23: Balance Sheet Source: Company Reports, Raymond James Ltd.


Exhibit 24: Income and Cash Flow Statements

$mln 2007 2008E 2009EREVENUETotal net revenue (net of royalities) 84 635 1,167

EXPENSESOperating 33 228 272Depletion, depreciation and accretion 19 150 264General and administrative 4 27 27Share‐based compensation 5 33 2Interest 2 3 14Foreign exchange (gain)/loss (8) 168 168Interest Income 0 (5) (20)Other Income 1 (1) (1)Total expenses 56 604 727

Income before provision for income taxesProvision for income taxes Current 5 32 160 Future 0 0 0Non‐controlling interest 5 0 0Net income 18 0 281

Cash Flow Statement

CASH FLOWS FROM (USED IN) OPERATING ACTIVITIESItems not requiring outly of cash:Net Income 18 0 281Depletion, depreciation and accretion 19 150 264Asset retirement obligation accretion 0 0 0Stock based compensation 5 33 2Future Income tax recovery ‐4 ‐1 0Foreign exchange loss 0 168 168Other Items 6 0 0

44 349 715

Changes in non‐cash working capital ‐17 ‐38 0

27 311 715

CASH FLOWS USED IN INVESTING ACTIVITIESExpenditures on property, plant and equipment ‐36 ‐305 ‐344Pacific Stratus acquisition ‐ cash acquired less acquisition cost ‐244 19 0Purchase of investments 0 ‐2 0Other ‐5 0 0

‐285 ‐287 ‐344

CASH FLOWS FROM FINANCING ACTIVITIESRepayment of debt ‐19 ‐16 ‐1Proceeds from exercise of warrants and options 1 6 0Proceeds from issuance of debt 23 0 0Due to related parties 0 0 0Issuance of shares for cash 394 0 0Subscriptions received in advance 0 0 0Other 0 0 0

399 ‐10 ‐1

Net increase in cash and cash equivalents 141 14 370Cash and cash equivalents, beginning o f period 0 141 154Cash and cash equivalents, end of period 141 154 524Source: Company Reports, Raymond James Ltd.









Fiscal Regimes

Colombian fiscal terms are divided into two contract styles. The older Ecopetrol association contracts, and the more recent ANH contracts. Under the association contracts, Ecopetrol, Colombia’s state oil company, has a back‐in right post discovery on all blocks. In addition, production is subject to up to a 20% government royalty. The newer ANH contracts eliminated the Ecopetrol back‐in right. Royalties under ANH contracts are based on a sliding scale, from 8% for production up to 5,000 bopd, up to 25% for production exceeding 600,000 bopd. In addition, a 30% windfall tax applies for fields producing in excess of 5 million barrels (total production). This tax is based on production in excess of the 5 million barrels threshold, and is referenced to WTI pricing. Under the RJ long term WTI assumption of US$130 per barrel, this equates to 24%. Income is also subject to a 33% corporate tax rate, as well as a 3.3% war tax for both contract types. In Peru, the company’s potential production would be subject to a 5‐20%, sliding scale royalty. Peruvian companies are also subject to a 30% income tax. Exhibit 25: Commodity Forecasts Source: Bloomberg, Raymond James Ltd.


Risks

Competition

The oil & gas industry is highly competitive and the corporation competes with a substantial number of companies. There can be no assurance that such competitors will not substantially increase the resources devoted to the development and marketing of products and services that compete with those of Pacific Rubiales or enter markets that Pacific Rubiales is active in. Commodity Price Volatility

The corporation is subject to the fluctuations in oil, natural gas and other commodity energy prices. It is anticipated that the international oil & gas industry has an inherently high capital cost due to large construction projects. Nevertheless, changes in commodity prices could result in a decision by Pacific Rubiales to suspend or reduce operations because such operations are no longer economically viable. If production is not suspended or reduced during such period, the low differential between the price of the corporation’s end products and the cost of production could lower Pacific Rubiales’ revenues. Reserve and resource risks

Pacific Rubiales currently provides third‐party reserves evaluation on its producing assets, and calculations remain dependent on long‐term oil pricing, geological assumptions made, and the companyʹs ability to produce said reserves. Regulatory and Political

Pacific Rubiales’s operations are subject to a variety international laws, regulations and guidelines, including laws and regulations relating to health and safety, the conduct of operations, the protection of the environment and the manufacture, management, transportation, storage and disposal of certain materials used in operations. Changes to laws, regulations and guidelines due to environmental changes, unforeseen environmental effects, general economic conditions and other matters may cause adverse effects to operations. The companyʹs exploration, producing and potential properties are located in Colombia, and Peru. The companyʹs operations, financial results, and valuation could be adversely affected by events beyond its control taken by the current or future governments in those countries with respect to policy changes regarding taxation, regulation, and other business environment changes.



Pacific Rubiales is subject to various environmental laws and regulations enacted in the jurisdictions in which it operates. Including the governance of the manufacturing, processing, importation, transportation, handling and disposal of certain materials used in operations. Pacific Rubiales may become liable for damages against which it cannot adequately insure or against which it may elect not to insure because of high costs or other reasons. Pacific Rubiales may be required to increase operating expenses or capital expenditures in order to comply with any possible new restrictions or regulations. Operating Risk and Insurance

Operational risks and hazards could expose Pacific Rubiales to substantial liability for personal injury, loss of life, business interruption, property damage or destruction, pollution and other environmental damages. While insurance coverage is expected to address all material risks to which it is exposed and is adequate and customary in its current state of operations, such insurance is subject to coverage limits and exclusions and may not be available for the risks and hazards to which Pacific Rubiales is exposed. Additional Financing

In order to execute our discussed plans, the corporation may require a combination of additional debt and/or equity financing to support ongoing operations, to undertake capital expenditures or to undertake acquisitions or other business combination transactions. There can be no assurance that additional financing will be available to Pacific Rubiales when needed or on terms acceptable to Pacific Rubiales. Inability to raise financing to support ongoing operations or to fund capital expenditures or acquisitions could limit growth. Currency Exchange Rate Risk

The revenue generated from the operations of Pacific Rubiales may be denominated in US dollars or other international currencies so that fluctuations in the currency exchange rates may have an impact on the results of Pacific Rubiales.


JUNE 16, 2008






KEY FINANCIAL METRICSFY-Dec 31 2007A 2008E 2009ECFPS (C$) $0.10 $0.72 $1.52P/CFPS nm 6.2x 2.9xCFPS - 1Q 0.00 0.10 0.37CFPS - 2Q -0.01 0.13 0.38CFPS - 3Q 0.01 0.22 0.39CFPS - 4Q 0.10 0.27 0.39NAVPS $5.48P/NAV 81%Revenue ($mln) $19 $111 $218Yield (%) 0%

Commodity AssumptionsWTI (US$/bbl) $72 $113 $130HHub (US$/mmbtu) $7.12 $10.00 $7.50Exchng Rate (US$/C$) $0.94 $1.00 $1.00ProductionOil (bbl/d) 3,112 5,639Nat. Gas (mmcf/d) 0 1Total (boe/d) 3,182 5,773

EBITDA ($mln) 2 96 203Net Debt/ CF -7.0x -1.0x -1.3x

COMPANY DESCRIPTION


OUTPERFORM 25.504.42

Solana is an international oil & gas company with operations in Colombia.

Solana Resources Ltd. SOR-TSXV

Initiating Coverage: An Undervalued Colombian Turnaround Story

Event

We are initiating research coverage on Solana Resources Ltd. (Solana) with an OUTPERFORM rating and a C$5.50 per share target price.

Action

In addition to an investment in an undervalued Colombian turnaround story, we are recommending the company to investors who want exposure to the growth oriented Costayaco field in Colombia, without owning the Argentinean and Peruvian assets of the field’s operator.

Analysis

Having established an impressive Colombian land position, Solana’s board, in October 2006, engaged a new management team to focus on reserves, and production, growth. By focusing on transforming land into reserves, and reserves into production, this team has been able to deliver tangible value add in under 18 months. Specifically, for 2007, year‐over‐year production grew by 40%, while year‐over‐year reserves increased threefold. In the longer term, we believe Solana’s three pronged strategy will yield continued shareholder value growth. We expect the company’s low risk development of existing fields and discoveries to provide growing cash flow from operations. Medium risk exploration in Colombia’s Llanos Basin provides the potential for sustainable growth. Solana also offers investors access to high impact exploration in the Catatumbo Basin. In addition, management’s track record indicates the possibility of an “exit via sale” strategy for the company, potentially at a premium to market valuations.

Valuation

We currently value Solana on the basis of a risked sum‐of‐the‐parts NAV, which includes an NPV (DCF, 10% after tax) of booked reserves. We also provide investors with our estimate of geological risk adjusted NPV (DCF, 10% after tax) of the company’s exploration portfolio. We calculate a risked‐sum‐of‐the‐parts NAV of C$5.48 per share for Solana. On an un‐risked basis, we calculate a NAV of C$16.48 for the company’s reserves, potential resources, and land.


Table of Contents


Stock Valuation and Recommendation ...........................................................5 Reserves Growth ............................................................................................7 Production Growth..........................................................................................8 Company Profile .............................................................................................9 Operations ....................................................................................................11 Colombia ......................................................................................................11 Appendix ......................................................................................................21 Fiscal Regimes..............................................................................................23 Risks.............................................................................................................24


Exhibit 1: Solana Corporate Summary

Solana Resources (SOR: V)Company summary Shares & listing informationOverview:Company name Solana Resources Limited Shares & capitalization:Ticker SOR Shares outstanding ‐ basic (M) 123Exchange TSX Venture Shares outstanding ‐ fully diluted (M) 128Rating OUTPERFORM Market capitalization (C$M) $544Current share price* C$4.42 Enterprise value 2007E ($M) $47212‐month target price C$5.50 Key shareholders*:Total projected return (incl. dividends payable) 24% Touradji Capital Management, L.P. 8.4%

Acuity Investment Management Inc. 1.6%* as at Jun 9, 2008 Management & Directors 5.6%

Properties Resources (Dec 31, 2007) (MM Bbl)Area Other/Details Reserves Proved Probable 2PColombiaChaza ‐‐> Production Colombia 7 6 14Guayuyaco ‐‐> ProductionMagangue ‐‐> Production Total 7 6 14Guachiria ‐‐> Production

RLI (Yrs) 6.3 5.5 11.9ValuationYear end: Dec. 31 2006A 2007A 2008E 2009E Key Operating and Financial DataP/CF nm nm 6.2x 2.9x Year end: Dec. 31 2006A 2007A 2008E 2009EEV/CF nm nm 9.8x 2.5xP/E nm nm 11.4x 5.0x PRODUCTION (WI):Target P/CF nm nm 7.7x 3.6x Crude Oil (b/d) 3,112 5,639Other Parameters Natural gas (mcf/d) 419 805EV/BOED $148,376 Total prod. (boe/d) 3,182 5,773EV/BOE (2P) $33.16 % Natural gas 2% 2%Raymond James NAVPS C$5.48 Y/Y growth 81%Commodity Price Assumptions 2007 2008 2009 LTBrent oil (US$/b) $73 $113 $130 $130 FINANCIAL STATEMENTS:NYMEX gas (US$/mmbtu) $7.12 $10.00 $7.50 $7.50 Revenues ($mln) $11 $19 $111 $218

Operating Expenses ($mln) $3 $4 $9 $13

Operating Net Back Estimates Income Tax ($mln) ‐$5 $0 $6 $82008E 2009E Net Income ($mln) ‐$28 ‐$9 $48 $110

Sale price (net of royalties) $101.23 $110.41 Ops Cash Flow ($mln) $6 $10 $88 $187Opex $8.11 $6.74Pre Tax Net Back $93.12 $103.68

CFPS ‐ basic $0.07 $0.10 $0.72 $1.52Tax $22.22 $32.38 CFPS ‐ fd $0.06 $0.09 $0.69 $1.47Post Tax Net Back $70.90 $71.29 EPS ‐basic ‐$0.34 ‐$0.09 $0.39 $0.89

EPS ‐ fd ‐$0.29 ‐$0.08 $0.38 $0.86Reserve Blowdown Production Profile Capex ($mln) $25.53 $33.29 $92.26 $50.00

Net Debt (surplus) ($MM) ($37) ($71) ($85) ($243)Net debt/cash flow (6.5x) (7.0x) (1.0x) (1.3x)

Management & DirectorsName PositionExecutive ManagementScott Price President & CEO Ex Breakaway Energy Inc.Glenn Van Doorne COO Ex Breakaway Energy Inc.Ricardo Montes CFO Ex ShellBoard representatives:Ray Antony Non‐exec Chairman Ex Breakside Energy Ltd.Stan Grad Co Chairman Soderglen Ranches Ltd.Grant Howard Non‐exec The Howard Group Inc.Roy Hudson Non‐exec Davis & Company LLPKeith Jackson Non‐exec Ex Anglo American plcJoaquin Moreno‐Uribe Non‐exec Ex. Shell VenezuelaScott Price President & CEO Ex Breakaway Energy Inc.


0

1,000

2,000

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4,000

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2008E 2010E 2012E 2014E 2016E 2018E 2020E

BOPD

Source: Company Reports, Raymond James Ltd., Capital IQ


Investment Highlights “Price is what you pay. Value is what you get” – Warren Buffett

Tenfold reserve increase over two years. At year end 2007, Solana booked 11 million barrels of 2P oil reserves (15 million barrels 3P), up from 1 million barrels at the end of 2005. Note that the 2007 year end reserves do not include the successful results from the Costayaco 2 and Costayaco 3 appraisal wells. Based on our analysis of these results, we currently estimate the potential for an additional 15 to 30 million barrels (gross) on the Costayaco field in 2P reserves, potentially doubling the company’s current reserves. Targeting significant production increase in 2008/2009. Having grown production to 869 boed in 2007 (average, net), a 40% increase over 2006, we anticipate continued production growth from the company in 2008 and 2009. We currently model 2008E net production of 3,182 boed, while for 2009; we anticipate average production of 5,773 boed. A turnaround story. We view the company as an investment in a turnaround story that is in the process of getting upwards reevaluated by markets. Having joined the company in October 2006, the management team continues to demonstrate success. As such, while we believe that Solana is still undervalued by capital markets, this ‘discount’ has contracted with each new success delivered by this team. A history of value creation. The company’s management team has a proven history of oil & gas value creation. Specifically, both the CEO and COO were involved, at the senior executive level, in building junior international oil & gas companies from the “ground up”, following which these companies were acquired, at a significant premium to market valuations. While we do not exclude the potential for a “history repeats itself” scenario; i.e. a potential acquisition of the company at a significant premium; we like Solana on the basis of the inherent value of the company’s assets and its management team’s expertise. Near term catalysts. We believe the following near term catalysts could create additional value for current Solana shareholders:

Costayaco field reserves update in 2H08; Exploration drilling in the Catguas block in 3Q08; Exploration drilling in Guachiría Norte by 1Q09; Results from the Guachiría Sur Palmitas‐2 well in 2Q or 3Q08;


Tenfold reserve increase in two years

History of creating value

Year over year production growth


Solana WI Reserves/Resources Unrisked NPV Unrisked NPV Risking Risked NPV Risked NPVInterest mm Barrels US$ million Per share US$ million Per share

Chaza 50% 10 $378 $2.96 100% $378 $2.96Guayuyaco 35% 1 $42 $0.33 100% $42 $0.33Magangué* 38% 0 $14 $0.11 100% $14 $0.11Guachiría 70% 1 $27 $0.21 100% $27 $0.21Reserve based NAV 12 $461 $3.61 100% $461 $3.61

Cash (Net debt) $72 $0.57 100% $72 $0.57

Reserves net asset value $533 $4.18 $533 $4.18Reserves net asset value (C$) $533 $4.18 $533 $4.18

Chaza upside 50% 15 $561 $4.39 10% $56 $0.44Guachiría Sur/Norte Upside 70% 4 $102 $0.79 10% $10 $0.08Catguas A&B Upside 85%/50% 29 $827 $6.47 10% $83 $0.65Garibay Upside 50% 3 $73 $0.57 10% $7 $0.06Colonia Upside** 100% N.A $5 $0.04 100% $5 $0.04San Pablo Upside** 100% N.A $5 $0.04 100% $5 $0.04Exploration upside 49.5 1,572 $12.31 $167 $1.31

Net asset value US$2,106 US$16.48 US$700 US$5.48Net asset value (C$) C$2,106 C$16.48 C$700 C$5.48


We have prepared an NPV (DCF, 10% after tax) summary for Solana’s assets in Colombia, based on blowing down the company’s booked reserves. As part of our NAV calculation on Solana, we also provide NPV (DCF, 10% after tax) calculations on the company’s exploration potential of 50 million barrels of oil, as well as land value for the company’s Colonia and San Pablo blocks. We currently assign US$50 per acre in land value for blocks without prospective resource estimates. As the company progresses in geotechnical evaluation on said blocks, our intent is to replace the land based value by a resource NAV estimate. While recent Colombian land farm‐out deals have been in excess of US$100 per acre, we have opted to use a more conservative US$50 per acre in our models.

Exhibit 2: Risked Contingent Net Asset Value Summary * 6:1 mcf:boe conversion ** $50 per acre land value Source: Company Reports, Raymond James Ltd. Given the continued volatility in commodity pricing, we are providing investors with valuation sensitivities for our risked NAV per share (fd) on Solana under different long term oil prices and different discount rates.

We calculate a core NAV of C$4.18 per share for Solana’s reserves


0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

Reserves Chazaupside

GuachiríaSur/NorteUpside

CatguasA&B

Upside

GaribayUpside

Colonialand

San Pabloland

US$ per Share

Exhibit 3: NAV Sensitivity

$90 $110 $130 $150 $170

5% C$5.39 C$5.97 C$6.55 C$7.12 C$7.70

10% C$4.64 C$5.06 C$5.48 C$5.90 C$6.32

12% C$4.42 C$4.79 C$5.17 C$5.54 C$5.92

15% C$4.14 C$4.46 C$4.78 C$5.10 C$5.42


Discoun

t rate

Source: Raymond James Ltd. We calculate a risked NAV of C$700 million, or C$5.48 per share (fd) for the company. Exhibit 4: Solana Value Creation Source: Company Reports, Raymond James Ltd.


Reserves Growth

The company exited 2007 with 10 million barrels of oil in net 2P reserves, a tenfold increase over 2005. Exhibit 5: Solana Net Reserves Growth

0

2

4

6

8

10

12

14

16

2005 2006 2007

MMBO

E

Proved Probable Possible

Source: Company Reports, Raymond James Ltd. For 2008, in addition to potential exploration success, we currently anticipate an increase in booked reserves from the Costayaco field in Colombia. Specifically, we estimate that the incorporation of results from the two recent successful appraisal wells on the field could potentially add 15 to 30 million barrels in gross oil reserves. Going forward, Solana has the potential to continue growing reserves through exploration activities. For 2008, the company has budgeted to drill five firm, as well as three contingent, exploration wells, with the potential to add an additional 5 to 10 million barrels in oil reserves to the company.


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Production Growth

Since joining the company in October 2006, Solana’s management has delivered significant organic production increases. Exhibit 6: Solana Production Profile

Source: Company Reports, Raymond James Ltd. While our reserve blowdown scenario has production declining post 2010, we believe Solana is positioned, assuming our above scenario on the Costayaco reserves is confirmed, to deliver in excess of 10,000 boed production by 2011.


(M)Common Shares Outstanding 123Stock options 5Shares O/S ‐ fully diluted 128Market Capitalization 544

Holders SharesTOURADJI CAPITAL MANAGEMENT, L.P. 8.4%PRICE, J. SCOTT* 3.1%GRAD, STANWILL GEORGE PETER** 2.1%ACUITY INVESTMENT MANAGEMENT INC. 1.6%CRESTSTREET ASSET MANAGEMENT LIMITED 1.0%AEGON CAPITAL MANAGEMENT, INC. 0.4%ANTONY, RAY*** 0.3%SPROTT ASSET MANAGEMENT INC. 0.2%BLUMONT CAPITAL CORPORATION 0.2%AGF MANAGEMENT LTD. 0.1%

Company Profile

Solana is a junior international oil and gas company, currently focused on Colombia. The company’s shares trade on the Toronto Venture stock exchange (symbol SOR), as well as the Alternative Investment Market of the London stock exchange (symbol SORL). The corporate and capital structures of the company are illustrated below. Exhibit 7: Solana Corporate Structure

Solana Petroleum Expolaration (Colombia) Limited(Cayman Islands)

Solana Resources Limited(Alberta)

Bayford Investments Ltd.(Barbados)

100% 100%

Source: Company Reports, Raymond James Ltd. Exhibit 8: Market Capitalization and Top 10 Holders

Notes: * Chief Executive Officer, ** Former Director, *** Chairman Source: Capital IQ, Raymond James Ltd.


Leadership Team

The company’s management team has a proven history of oil & gas value creation. Specifically, both the CEO and COO were involved, at the senior executive level, in building junior international oil & gas companies from the “ground up.” In addition, each of the company’s key technical team members has several decades of international oil & gas exposure, which we believe will be critical in continuing to deliver production and exploration success. Scott Price, President, CEO, and Director, came to Solana via the acquisition of Breakaway Energy. In addition to a proven technical track record in international oil & gas operations, his role as CEO of Aventura equipped him with the skills required to develop a successful international oil & gas company. Specifically, under Mr. Price’s watch, Aventura grew from a $12 million market cap to close to $200 million, following which it was acquired by British Gas (BG‐LSE, not rated) for $228 million. He has over 20 years of international oil and gas experience. Mr. Price is a graduate of the University of Calgary (B.Sc. in Chemical Engineering, MBA). He is a registered engineer in the province of Alberta. Glenn Van Doorne, VP Operations, joined Solana in October 2006, via the acquisition of Breakaway. He brings over 30 years of international oil and gas experience, including a stint with the International Energy Agency (IEA). He was also VP, Exploration and Production for Hurricane Hydrocarbons (PetroKazakhstan), increasing that company’s production (50 bopd to 70,000 bopd), and reserves (one million barrels to 400 million barrels). Note that PetroKazakhstan was sold to CNPC in 2005 for $4.18 billion. In addition, Mr. Van Doorne was the founder of IbrizOil, a Kazakh oil company later sold to Big Sky Energy. Mr. Van Doorne is a graduate of the Belgium (B.Sc. and M.Sc. in Geological and Mineralogical Sciences). Ricardo Montes, CFO, joined the company from Shell in July 2006, where he was a Financial and Accounting Manager. Prior to that, Mr. Montes was VP Finance for Shell in Venezuela. He has close to 25 years of international oil & gas experience. Mr. Montes is a graduate of Universidad de la Sabana in Colombia (MBA).


Country Asset Solana Operator Area StatusInterest Gross

km2

ColombiaMagangue 37.8% SOR 84.0 ProducingCatguas 100% SOR 1,591.0 ExplorationGuachiria Norte 100% SOR 412.0 ExplorationColonia 100% SOR 439.0 ExplorationSan Pablo 100% SOR 423.0 ExplorationGuachiria 100% SOR 68.0 ExplorationGuachiria Sur 100% SOR 366.0 ExplorationGaribay 100% SOR 307.0 ExplorationGuayuyaco 35% GTE 212.0 ProducingChaza 50% GTE 325.0 ProducingTotal 4,227.0

Operations

Solana currently has interests in 10 oil & gas blocks in Colombia, seven of which it operates. Exhibit 9: Solana Property Breakdown Source: Company Reports, Raymond James Ltd.

Colombia

Colombia, the only South American country with both a Pacific and a Caribbean coastline, is bordered by Venezuela to the northeast, Brazil to the southeast, Ecuador and Peru to the south, and Panama to the northwest. With almost 45 million people, it is one of the most populous countries in South America. Colombia has substantial oil reserves and is a major producer of gold, silver, emeralds, platinum and coal. Its 2007 GDP (PPP) was approximately US$ 320.4 billion (US$ 7,200 per capita). The Colombian economy has experienced positive growth over the past five years, with a 6.5% GDP real growth rate in 2007. A 40‐year conflict between the government and insurgent and paramilitary groups fueled by drug‐related crime remains one of the country’s major problems, impacting parts of the country’s hydrocarbon producing basins. Some of the ongoing issues also include high unemployment and funding new exploration to offset the country’s declining oil production. Colombia’s president, Alvaro Uribe, elected in 2002, is in his second term in the office. He is credited for reducing the activities of anti‐government armed groups.


Exhibit 10: Colombia Hydrocarbon Basins

Source: ANH Solana’s blocks lie in the Putumayo, Llanos, Catatumbo and Magdalena Basins.


The Magdalena Basin, comprised of the Lower, Middle and Upper Magdalena Basins, runs along the Andean mountain range (Cordillera Occidental, Cordillera Central, and Cordillera Oriental), extending from the Caribbean Sea in the north, to the Ecuadorian border in the south. The basin was formed during the Cretaceous to Oligocene (Tertiary) times. Stacked Paleogene sands (Paleocene, Eocene, Oligocene, and Miocene), such as the Lisama, Esmeraldas‐La Paz, Cienaga de Oro, and Colorado‐Mugrosa formations represent the main hydrocarbon‐bearing reservoirs of the basin. These reservoirs have good porosity (15‐20%) and permeability (20‐600 millidarcies). Cretaceous age shales (Umir and La Luna formations), as well as Miocene shales (Lower Porquero formation), are the most likely hydrocarbon source rock, or kitchen, for this petroleum province. As for trap, the basin’s association with the Las Monas Fault (NE‐SW compressional wrenched thrust) has created several anticlines, including the La Cira/Infantas field (close to one billion barrels of oil produced to date). The basin also contains stratigraphic traps. Magdalena oil is of good quality, between 30° to 52° API, and very low sulfur content. The Caguán ‐ Putumayo Basin runs from the Ecuadorian/Peruvian border in the south, to the Eastern Cordillera foothills in the north. Similar to the other Colombian Basins, the Putumayo was formed during the Cretaceous to Oligocene (Tertiary) times. Primary reservoir is the Caballos formation (Cretaceous), with average to good porosity (10‐16%) and low permeability (50 millidarcies). The Cretaceous Villeta shales provide excellent seal across the basin, while traps tend to be structural in nature, including fault‐related folds, and anticlines. Putumayo oil is light to medium (30° API). The Llanos Basin runs from the Colombian‐Venezuelan border in the northeast, to Eastern Cordillera in the southwest. The Carbonera and Mirador sandstones (Paleogene) are known to be excellent reservoirs in the basin. In addition, certain Cretaceous sands have also shown good reservoir quality in the Llanos. These reservoirs have good porosity in the east of the basin (30%), decreasing to average porosities in the west (10%). The majority of the basin’s oil is heavy (10° to 12° API), although much lighter oil is also found (42° API). Most discovered fields in the basin have been found in structural traps (fault related), although stratigraphic traps (pinchouts, paleohighs, and channels) are considered prospective. The Catatumbo Basin forms the southwest flank of Venezuela’s prolific Maracaibo Basin. The basin was formed during the Cretaceous and Tertiary periods times. The La Luna formation is considered the major source rock in the basin. Cretaceous limestone and sandstone (Uribante Group, Capacho and La Luna formations), as well as Paleogene sandstone (Catatumbo, Barco, Mirador and Carbonera formations) form the basin’s main reservoirs.


Fractured basement rocks are also considered to be potential reservoirs. Most discovered fields in the basin have been found in structural traps. Note that the Catatumbo Basin is considered one of Colombia’s most prolific basins. Exhibit 11: Operations Map

Source: Company Reports Solana’s portfolio consists of a 50% interest in the Chaza, a 35% interest in the Guayuyaco, a 70% interest in the Guachiría, Guachiría Norte, and Guachiría Sur, a 50% interest in the Garibay, a 100% interest in the Colonia and San Pablo, a 37.8% in the Magangué, an 85% interest in Area A of Catguas, and a 50% interest in area B of the Catguas.


Chaza

Located in the Putumayo Basin, the Chaza block was awarded under an ANH contract, with the exploration phase due to expire in 2011, and the production phase lasting until 2032. Solana has a 50%, non operated, working interest, of the 80,242 acres block, with Gran Tierra (GTE‐TSX, MARKET PERFORM) holding operatorship and the other 50% interest. Following the successful Costayaco 1 exploration well in 2Q07, the partners drilled and tested two additional appraisal wells on the field (Costayaco 2 and Costayaco 3). Having flow tested up to 5,906 bopd from separate formations; the Costayaco 1 well is currently producing 3,500 bopd (gross), due to local infrastructure limitations. The Costayaco 2 well tested in excess of 6,000 bopd from several formations, while Costayaco 3 flowed at up to 2,543 bopd. The partners are in the process of preparing Costayaco 2 for long term production and testing. Note that field production remains constrained by oil trucking capacity limitation. Specifically, production is currently trucked to a production battery at Uchupayaco, with road conditions limiting trucking to 3,500 bopd. To debottleneck this, the partners are in the process of building a 25,000 bopd (upgradable) pipeline from Costayaco to Uchupayaco to replace trucking operations. While this line is scheduled for completion during 2H08, production from the field will remain constrained by the Santana‐Orito pipeline capacity allocation for Costayaco, limited to 6,000 bopd (gross) downstream of Uchupayaco. To address this, the partners are currently investigating the twinning of the Santana‐Orito line. We currently expect a final decision regarding capacity to be reached following determination of the actual field size, potentially by the end of 2008. This would allow a possible in service date for the line by the end of 2009. In the short term, there exists the possibility to truck 3,000 to 4,000 bopd of production from Santana to Orito, potentially increasing production from the field to 10,000 bopd (gross) in 2H08. For our reserves blow down assumption, we currently model production from the block at 4,750 bopd (gross) for 2008, including potential production from Costayaco 2 later this year. In the longer term, and excluding potential production from the ongoing Costayaco 4, and the planned Costayaco 5, 6 and 7 wells, we currently model 9,500 bopd for 2009, with production reducing at 15% per annum thereafter.


Exhibit 12: Putumayo Infrastructure

Source: Company Reports The company’s reservoir engineering firm, Degolyer and MacNaughton, estimates the field’s 2P reserves at 9.3 million barrels of oil net to Solana’s working interest (post royalty), mainly based on results from Costayaco 1. Gaffney, Cline & Associates, the third party reservoir engineering firm used by Gran Tierra, currently estimate a more conservative 9 million barrels of oil for a 50% working interest on the field (net of government royalty). As with all geological data, reservoir modeling, we believe, will always be a mix of pure science, and some art. As such, given that neither numbers account for the Costayaco 2 and Costayaco 3 test results, we believe using the higher reserves in our calculations can easily be supported. Specifically, based on our analysis of the Costayaco 2 and Costayaco 3 test results, mainly confirming the


oil/water contact in the lower Caballos formation we currently estimate potential additions of 15 to 30 million barrels (gross) to the field in the next engineering reserve reports. Note that no evidence of an oil/water contact has yet been identified in the shallower T Sandstone zone. To date, the only certainty is that the oil/water contact in this shallower zone is further out that the Costayaco 1, 2 and 3 radius. As such, while unable to estimate ultimate potential reserves from this zone, we expect them to be significantly higher than reported at year end 2007, with ultimate size depending on the location of the oil/water contact. Exhibit 13: Costayaco Field

Source: Company Reports In addition to the ongoing Costayaco 4, the partners currently plan on drilling Costayaco 5, 6 and 7 later this year.


Guayuyaco

Located in the Putumayo Basin, the 52,366 acres Guayuyaco block is currently covered by an Ecopetrol production contract, expiring in 2027. Solana currently has a 35% non operated interest in the block. The block currently contains two oil discoveries, the Guayuyaco and the Juanambu fields. The Guayuyaco field, discovered in 2005 currently has two wells on production, while the Juanambu field, discovered in 2007, is producing from one well. We currently are forecasting 550 bopd (net) from the block in 2008 production to the company’s 35% interest. Note that the partners are planning on drilling at least one additional producer on Juanambu in 2008. The Juanambu filed is connected, via a spur line to the adjacent Toroyaco facility, from where crude is exported via existing infrastructure. In the longer term, the partners could drill two prospects currently identified on the block, mainly the Verdeyaco and the Floresta.

Magangué

Solana currently has a 37.8% working interest, and operatorship, of the 20,757 acres Magangué block in the Lower Magdalena Basin. The block contains the Güepajé gas field, reported to contain 7.5 Bcf of 2P gas reserves. Production from this field is currently shut in, pending installation of a new compressor. The field’s last reported production (4Q07) was 2.6 mmcf/d (785 mcfd net to Solana). Note that gas production from the field was sold locally at $2.55/MMbtu. Given the block’s neighbourhood; adjacent to the prolific Pacific Rubiales (PEG‐TSX, STRONG BUY) La Creciente block, the company is in the process of re‐evaluating available geological information (including seismic) to identify potential exploration.

Guachiría

Solana has a 70% interest and operatorship of the 16,903 acres Guachiría block in the Llanos Basin. While this block is governed by an ANH exploration and exploitation contract, it is subject to an additional 13% royalty payable to Ecopetrol. Guachiría is home to the Yalea‐1 production well, with latest production reported at 30 bopd (gross). In addition, Solana recently drilled the Primavera‐1 well, an oil discovery that flow tested at 650 bopd (gross). The company expects to place this well on long term production as of June 2008.


Exploration

In addition to the above producing assets, Solana currently has an interest in seven Colombian exploratory stage blocks. In the Putumayo Basin, the company has a 70% interest in the Guachiría, Guachiría Norte, Guachiría Sur, a 50% interest in the Garibay, and a 100% interest in the Colonia and San Pablo. In the Catatumbo Basin, the company has an 85% interest in Area A of Catguas, and a 50% interest in area B of the Catguas. Guachiría Norte – The 101,807 acres Guachiría Norte block was awarded to Solana under an ANH exploration and Exploitation contract, with exploration Phase 4 due to expire on March 21, 2009. As part of the agreement, Solana has committed to drilling two exploration wells, as well as acquire 25 km2 of 3D seismic on the block. The company is reprocessing legacy seismic on the block, aimed at identifying future drill locations. Note that the block is believed to contain a significant Carbonera C5 channel. Guachiría Sur – The 90,441 acres Guachiría Sur Block is subject to an ANH exploration and exploitation contract. In addition to recently acquiring 120 km2 of 3D seismic on the block, Solana spud the Palmitas‐2 exploration well in 1Q08. Initial results indicate a potential oil discovery on the Carbonera structural play, although confirmation remains pending test results, expected by 3Q08 at the latest. Colonia – The Llanos basin Colonia block is one of two blocks acquired by Solana’s ‘new’ management team. These 108,479 acres is covered by an ANH contract. The company’s minimum work commitments on the block include the acquisition of 55 km2 of 3D seismic, as well as drilling one exploration well per year between June 2008 and June 2013. San Pablo – This 104,526 acres Llanos Basin block was acquired in conjunction with the Colonia block on June 25, 2007. Remaining minimum work commitments on the block include drilling one exploration well per year from June 2008 until June 2013. This block is subject to an ANH contract. 50 km2 3‐D seismic data was acquired in December 2007. Garibay – Solana currently has a 100% interest in the 75,861 acres Garibay block. Under the ANH contract for this block, Solana is required to drill one exploration well by October 25, 2008. Late last year, the company announced farming out 50% of the block to a CEPSA (CEP‐MC, not rated) subsidiary. As per the farm‐in agreement with Solana, CEPCOLSA will bear 100% of cost on this exploration well (Topocho‐1) in order to earn its 50% interest.


Catguas – Covering 393,145 acres of the Catatumbo Basin, the Catguas block is Solana’s largest in areal extent. Laying on trend, as well as adjacent to several oil fields (including the 250+ million barrels Tibu oil field), we consider this block as highly prospective. In addition to the drill ready Ñatubay structure (estimated to contain a potential 19 million barrels of oil), Solana has identified four leads on the block, potentially containing 30 million barrels of oil. The company has an 85% working interest in the southern 70% of the block (area B), and a 50% interest in the northern 30% of the block (area A). The block contains the Tres Curvas‐1 oil discovery, which flow tested at 180 bopd (gross) from two formations. Note that this well is currently on extended test using a progressive cavity pump, aimed at identifying potential benefits of this technology in the basin. The company is also committed to a minimum of two wells by November 2008 (one new and one re‐completion, or two new). These wells are scheduled for 3Q08, targeting a deeper formation than Tres Curvas‐1, in addition to the same shallower ones. 15% of the block will have to be relinquished in November 2008. Solana, as part of its work commitments, is in the process of acquiring 132 Km of 2D and 50 km2 of 3D seismic on the block. While the Catatumbo basin, including Solana’s block, is very prospective, its location, along the border for Venezuela, adds a layer of security risks to the company’s operation. Although we don’t expect this to preclude the company from engaging in exploration, and potentially production, operations, militant activities could delay said operations.


$mln 2005 2006 2007 2008E 2009EASSETSCurrentCash and cash equivalents 24 30 72 75 233Cash in trust 0 3 0 0 0Accounts receivable 8 6 8 18 18Prepaid expenses 3 1 1 1 1Other 0 0 0 0 0

35 41 80 94 252

Deposits 2 3 3 50 50Petroleum and natural gas properties 74 54 82 157 157Other capital assets 1 1 1 1 1Investment 0 0 0 0 0

Other capital assets 0 0 0 0 076 58 86 208 208112 99 167 302 460

LIABILITIES AND SHAREHOLDERSʹ EQUITYCurrent Accounts payable 7 3 9 9 9Other 0 0 0 0 0

7 3 9 9 9

Asset retirement obligations 1 2 2 2 2Income tax liability 6 0 0 18 109Other 0 0 0 0 0

7 2 2 20 111

Shareholdersʹ equityShare capital 111 123 187 194 194Contributed surplus 4 5 12 13 13Cumulative other comprehensive income 0 6 6 109 109Deficit ‐17 ‐40 ‐49 ‐43 ‐86Other 0 0 0 0 110

98 94 155 273 340112 99 167 302 460

Appendix Exhibit 14: Balance Sheet Source: Company Reports, Raymond James Ltd.


Exhibit 15: Income & Cash Flow Statements$mln 2005 2006 2007 2008E 2009E

REVENUEPetroleum sales, net of royalties 8 9 18 108 213Interest income 1 2 1 3 5Total net revenue 9 11 19 111 218

EXPENSESOperating 2 3 4 9 13General and administrative 3 5 5 7 10Share‐based compensation 2 3 14 6 2Depletion, depreciation and accretion 6 35 6 17 21Interest on term loan 0 0 0 0 0Foreign Exchange Loss (Gain) 0 ‐2 0 1 0Other 0 0 0 0 0

13 44 29 39 46

Income before provision for income taxesProvision for income taxes Current 0 ‐5 0 6 8 Future 0 0 0 18 54Net income ‐4 ‐28 ‐9 48 110

Cash Flow Statement

CASH FLOWS FROM OPERATING ACTIVITIESItems not requiring outlay of cash:Net Income ‐4 ‐28 ‐9 48 110 Depletion and depreciation 6 35 6 17 21 Future income taxes 0 ‐5 0 18 54 Share‐based compensation 2 3 14 6 2Unrealized loss on derivative financial instruments 0 0 0 0 0

Other items 0 0 0 0 04 6 10 88 187

Changes in non‐cash working capital 2 1 3 ‐2 0

6 7 13 86 187

CASH FLOWS USED IN INVESTING ACTIVITIESExpenditures on property, plant and equipment ‐34 ‐26 ‐33 ‐92 ‐50Change in working capital ‐ Investing ‐3 2 2 ‐8 0Additions to other capital assets 0 0 ‐1 0 0Other receivables 0 0 0 0 0Deposits ‐2 ‐1 0 2 0Investment 0 0 0 0 0Other 0 ‐4 0 0 0

‐39 ‐29 ‐32 ‐99 ‐50

CASH FLOWS FROM FINANCING ACTIVITIES

Proceeds from exercise of options 1 0 0 0 0Proceeds from issuance of common stock 0 34 57 16 21Sale of capital assets 0 0 0 0 0Repayment of demand loan 0 0 0 0 0Other 0 0 0 0 0

1 34 57 16 21

Net increase in cash and cash equivalents ‐32 12 38 3 158Cash and cash equivalents, beginning o f period 56 21 33 72 75Cash and cash equivalents, end of period 24 33 72 75 233Source: Company Reports, Raymond James Ltd.









Fiscal Regimes

Colombian fiscal terms are divided into two contract styles. The older Ecopetrol association contracts, and the more recent ANH contracts. Under the association contracts, Ecopetrol, Colombia’s state oil company, has a back‐in right post discovery on all blocks. In addition, production is subject to up to a 20% government royalty. The newer ANH contracts eliminated the Ecopetrol back‐in right. Royalties under ANH contracts are based on a sliding scale, from 8% for production up to 5,000 bopd, up to 25% for production exceeding 600,000 bopd. In addition, a 30% windfall tax applies for fields producing in excess of 5 million barrels (total production). This tax is based on production in excess of the 5 million barrels threshold, and is referenced to WTI pricing. Under the RJ long term WTI assumption of US$130 per barrel, this equates to 24%. Income is also subject to a 33% corporate tax rate, as well as a 3.3% war tax for both contract types. Exhibit 16: Commodity Forecasts

Source: Bloomberg, Raymond James Ltd.


Risks Competition

The oil & gas industry is highly competitive and the corporation competes with a substantial number of companies. There can be no assurance that such competitors will not substantially increase the resources devoted to the development and marketing of products and services that compete with those of Solana or enter markets that Solana is active in. Commodity Price Volatility

The corporation is subject to the fluctuations in oil, natural gas and other commodity energy prices. It is anticipated that the international oil & gas industry has an inherently high capital cost due to large construction projects. Nevertheless, changes in commodity prices could result in a decision by Solana to suspend or reduce operations because such operations are no longer economically viable. If production is not suspended or reduced during such period, the low differential between the price of the corporation’s end products and the cost of production could lower Solana’ revenues. Reserve and resource risks

Solana currently provides third‐party reserves evaluation on its producing assets, and calculations remain dependent on long‐term oil pricing, geological assumptions made, and the companyʹs ability to produce said reserves. Regulatory and Political

Solana’s operations are subject to a variety international laws, regulations and guidelines, including laws and regulations relating to health and safety, the conduct of operations, the protection of the environment and the manufacture, management, transportation, storage and disposal of certain materials used in operations. Changes to laws, regulations and guidelines due to environmental changes, unforeseen environmental effects, general economic conditions and other matters may cause adverse effects to operations. The companyʹs exploration, producing and potential properties are located in Colombia. The companyʹs operations, financial results, and valuation could be adversely affected by events beyond its control taken by the current or future governments in those countries with respect to policy changes regarding taxation, regulation, and other business environment changes.



Solana is subject to various environmental laws and regulations enacted in the jurisdictions in which it operates. Including the governance of the manufacturing, processing, importation, transportation, handling and disposal of certain materials used in operations. Solana may become liable for damages against which it cannot adequately insure or against which it may elect not to insure because of high costs or other reasons. Solana may be required to increase operating expenses or capital expenditures in order to comply with any possible new restrictions or regulations. Operating Risk and Insurance

Operational risks and hazards could expose Solana to substantial liability for personal injury, loss of life, business interruption, property damage or destruction, pollution and other environmental damages. While insurance coverage is expected to address all material risks to which it is exposed and is adequate and customary in its current state of operations, such insurance is subject to coverage limits and exclusions and may not be available for the risks and hazards to which Solana is exposed. Additional Financing

In order to execute our discussed plans, the corporation may require a combination of additional debt and/or equity financing to support ongoing operations, to undertake capital expenditures or to undertake acquisitions or other business combination transactions. There can be no assurance that additional financing will be available to Solana when needed or on terms acceptable to Solana. Inability to raise financing to support ongoing operations or to fund capital expenditures or acquisitions could limit growth. Currency Exchange Rate Risk

The revenue generated from the operations of Solana may be denominated in US dollars or other international currencies so that fluctuations in the currency exchange rates may have an impact on the results of Solana.


JUNE 16, 2008






KEY FINANCIAL METRICSFY-Dec 31 2007A 2008E 2009ECFPs (C$) nm nm nmP/CFPS nm nm nmCFPS - 1Q nm nm nmCFPS - 2Q nm nm nmCFPS - 3Q nm nm nmCFPS - 4Q nm nm nmNAVPS nmP/NAV nmRevenue ($mln) nm nm nmYield (%) 0%

Commodity AssumptionsWTI (US$/bbl) $72 $113 $130HHub (US$/mmbtu) $7.12 $10.00 $7.50Exchng Rate (US$/C$) $0.94 $1.00 $1.00ProductionOil (kbbl/d) 0 0 0Nat. Gas (mmcf/d) 0 0 0Total (boe/d) 0 0 0

EBITDA ($mln) 0 2 -1Net Debt/ CF nm nm nm

COMPANY DESCRIPTION


3.05

WesternZagros is an exploration stage international oil & gas company. The company's main asset is an exploration block in the Kurdistan region of Northern Iraq.

OUTPERFORM 24.50

WesternZagros Resources Ltd. WZR-TSXV

Initiating Coverage: Modern Exploration on History Rich Lands

Event

We are initiating research coverage on WesternZagros Resources Ltd. (WesternZagros) with an OUTPERFORM rating and a C$4.50 per share target price.

Action

We are recommending WesternZagros to investors looking for exposure to a pure play; high‐impact; exploration portfolio in one of the world’s most prolific hydrocarbon basins.

Analysis

WesternZagros is a junior international oil & gas company, currently focused on exploration in the Kurdistan region of Northern Iraq. The company has a 40% interest in a 2,120 km2 production sharing contract (PSC) in the Kalar‐Bawanoor area of Kurdistan. We believe current market valuations offer investors a very attractive risk/reward proposition. Specifically, markets appear to be valuing WesternZagros on the basis of a 300‐350 million barrels of recoverable oil discovery, less than 3% of the 12 billion barrels of potential OOIP on the block. While the pure exploration stage of the company currently prevents us from assigning a STRONG BUY rating, we do consider WesternZagros a must own for investors looking for a high impact exploration oil & gas play.

Valuation

We currently value WesternZagros on the basis of a risked Expected Monetary Value (EMV), which includes a geological chance of success adjusted NPV (DCF, 10% after tax) of the company’s exploration prospects, as well as a monetary cost of failure. We calculate an EMV of C$4.56 per share on WesternZagros. On an un‐risked basis, reflecting a potential discovery of 7 billion barrels of OOIP, we calculate a NAV of C$20 per share, a potential sevenfold return on investment from current trading levels. Note that the company’s last reported data estimated the block to contain up to 12 billion barrels of OOIP, close to double the 7 billion barrels estimate we use in our NAV.


Table of Contents

Investment Highlights......................................................................................4 Stock Valuation and Recommendation ...........................................................5 Company Profile .............................................................................................8 Operations ....................................................................................................10 Kurdistan Region of Iraq................................................................................11 Appendix ......................................................................................................18 Fiscal Regimes..............................................................................................20 Risks.............................................................................................................22


Exhibit 1: Western Zagros Corporate Summary

WesternZagros Resources Ltd. (WZR: V)Company Summary Shares & Listing InformationOverview:Company name WesternZagros Resources Shares & capitalization:Ticker WZR Shares outstanding ‐ basic (M) 207.5Exchange TSXV Shares outstanding ‐ fd (M) 214.4Rating OUTPERFORM Market capitalization (C$mln) $632.8Current share price* C$3.05 Enterprise value 2007E ($mln) $493.612‐month target price C$4.50 Key shareholders*:Total projected return (incl. dividends payable) 48% Paulson & Co. Inc. 13.4%

OppenheimerFunds, Inc. 7.6%* as at Jun 9, 2008 Vertex One Asset Management Inc. 6.0%

PropertiesArea Other/Details Prospective Resources (July 31, 2007) (MM Bbl)Kurdistan Oil Initially In Place (undiscovered) MeanKalar ‐ Bawanoor PSC ‐‐> Exploration Kalar 1,640

Bawanoor 1,427Sarqala 1,177East Kalar Deep 670East Kalar 503

Valuation N. Structures 1 833Year end: Dec. 31 2006A 2007A 2008E 2009E North Bawanoor 833P/CF nm nm nm nm Miocene Pinch‐Out 833EV/CF nm nm nm nm Oligocene Pinch‐Out 333P/E nm nm nm nm Oligocene Reef 3,500Target P/CF nm nm nm nm Total 11,749Other Parameters *seismically defined structuresEV/BOED nm Key Operating and Financial DataEV/BOE (2P) nm Year end: Dec. 31 2007A 2008E 2009EEV/BOE (Reserves + Resources) $0.04 PRODUCTION (Net):

Crude oil (b/d) 0 0 0Commodity Price Assumptions 2007 2008E 2009E LT Natural gas (mmcf/d) 0.0 0.0 0.0Brent oil (US$/b) $73 $113 $130 $130 Total prod. (boe/d) 0 0 0NYMEX gas (US$/mmbtu) $7.12 $10.00 $7.50 $7.50 % Natural gas 0% 0% 0%

FINANCIAL STATEMENTS:

EMV Estimate Sensitivity* Revenues ($mln) nm nm nmOperating Expenses ($mln) nm nm nm

COS EMV ($mm) EMVPS Income Tax ($mln) nm nm nmNet Income ($mln) nm nm nm

10% $325 $1.52 Operating Cash Flow ($mln) nm nm nm20% $760 $3.5425% $978 $4.56 CFPS ‐ basic nm nm nm30% $1,195 $5.57 CFPS ‐ fd nm nm nm40% $1,630 $7.60 EPS ‐basic nm nm nm50% $2,065 $9.63 EPS ‐ fd nm nm nm100% $4,240 $19.78 Capex ($M) $35 $102 $100

Net Debt (surplus) ($mln) ($96) ($63) $42*Source: Raymond James Ltd. estimates Net debt/cash flow nm nm nm

Potential Production Profile (2,833 million bbls) (Gross) Management & DirectorsName PositionExecutive ManagementFrred Dyment Executive Chairman Ex Ranger Oil, Maxx Petroleum, CAPPSimon Hatfield President Ex Exxon, Petro‐Canada, TalismanRobert Theriault VP Engineering and OpsEx Husky, Cairn, CSR PetroleumGreg Stevenson VP Finance Ex Western Oil SandsBoard representatives:Frred Dyment Executive Chairman Ex Ranger Oil, Maxx Petroleum, CAPPSimon Hatfield President Ex Exxon, Petro‐Canada, TalismanDavid Boon Non‐exec Ex Pan Canadian, EnCanaJohn Frangos Non‐exec Ex BHP, Western Oil SandsJim Houck Non‐exec Ex Western Oil Sands, ChevronTexacoRandall Oliphant Non‐exec Ex Barrick Gold


1,133

2,833 1,417

708 850

Potential Reservesmillon bbls oil

283 567

0100200300400500600700800900

2006 2008E 2010E 2013E 2015E 2017E 2019E 2021E 2023E 2025E

Barrels p

er day (000ʹs)

Source: Company Reports, Raymond James Ltd., Bloomberg, Capital IQ


Investment Highlights “Qui audet adipiscitur (Who Dares Wins)” – Special Air Service

WesternZagros is an exploration stage junior international oil & gas company, currently focused on the Kurdistan Region of Northern Iraq. High impact exploration ‐ 12 billion barrels of potential OOIP. In its September 14, 2007 information circular, WesternZagros indicates the potential for over 11.7 billion barrels of OOIP on the Kalar‐Bawanoor block. In addition, 5.4 billion barrels of this potential were, at the time, based on five seismically defined structures, and believed to be a reasonable estimate by the company’s independent reserves engineering firm (Sproule). Both figures are based on potential discoveries being oil, and not gas and gas condensate, fields. As with all exploration, note that drilling results are expected to be binary; proving the presence of commercial quantities of oil; or not. Targeting two exploration wells in 2008. In addition to the recently spudded Sarqala‐1 exploration well, WesternZagros’ 2008 plans include drilling a minimum of one additional exploration wells on the block. Based on the latest public information, the Sarqala structure (previously East Shakal) is estimated to contain a potential 1,177 barrels of oil (mean basis). Managed by an experienced team. Each of WesternZagros’ key technical team members has, on average, 30 years of oil & gas exposure. This includes extensive international oil & gas exposure with established oil & gas companies, including ExxonMobil, Petro‐Canada, Talisman, Cairn, and Husky. An attractive risk/reward exploration proposition. Markets appear to be valuing WesternZagros on the basis of a 300‐350 million barrels of recoverable oil discovery, less than 3% of management’s last reported estimate of 12 billion barrels of potential OOIP on the block. Charting pre‐exploration value build. Assuming that past events predict the future, WesternZagros’ market valuation could experience some near term appreciation. Specifically, we note the historical tendency of market valuations on pure exploration plays to build‐up, or ‘run‐up’ during the drilling of exploratory wells. As such, we note the potential for WesternZagros to follow this trend during the 120 days of drilling time on Sarqala‐1.

12 billion barrels of potential OOIP

An experienced management team

Attractive risk reward

2 exploration wells in 2008


Near term catalysts. We believe the following near term catalysts could create additional value for current WesternZagros shareholders:

Results on the Sarqala‐1 well expected in 3Q08; Drilling of the company’s second exploration well later this year; Potential resolution of the Kurdistan oil export situation.



Given the company’s exploration stage nature, we believe EMV to be a better value gauge than NAV calculations. An EMV reflects the exploration geological risk (chance of success (COS)), the value of exploration success (NPV), as well as the cost of failure (COF). Specifically, we calculate our EMV as follows: EMV = (NPV x COS) – (COF x {1‐COS}) Given the very subjective nature of chances of success (COS) estimates for a same play, we provide investors with a range of EMV calculations under varying COS cases. For the value of success, we account for 7,083 million barrels of potential OOIP, as this reflects the company’s current prospects and leads. While WesternZagros’ last published resource estimate indicated up to 12 billion barrels of potential OOIP, to remain true to our valuation methodology, we only include seismically identified potential barrels into our NPV calculations. We view any additional OOIP potential as a free option included in our risk/reward based target price. Note that the prospectivity of the basin is such that our estimates may prove to be overly conservative in the event the company chooses to drill all currently identified structures. We have prepared an NPV (DCF, 10% after tax) summary for the following WesternZagros prospects and leads – Kalar, Sarqala, Bawanoor, East Kalar, East Kalar deep, North Bawanoor and N. Structures 1 – based on a potential 2,833 million barrels of recoverable oil. Note that our recoverable oil scenario is based on a recovery factor of 40% of OOIP. Given the lack of reservoir data from potential fields on the block; precluding the accurate calculation of a field recovery factor, we have opted to use regional analogs in setting our COS and recovery factor assumptions. Specifically, we note that investigations and data from 6 recent wells, suggest recovery factors between 30% and 50% of OOIP on Addax’s (AXC‐TSX, OUTPERFORM) neighbouing Taq Taq field. As an aside, Kirkuk basin reservoirs tend to be highly fractured, with wells achieving flow rates as high as 100,000 bopd, and good localized drainage.

We calculate an EMV C$4.56 share for WesternZagros

We believe EMV to be a better gauge for explorcos than NAV


Exhibit 2: Risked Contingent EMV Summary

Potential recoverable resouces Geological Risk Potential Reserves NPV EMV EMV per sharemmbbls COS mmbbls C$ Million C$ Million C$2,833 10% 283 $4,240 $325 $1.522,833 20% 567 4,240 760 3.542,833 25% 708 4,240 978 4.562,833 30% 850 4,240 1,195 5.572,833 40% 1,133 4,240 1,630 7.602,833 50% 1,417 4,240 2,065 9.632,833 100% 2,833 4,240 4,240 19.78


Exhibit 3: Geological Chance of Success75% COS 37.5% COS 18.3% COS 5% COS

Same Play Same Play New Play, New BasinAdjacent Structure Nearby Structure Play with Negative Data

Very Low Risk Low Risk Moderate Risk Very High Risk

Source: Otis and Schneidermann, Raymond James Ltd.

9.2% COS

New Play, Same TrendOld Play, New Trend

High Risk

We currently model a 25% COS on the company’s seismically identified leads and prospects in determining our valuation of the company. We also assume a $110 million cost of failure, accounting for drilling three exploration wells. Specifically, we refer to the work of Otis and Schneidermann, noting that a rule of thumb for “Same Play, Nearby Structure” is to assign a 37.5% geological COS, while COS is typically 18.3% for an “Old Play New Trend.” While we believe the WesternZagros structures/block lie between these two, we model the lower end of the range, partially to compensate for our somewhat aggressive recovery factor assumption. Further justification for our COS lies in the historical regional exploration success rate of 47%; significantly higher than our 25% assumption. In addition, the presence of several oil seeps on the block confirms a working Hydrocarbon system, and narrows exploration risk to the presence of reservoir and seal on identified structures. Our estimates are based on the case of oil discoveries on the company’s block. Given the limited regional gas market, we expect that a gas discovery could take up to ten years to be commercially developed. Specifically, given limited local market demand, the gas infrastructure in Iraq; including the four natural gas fields earmarked for near term exploitation; remains at an early stage. While we would consider a gas discovery on the block as value adding, we believe short term investors would be better served by an oil discovery.


0

5

10

15

20

25

East Kalar East KalarDeep

N.Structures 1

NorthBawanoor

Sarqala Bawanoor Kalar

C$ per Share

Given the continued volatility in commodity pricing, we are providing investors with valuation sensitivities for our risked EMV per share (fd) on WesternZagros under different long term oil prices and different discount rates. Exhibit 4: EMV Sensitivity

$90 $110 $130 $150 $170

5% C$4.94 C$6.46 C$7.47 C$8.89 C$9.37

10% C$2.77 C$3.84 C$4.56 C$5.54 C$5.82

12% C$2.18 C$3.12 C$3.76 C$4.62 C$4.86

15% C$1.48 C$2.28 C$2.83 C$3.54 C$3.73


Discoun

t rate

Source: Raymond James Ltd. Note that current market valuations appear to be pricing WesternZagros on the basis of a 300‐350 million barrels of oil discovery, a 95% discount to the company’s estimated prospective OOIP of 12 billion barrels of oil. Exhibit 5: WesternZagros Value Creation Source: Company Reports, Raymond James Ltd.


Company Profile

WesternZagros is an exploration stage junior successful international oil and gas company, focused on creating value from its assets in Kurdistan. The company’s shares trade on the TSX Venture Exchange under the symbol WZR. The corporate and capital structures of the company are illustrated below. We have also included a list of the company’s top ten institutional shareholders. Exhibit 6: WesternZagros Corporate Structure

WesternZagros Resources Ltd. (Alberta)

WesternZagros Resources Inc. (Alberta)

Western Oil International Holdings Limited(Cyprus)

WesternZagros Limited. (Cyprus)



(M)Common Shares Outstanding 207Stock options 7Shares O/S ‐ fully diluted 214Market Capitalization ($mln) 633

Holders SharesPAULSON & CO. INC. 13.4%OPPENHEIMERFUNDS, INC. 7.6%VERTEX ONE ASSET MANAGEMENT 6.0%FIDELITY MANAGEMENT & RESEARCH COMPANY 4.1%MACKENZIE FINANCIAL CORPORATION 3.1%HORIZON ASSET MANAGEMENT, INC. 1.7%JET CAPITAL INVESTORS LP 0.9%PYRAMIS GLOBAL ADVISORS, LLC 0.5%WELLINGTON MANAGEMENT COMPANY LLP 0.3%AIM FUNDS MANAGEMENT INC. 0.2%

Exhibit 7: Market Capitalization and Top 10 Holders Source: Capital IQ, Raymond James Ltd.

History

“Aux âmes bien nées, la valeur nʹattend point le nombre des années (To well born souls, value does not await number of years)” –Pierre Corneille

In 2006, the predecessor to WesternZagros was awarded a PSC by the regional government of Kurdistan for the Kalar‐Bawanoor block. Following its incorporation; as part of a Plan of Arrangement between Marathon Oil and Western Oil Sands; in 2007, WesternZagros signed an amended PSC with the KRG for this block in early 2008.

Leadership tam

Each of WesternZagros’ key technical team members has, on average, 30 years of oil & gas exposure. This includes extensive international oil & gas exposure with established oil & gas companies, including ExxonMobil, Petro‐Canada, Talisman, Cairn, and Husky.


Fred Dyment, Executive Chairman and Director, has been active in the oil & gas industry for over 30 years, including the position of Governor of the Canadian Association of Petroleum Producers (CAPP) from 1995 to 1997. Prior to WesternZagros, he was the CEO of Maxx Petroleum. Prior to that, Mr. Dyment held various roles at Ranger Oil, including that of CEO. Mr. Dyment holds a Chartered Accountant designation. Simon Hatfield, President and Director, has held various managerial as well as technical roles with Imperial Oil, Exxon, Talisman, Chauvco and Petro‐Canada. In addition, he has been involved in Iraq’s oil & gas industry for over a decade, including initiating the Kurdistan opportunity for WesternZagros. Mr. Hatfield is a graduate of the University of Calgary (Executive Development Program). He also holds a B.Sc. and a M.Sc. in Geology. Greg Stevenson, Vice President, Finance, joined the company from Western Oil Sands where he was the Controller. Prior to that, Mr. Stevenson was with a major accounting firm. Robert Theriault, Sr. VP Engineering & Operations, joined WesternZagros in August 2007. Prior to this, he was the Director of Midstream and Producing Assets for Cairn India. Part of his 30+ years of international oil & gas expertise were gained as Husky’s Manager of International Development. Mr. Theriault has also held various engineering and management positions with Pertamina‐Husky, CSR Petroleum, and Suncor. He is a graduate of the University of Calgary (B.Sc. in Mechanical Engineering). Mr. Theriault is a registered engineer in the province of Alberta. Dr. George Pinckney, VP Exploration, has over 30 years of oil & gas experience. The majority of his career was with Exxon, in various global leadership and technical roles. Academically, Mr. Pinckney holds a PhD (Geology) from the United Kingdom. He is also a registered geologist in Alberta.

Operations

The company is currently focused on an exploration play in the Kurdistan region of Northern Iraq. Specifically, WesternZagros has a 40% interest, and operatorship, of a 2,120 km2 block in the Kalar‐Bawanoor region of Kurdistan.


Kurdistan Region of Iraq

Iraq is bordered by Iran to the west, Saudi Arabia and Kuwait to the south, Turkey to the north, and Syria and Jordan to the east. Having gained independence in 1932, Iraq was a Hashemite monarchy until 1958, followed by a decade of military coups which culminated in the ‘reign’ of Saddam Hussein from 1979‐2003. In 2005, following the 2003 invasion by a US‐led coalition, Iraq was divided into federal regions. Kurdistan, governed by the Kurdistan Regional Government (KRG) is one of the federally recognized1 autonomous regions within Iraq, and includes the areas of Suleimaniah, Erbil and Dohuk. While the rest of Iraq remains prone to sectarian, and anti‐US, violence, Kurdistan continues to witness relative peace, leading to economic prosperity and growth. Exhibit 8: WesternZagros Operations in Kurdistan

Source: Company Reports 1 Iraqi constitution, article 113


The WesternZagros block lies in the hydrocarbon rich Kirkuk Basin. This basin extends across the Zagros fold belt ranges from Iran, through Iraq, and into parts of Northern Syria. The Kirkuk Basin was formed during the Late Permian to Paleocene times, covering parts of what used to be the Tethys Ocean. Jurassic and Cretaceous ages shales and carbonates are considered the most likely hydrocarbon source rock, or kitchen, for this petroleum province. The Shiranish, the Jaddala, and the Fars formations, Cretaceous and Tertiary carbonates, represent the main hydrocarbon‐bearing reservoirs of the basin. Note that the wide range of reservoir porosities adds a layer of complexity to field developments as well as reservoir modeling. As for trap, the basin contains some giant but simple faulted anticlines, typically identified via surface expressions, creating a very efficient trapping mechanism for regional oil and gas fields. In addition to the above structural traps, stratigraphic components are also present in some regional fields. In addition to oil, the basin is also home to several gas fields.


Exhibit 9: Kurdistan Stratigraphy



Kalar‐Bawanoor

Covering 2,120 km2, this exploration stage block lies adjacent to the prolific Kirkuk, Kor Mor and Chia Surkh fields. WesternZagros currently has, through the revised PSC signed with the KRG in February 2008, a 40% working interest and operatorship on the block. Note that the KRG currently has a 20% carried working interest in the block. The KRG also has the right to assign the remaining 40% interest to a third party company of its choosing by the end of August 2008. The PSC currently covers a three‐year exploration sub‐period, ending on December 31, 2010. In addition, WesternZagros has the option to extend this term by a two‐year exploration sub‐period, as well as two one‐year extensions. As per the revised terms, initial exploration commitments include a minimum of 1,150km seismic surveys (1,070 km of which has been acquired to date). The PSC terms also include drilling a minimum of three exploration wells by the end of 2010. Financially, the partners have committed to spending no less than US$75 million (US$30 million net to WesternZagros’ interest) in exploration on the block (aggregate seismic, geologic studies and drilling). Note that the PSC terms also include payment of an undisclosed capacity building bonus, payable over a 15 month period. Based on our analysis of other regional PSCs, as well as company specific information, we currently estimate this bonus to range between US$25 million to US$50 million. For the optional second term, commitments include an additional 575km of seismic lines, drilling a minimum of two additional wells, and aggregate spend of no less than US$35 million. The partners would also need to commit to drill a minimum of one exploration well per extension period. In the event of a discovery, the agreement includes an appraisal for commerciality obligation. The partners would then have to develop any commercial discoveries over a 20+5+5 year development and production period.


Exhibit 10: Prospects, Leads and Plays on the EPSA Area

Source: Company Reports Based on the seismic acquired to date, WesternZagros has identified eight prospects and leads, estimated to contain 7,083 million barrels of potential OOIP.


Mean Undiscovered Resources*MMbbls

Seismically Identified StructuresKalar 1,640Bawanoor 1,427Sarqala 1,177East Kalar Deep 670East Kalar 503N. Structures 1 833North Bawanoor 833

7,083

Stratigraphic PlaysMiocene Pinch‐Out 833Oligocene Pinch‐Out 333Oligocene Reef 3,500

Total 11,749

Exhibit 11: Estimate of Undiscovered Resources * Mean reflects an average confidence level with respect to the undiscovered resource estimates. Source: Company Reports, Raymond James Ltd. Visual interpretation of Exhibit 10 compared with previous versions indicate a smaller aerial extent to the Kalar prospect, potentially impacting our above OOIP estimates for this prospect. The Sarqala structure, previously East Shakal, unlike most regional structures presents limited surface expressions. Covering an areal extent of approximately 25 to 30 km2, it lies between the towns of Shakal and Kalar. An analysis of seismic lines over the structure indicates the possibility of a four‐way dip closure over several potential reservoir sands. Specifically, the structure appears to contain Miocene carbonates, such as the Upper Fars, as well as Cretaceous carbonates, such as the Shiranish and Qamchuga, known to be productive in the region. WesternZagros’ first exploration well, Sarqala‐1, is targeting all of the above formations. With an estimated drilling time of 120 days, we expect final results from this well by 3Q08. In the event of an oil discovery, we currently model a total of 1,177 million barrels of OOIP from all formations. In the event of a gas discovery, we estimate a potential 2.83 Tcf of OGIP.


The Kalar prospect, visible via surface expressions, lies 16km from the town of Kalar. The structure appears to lie against a potentially sealing northwest‐southeast thrust fault, and is associated with the Tukin surface oil seep. Note that a secondary anticline structure, including the Shiranish and Qamchuga cretaceous carbonate formations, is visible on seismic. In the event of an oil discovery, we currently model a total of 1,640 million barrels of OOIP from all formations. In the event of a gas discovery, we estimate a potential 5.1 Tcf of OGIP. Based on information made available to date, we consider this to be a low risk exploration opportunity. We anticipate the company to drill Kalar as part of its three exploration well commitments on the block. Bawanoor, similarly to Kalar, is a surface visible anticline, located in the middle of the company’s block. Seismic data on the structure indicates the potential for highly fractured reservoirs. While regional fracturing typically indicates highly productive wells, this does add a layer of complexity to reservoir modeling, and thus resource evaluation. In the event of an oil discovery, we currently model a total of 1,427 million barrels of OOIP from all formations. In the event of a gas discovery, we estimate a potential 3.8 Tcf of OGIP. In addition, pending disclosure of additional seismic information, we view this structure as carrying a higher exploration risk than the other two prospects. We anticipate the company to drill Kalar as part of its three exploration well commitments on the block.


Appendix

Exhibit 12: Balance Sheet $mln 2007 2008E 2009EAssetsCurrent Assets Cash and Cash Equivalents 100 82 ‐23 Accounts Receivable 0 0 0 Prepaid Expenses 0 0 0

101 82 ‐23

Long‐term Assets Oil & gas interests 0 75 175 Property, Pland and Equipment 56 158 263 Deposits Held in Trust 4 10 10

60 243 449

161 326 426

LiabilitiesCurrent Liabilities Accounts Payable and Accrued Liabilities 5 19 19

Shareholdersʹ EquityShare Capital 175 254 254Warrants 5 0 0Contributed Surplus 0 81 189Deficit ‐24 ‐28 ‐36

156 306 406

161 326 426 Source: Company Reports, Raymond James Ltd.


Exhibit 13: Income & Cash Flow Statements $mln 2007 2008E 2009ERevenues Interest Income 0.82 4.80 1.69

Expenses Charges Under Service Agreement 9.07 ‐ ‐ General and Administrative 1.64 6.55 6.00 Depreciation 0.04 ‐ ‐ Foreign Exchange Loss 0.49 0.72 1.00

11.24 7.27 7.00

Net Income (10.43) (2.47) (5.31)

Cash Provided By (Used In)

Cash From Operating Activities Net Loss (10.43) (4.36) (7.31) Non‐cash Items Depreciation 0.04 ‐ ‐ Stock‐based Compensation ‐ 1.82 2.00

(10.39) (2.53) (5.31) Increase in Non‐Cash Working Capital (0.11) ‐ ‐

(10.49) (2.53) (5.31)

Cash From Financing Activities Share Issuance Under Private Placement 97.77 71.44 ‐ Exercise of Warrants 4.20 6.05 ‐ Increase in Due to Related Party 42.83 ‐ ‐

144.80 77.48 ‐

Cash From Investing Activities Capital Expenditures (34.56) (101.58) (100.00) Deposits Held in Trust (4.15) (6.08) ‐ Decrease in Non‐cash Working Capital 4.66 14.37 ‐

(34.05) (93.30) (100.00)

Increase (Decrease) in Cash and Cash Equivalents 100.26 (18.29) (105.31)

Cash and Cash Equivalents at Beginning of Period 0.10 100.37 82.08

Cash and Cash Equivalents at End of Period 100.37 82.08 (23.23) Source: Company Reports, Raymond James Ltd.


Total Oil Produced

Operations Oil

Net Available Oil

Cost Recovery Oilup to 45% of Net Availabe Oil

Operating Costs

Exploration Costs

Development Costs

Profit Oilremaining net available oil

Total Profit Oilsharing based on ʺRʺ factor

slide range of 35%/65% to 16%/84%

Contractor KRG

WesternZagros(40%)

Third Party(40%)

KRG(20*%)

Royalty Oil10% of total crude oil

Fiscal Regimes

WesternZagros’ assets are currently governed by Production Sharing Contracts, under which produced oil is allocated to royalty oil, cost oil and profit oil. Note that the contractors are required to bear all upfront capital costs, which would then be recouped via the ‘Capital Cost Oil’ category. Exhibit 14: Kurdistan PSC Oil Allocation Source: Company Reports, Raymond James Ltd. Note: * Interest carried by WesternZagros









Exhibit 15: Commodity Forecasts Source: Bloomberg, Raymond James Ltd.


Risks Competition

The oil & gas industry is highly competitive and the corporation competes with a substantial number of companies. There can be no assurance that such competitors will not substantially increase the resources devoted to the development and marketing of products and services that compete with those of WesternZagros or enter markets that WesternZagros is active in. Commodity Price Volatility

The corporation is subject to the fluctuations in oil, natural gas and other commodity energy prices. It is anticipated that the international oil & gas industry has an inherently high capital cost due to large construction projects. Nevertheless, changes in commodity prices could result in a decision by WesternZagros to suspend or reduce operations because such operations are no longer economically viable. If production is not suspended or reduced during such period, the low differential between the price of the corporation’s end products and the cost of production could lower WesternZagros’ revenues. Reserve and resource risks

WesternZagros is an exploration stage company with no known oil and/or gas discoveries. There is a risk that the company may not discover any material hydrocarbon accumulations on its lands. WesternZagros currently provides third‐party resource evaluation on its assets, and calculations remain dependent on long‐term oil pricing, geological assumptions made, and the companyʹs ability to produce said reserves. Regulatory and Political

WesternZagros’s operations are subject to a variety international laws, regulations and guidelines, including laws and regulations relating to health and safety, the conduct of operations, the protection of the environment and the manufacture, management, transportation, storage and disposal of certain materials used in operations. Changes to laws, regulations and guidelines due to environmental changes, unforeseen environmental effects, general economic conditions and other matters may cause adverse effects to operations. The companyʹs exploration, producing and potential properties are located in the Kurdistan Region of Iraq. While currently semi‐autonomous, Kurdistan remains part of Iraq, existing oil exploration and agreements potentially being impacted by political changes in that country. The companyʹs operations, financial results, and valuation could be adversely affected by events beyond its control taken by the current or future governments in those countries with respect to policy changes regarding taxation, regulation, and other business environment changes.



WesternZagros is subject to various environmental laws and regulations enacted in the jurisdictions in which it operates. Including the governance of the manufacturing, processing, importation, transportation, handling and disposal of certain materials used in operations. WesternZagros may become liable for damages against which it cannot adequately insure or against which it may elect not to insure because of high costs or other reasons. WesternZagros may be required to increase operating expenses or capital expenditures in order to comply with any possible new restrictions or regulations. Operating Risk and Insurance

Operational risks and hazards could expose WesternZagros to substantial liability for personal injury, loss of life, business interruption, property damage or destruction, pollution and other environmental damages. While insurance coverage is expected to address all material risks to which it is exposed and is adequate and customary in its current state of operations, such insurance is subject to coverage limits and exclusions and may not be available for the risks and hazards to which WesternZagros is exposed. Additional Financing

In order to execute our discussed plans, the corporation may require a combination of additional debt and/or equity financing to support ongoing operations, to undertake capital expenditures or to undertake acquisitions or other business combination transactions. There can be no assurance that additional financing will be available to WesternZagros when needed or on terms acceptable to WesternZagros. Inability to raise financing to support ongoing operations or to fund capital expenditures or acquisitions could limit growth. Currency Exchange Rate Risk

The revenue generated from the operations of WesternZagros may be denominated in US dollars or other international currencies so that fluctuations in the currency exchange rates may have an impact on the results of WesternZagros.

RJ Disclosures

Analyst Certification

The views expressed in this report (which include the actual rating assigned to the company as well as the analytical substance and tone of the report) accurately reflect the personal views of the analyst(s) covering the subject securities. No part of said personʹs compensation was, is, or will be directly or indirectly related to the specific recommendations or views contained in this research report.

Stock Ratings

STRONG BUY 1: the stock is expected to appreciate and produce a total return of at least 15% and outperform the S&P/TSX Composite Index over the next six months. OUTPERFORM 2: the stock is expected to appreciate and outperform the S&P/TSX Composite Index over the next twelve months. MARKET PERFORM 3: the stock is expected to perform generally in line with the S&P/TSX Composite Index over the next twelve months and is potentially a source of funds for more highly rated securities. UNDERPERFORM 4: the stock is expected to underperform the S&P/TSX Composite Index or its sector over the next six to twelve months and should be sold.

Distribution of Ratings

Out of 191 stocks in the Raymond James Ltd. (Canada) coverage universe, the ratings distribution is as follows: Strong Buy and Outperform (Buy, 65%); Market Perform (Hold, 33%); Underperform (Sell, 2%). Within those rating categories, the percentage of rated companies that currently are or have been investment‐banking clients of Raymond James Ltd. or its affiliates over the past 12 months is as follows: Strong Buy and Outperform (Buy, 52%); Market Perform (Hold, 24%); Underperform, (Sell, 25%). Note: Data updated monthly.

Risk Factors

Some of the general risk factors that pertain to the projected 6‐12 month stock price targets included with our research are as follows: i) changes in industry fundamentals with respect to customer demand or product/service pricing could adversely impact expected revenues and earnings, ii) issues relating to major competitors, customers, suppliers and new product expectations could change investor attitudes toward the sector or this stock, iii) unforeseen developments with respect to the management, financial condition or accounting policies or practices could alter the prospective valuation, or iv) external factors that affect global and/or regional economies, interest rates, exchange rates or major segments of the economy could alter investor confidence and investment prospects.

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RJ Disclosures

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The Analyst and/or Associate are required to conduct due diligence on, and where deemed appropriate visit, the material operations of a subject company before initiating research coverage. The scope of the review may vary depending on the complexity of the subject companyʹs business operations.

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All expressions of opinion reflect the judgment of the Research Department of Raymond James Ltd. or its affiliates (RJL), at this date and are subject to change. Information has been obtained from sources considered reliable, but we do not guarantee that the foregoing report is accurate or complete. Other departments of RJL may have information which is not available to the Research Department about companies mentioned in this report. RJL may execute transactions in the securities mentioned in this report which may not be consistent with the report’s conclusions. RJL may perform investment banking or other services for, or solicit investment banking business from, any company mentioned in this report. This information is not an offer or solicitation for the sale or purchase of securities. Information in this report should not be construed as advice designed to meet the individual objectives of every investor. Consultation with your investment advisor is recommended. For institutional clients of the European Economic Area (EEA): This document (and any attachments or exhibits hereto) is intended only for EEA Institutional Clients or others to whom it may lawfully be submitted. RJL is a member of CIPF. ©2008 Raymond James Ltd.

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Any U.S. Institutional Investor wishing to effect trades in any security should contact Raymond James (USA) Ltd., a U.S. broker‐dealer affiliate of Raymond James Ltd.

RJ Disclosures

Company Symbol Exchange Disclosures

Addax Petroleum AXC TSX 7Bankers Petroleum BNK TSX 7Gran Tierra Energy GTE TSX, AMEX 7Pacific Rubiales Energy PEG TSX 7Solana Resources SOR TSXV 6WesternZagros Resources WZR TSXV 7

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