Description

Listing: PBEGF (OTC) PBG (Toronto Stock Exchange)
Shares Outstanding (primary): 45.3 million
Shares Outstanding (fully diluted): 50.3 million
Recent Share Price: $2.57 U.S.
Insider Ownership: 32.6%
Institutional Ownership: 11.5%

Forecast 2003 P/E ratio (fully diluted): 5.9x
Forecast 2003 Price/Cash Flow ratio (fully diluted): 2.5x

Forecast 2004 P/E ratio (fully diluted): 2.9x
Forecast 2004 Price/Cash Flow ratio (fully diluted): 1.2x

All prices contained within this report are converted into U.S. dollars.

Petrobank Energy and Resources was a value oriented oil and gas firm which has catalyzed into a company with the greatest two year growth profile of any publicly traded oil and gas firm in North America.

The event now fueling Petrobank’s rapid growth is an acquisition of a contract to develop two under-exploited government run oil fields in Columbia. This acquisition was done at no cost. When fully exploited, these fields should effectively add over 120 million barrels of proven reserves to the capital asset base of Petrobank. This would increase the asset base of Petrobank by over 1300% from its current 9 million boe (barrel of oil equivalent).

Growth in the production of oil and gas is forecast to accelerate from an average of 4,200 boepd (barrels of oil equivalent) at the end of 2002, to an average of 10,189 boepd in 2003 and an average of 20,394 boepd in 2004. A further growth rate in excess of 50% is forecast in 2005 (to 30,000+ boepd), but is not contained within the scope of this summary.

This temporary supernormal growth forecast has left investors struggling to define a fair market value. A very significant profit opportunity now exists for those who can accurately assess the degree of growth, while erring on the side of caution.

Initial results from development drilling in the last quarter confirm the validity of the assumptions contained herein and the forecasts derived from them.

COMPANY HISTORY

Petrobank Energy and Resources is the latest South American Oil development vehicle run by the highly successful management team of Mssrs. John Wright, Michael and Bruce Chernoff. They employ a simple, successful system for building oil and gas wealth.

1. Mssrs Wright and Chernoff inject capital into a publicly traded shell company. This capital is then used to develop smaller oil and gas fields in North America. These fields establish a sustainable level of cash flow for modest expenditures and create a platform for future growth. Management works for nominal salaries, and corporate spending is kept to a bare minimum.

2. The cash flow from domestic production is then used to purchase older, smaller to mid sized oil fields in South America from government agencies. The fields are selected on the basis of their workover potential using current technologies. In general terms, the fields purchased are largely untapped government agency owned fields.

3. 3-D seismic mapping is used to redefine the ultimate productivity of the purchased fields. Lower risk development wells are then drilled to prove up the reserves indicated in this mapping.

4. Once production and reserves from the acquired fields have increased to optimum levels, and the price of oil warrants, either the company in its entirety or the assets developed are then sold. Management receives their commensurate reward through their large equity stake.

This business model worked well for shareholders of management’s previous oil company, Pacalta Resources. In April 1996, Pacalta Resources purchased a mid sized oil field in Ecuador from a government agency. The acquisition dramatically increased Pacalta’s production, undeveloped land inventory, prospect base and reserves.

Pacalta employed high volume electrical submersible pumps to boost production sharply from this proven oil field. From the period of April 1996 to January 1999, Pacalta’s daily production grew from 5,300 barrels of oil per day (bopd) to 44,825 bopd. Oil reserves net to Pacalta grew five fold over that three year period.

In 1999, Pacalta was sold to Alberta Energy Corporation. The price paid by Alberta Energy represented a value equivalent to 4.8x tangible shareholders equity, 2x proven assets and $2.47 U.S. per barrel of proven reserves. On a flowing oil basis (a common unit of measurement when defining oil transactions), this represented a value of $10,000 U.S. per flowing barrel.

Investors who purchased shares of Pacalta upon the date of the Ecuadorian purchase and held through the time of the Alberta Energy takeover were rewarded with a share price that increased from $2. U.S. to $8 U.S.

Petrobank is picking up where Pacalta left off. In May 2002, Petrobank obtained an oil concession in Columbia from Alberta Energy. This concession was originally granted to Pacalta in late 1997, and lay virtually dormant until May.

Under the terms of this contract, Petrobank spends capital to increase production from these proven oil fields, and earns from 69% to 79% of all new production (subject to an 8% royalty and a diminished working interest after full repayment of invested capital). Petrobank is not the operator of the fields, and therefore is not responsible for maintenance investments on these fields. All upkeep of the fields, environmental remediation expenses etc, are paid in the form of a net per barrel fee to the field operator.

COMPANY OPERATIONS

Orito Field

The Orito field was once one of Columbia’s premier fields, and still represents one of Columbia’s largest oil reserves. Originally discovered in the late 1960’s, production peaked at approximately 70,000 bopd in 1972, and has gradually declined to a current level of roughly 3,500 bopd. Only primary oil extraction techniques have ever been used at this field (vertical wells using natural pressure), and until the acquisition of the fields by Petrobank only limited two dimensional seismic mapping of the oil field has been done.

The total oil reserves in place at Orito were originally estimated to exceed 1.2 billion barrels at inception, and approximately 220 million barrels have been produced to date. Older seismic mapping suggests that approximately 110 million barrels have yet to be produced with conventional primary techniques. Recent three dimensional seismic mapping undertaken by Petrobank indicates a high probability that the existing reserve number is conservative.

Virtually no work has been done on this field since the early 1980’s. I estimate that modern primary and tertiary extraction techniques may quickly boost Orito production to between 20,000-30,000 bopd. This would be consistent with historical average production from similar sized fields in this geologic formation. In addition, this production estimate is supported by results obtained from enhanced productivity rates on nearby fields where secondary (tertiary) extraction techniques are utilized.

Petrobank has committed to drilling three high impact development wells in Orito before the end of 2003. The first two development wells drilled at the Orito field thus far have been successful. The first well tested in excess of 1000 bopd. The second well is currently undergoing production testing, but indicates a productive pay zone equal to that of the first well. A further eleven to twelve wells will be drilled in 2003. There is such a high inventory of excellent drilling sites available that this number of wells is likely to be expanded in 2003.

In addition, Petrobank will be installing high volume electrical submersible pumps (ESPs) to stimulate production on five existing wells. The use of ESPs on Pacalta’s field in Ecuador increased production on virtually dormant wells to beyond 1000 bopd per well.

The wells in Orito are relatively deep (6,000+ feet), high pressure and prolific. As the anticipated finding costs on a per barrel basis are low (less than $2 per barrel), production rates are largely fixed and the reserves per well are expected to be high, this field will be very profitable by international standards, and extremely high by North American standards.

The cost for the initial drilling and well rehabilitation program will be approximately $39 million U.S. This report assumes that the drilling and rehabilitation program achieves an 80% success rate, and that gross reserves of roughly 2 million barrels per well are achieved.

The conclusion of the initial stage of Orito development should conservatively yield a minimum of 28 million barrels of proven oil reserves net to Petrobank. Total average production from this first stage of development (to be concluded in late 2003) is forecast to exceed 4,222 bopd. Forecast exit production rates for 2003 should be well in excess of 7,552 bopd. Net finding costs are estimated to be $1.95 U.S. per barrel.

The oil to be produced from the Orito field is roughly 20%-25% heavier than West Texas Intermediate crude (WTI) and is discounted accordingly. Under the terms of the production contract with EcoPetrol (the Columbian state oil company); Petrobank will net approximately 60% of WTI after all costs. This netback is roughly equivalent to operating cash flow.

I estimate that the total time frame required to bring this field to full development will be 36 months. Average netbacks of $23.8 million are forecast for 2003. Exit 2003 netback rates are likely to exceed $43 million.

Average production rates for 2004 are forecast to be 11,316 bopd, with exit rates in 2004 in the range of 13,937 bopd. The average 2004 netback is forecast to be $64.4 million, with exit netback rates likely to exceed $79.3 million.



NIEVA FIELD

The Nieva field is considerably smaller than Orito. In terms of production potential and reserve potential net to Petrobank, it is nevertheless significant.

The total reserve potential of Nieva using two dimensional seismic mapping suggest that oil reserves in place exceeded 220 million barrels. Roughly 16% of the reserve has thus far been produced. This field will have less upside in terms of production from high impact development wells. Production increases are forecast to come via infill drilling, well workovers, ESP and potentially water flood. The wells are somewhat shallower than Orito, which suggest that a larger scale water flood will be highly feasible.

The estimated cost of the first stage of field rehabilitation is forecast at $12 million U.S. This should add a minimum of 7 million barrels of proven reserves.

The oil produced at Nieva is somewhat lower in quality than Orito, and is discounted from WTI accordingly. Netbacks for Petrobank are forecast to be roughly 53% of WTI.

Average production rates of 1,347 bopd support a netback forecast of $6.2 million for 2003. Exit production rates in 2003 of 2021 bopd suggest an exit netback rate of $10.2 million. Average forecast production for 2004 from Nieva should be 3,978 bopd, with a 2004 exit rate of 5,641 bopd. This supports an average netback forecast for 2004 of $20 million, with exit rate netback for 2004 in the range of $28.3 million.

Canadian Assets

Petrobank has a production base that is roughly 70% oil and 30% natural gas. Production is forecast to grow only modestly (roughly 10%) beyond the current level of 4,200 boepd (barrel of oil equivalent per day), using a conversion ratio of 10:1 for gas. On average, the netbacks for Petrobank on this production are forecast to be approximately $14 U.S. per barrel in 2003.

Average netback rates are forecast to be $21.8 million U.S in 2003 and $24.1 million in 2004.

COMBINED ASSETS

Total development spending of approximately $70 million is anticipated over the next 12 months. This is forecast to result in a 34 million barrel upward revision of proven oil reserves to Petrobank (net of production). No value is assigned to probable reserves.

Production is forecast to grow from an average of 4,200 boepd in 2002 to an average of 10,189 boepd in 2003, and an average of 20,394 for 2004. Exit production rates of approximately 25,000 boepd are forecast by year end 2004.

Development spending of $110 million is forecast for 2004.

ASSET VALUATION FORECAST FOR 2003 & 2004

2003. A non discounted value of proven forecast 2003 reserves consistent with other oil reserves with similar flow rates in South America suggest that a value of $220.1 million ($5.00 U.S. per barrel) is appropriate.

On a flowing barrel of oil basis, a valuation of $17,500 U.S. per barrel of exit production indicates that a target price of $5.18 U.S. per share is realistic.

Tangible shareholders equity at year end 2003 is forecast to be $3.37 U.S. per share. Growth oriented junior oil companies are generally fairly valued at up to two time’s tangible shareholders equity, and seldom less than one times tangible equity.

2004. Expenditures are estimated to slightly exceed $110 million U.S. in 2004. This will result in an additional proven oil reserve addition net to Petrobank (after production) of 45 million barrels.

This results in a non discounted value of proven forecast 2004 reserves totaling $445 million U.S

On a flowing barrel of oil basis, a valuation of $17,500 U.S. per barrel on an exit rate of 25,000 boepd indicates that a target price of $8.69 U.S. per share is realistic.

Tangible shareholders equity at year end 2004 is forecast to be $6.89 per share.

PEER GROUP ANALYSIS

Companies of similar size with predominantly international assets in higher risk political jurisdictions sell for a minimum of 3.6 x cash flow and an average of 4.2 x cash flow.

2003. Based upon a 3.6 estimated 2003 average cash flow of $1.03 per share, Petrobank would be fairly valued at $3.70 U.S. per share. Using an average of 4.2 x results in a valuation of $4.32 U.S. per share.

2004. Based upon a 3.6x estimated 2004 average cash flow of $2.13 per share, Petrobank would be fairly valued at $7.66 U.S. per share. The application of a 4.2x valuation results in a market value of $8.95 U.S. per share.

BALANCE SHEET ANALYSIS

The current balance sheet is exceptionally strong for a company of Petrobank’s size, and well set up the next phase of expansion.

Petrobank has approximately $8 million U.S. of net working capital, unused credit lines of roughly $34 million U.S., and long term debts of roughly $37.8 million U.S. All of the debt is in the form of a debenture issue which matures on July 30, 2006. This debenture may be retired in cash, or alternatively, in the form of company shares at Petrobank’s option.

The forecast total spending requirements of $210 million U.S. through the balance of 2004 is forecast to be met through the following.

1. Cash flow equal to $158 million.
2. Use of present cash balances in the amount of $8 million.
3. Conversion of in the money options and warrants for cash proceeds of $8 million.
4. Conventional bank debts for the balance.

No common equity issues will be required, nor are they expected.



BUSINESS RISKS

OIL PRICE RISK. This report assumes that WTI prices will average $25 U.S. per barrel for 2003 and $24 U.S. per barrel in 2004. Should oil prices fall below that for an extended period, internally generated cash flow would decline. This would result in additional debt being required beyond forecast levels.

In addition, a decline in oil prices would lead to a compression of the cash flow ratios that the investing public would be willing to pay for the peer group. Petrobank’s future share price would be negatively impacted.

DEVELOPMENT SUCCESS RISK. This report assumes that Petrobank will enjoy an 80% overall success rate with development drilling in the years 2003 and 2004. Development drilling generally enjoys a success rate of 80%+ when three dimensional seismic data is available on proven oil fields. Management previously had a 100% success rate with their properties in Ecuador, which are both geographically and geologically similar to the Columbian properties.

This report assumes that Orito development wells will come on stream with initial production rates of 500 bopd, and will decline by 20% per annum. Nieva development will come on stream with initial production rates of 150 barrels per day and will decline by 30% per annum. ESP stimulated wells in Orito will initially produce 500 bopd and will decline by 30% per annum. Canadian development will rise by 10% per annum, net of production declines.

These forecasts should prove to be conservative. Orito wells at forecast depths have often come on stream with production rates in excess of 1000 bopd. Several showed initial production rates closer to 2000 bopd. Nieva wells have typically come on stream with initial production rates in excess of 200 bopd. Wells stimulated through ESP in the geologic trend generally show initial production in excess of 1000 bopd.

Should the 80% forecast success rate not be met, costs of finding oil on a per barrel basis would rise, as would depletion and amortization expenses. Lower production rates would have a negative effect upon all evaluations.

POLITICAL RISKS

Petrobank’s oil fields are located in the Putamaya basin of Columbia. This is an area of growing civil unrest. The political risk is difficult to quantify in any terms other than absolute. The current share price of Petrobank attributes a value per share of roughly $.77 U.S. to the Columbian assets at present. As the development of these fields proceed, the value of the Columbian assets will grow exponentially until they become the overwhelming share of the total asset value of Petrobank. Should oil assets in Columbia be nationalized by a new regime, the price of Petrobank would likely fall to a level below the net asset value of the remaining Canadian productive assets.

CONCLUSIONS

Petrobank Energy and Resources represents an unusually attractive opportunity within an unusually attractive sector. At current prices, investors may enjoy the high reward/low risk return that often comes with ownership of a business going through a period of supernormal growth. The development potential of the oil assets in Columbia are easily quantified and will become clearly evident over the next year. Investors at present are paying equity prices which attach only nominal values to this large and proven oil asset. Return on invested capital forecasts of 80% + for the years 2003 and 2004 suggest that value investors have excellent downside protection and significant upside potential.

Finally, Petrobank management now has considerable expertise in this area of the world and a proven track record of success.

Using the forecast cash flow pricing, one could reasonably suggest that fair market values for Petrobank common shares could be a minimum of $3.70 in 2003 and $7.66 in 2004. Flowing oil models and tangible shareholders equity models support this view and suggest that the model is in fact very conservative.

Price targets for 2003 should realistically be $5.18 U.S. and $8.69 U.S. per share in 2004.

Development success ratios above 80%, continuation of present oil pricing and/or success with larger scale use of ESPS on the Orito field will render this forecast to be conservative. Inclusion of probable reserves to this model will also make the valuations contained within this report overly conservative. Finally, should the drilling programs now in place be accelerated, the price targets could be achieved in much shorter timeframes.

Catalyst

Development drilling of two larger oilfields has the potential to increase reserves by over 1300% and production by over 100% in each of the years 2003 and in 2004. Cash flow is forecast to increase by over 500% from current levels within the next 24 months.