[Canada Research] Cardium Junior Oil Amp Gas Producers

7/22/2019 [Canada Research] Cardium Junior Oil Amp Gas Producers

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Canada ResearchPublished by Raymond James Ltd

Please read domestic and foreign disclosure/risk information beginning on page 103 and Analyst Certification on page 31.Raymond James Ltd. | 2200 – 925 West Georgia Street | Vancouver BC Canada V6C 3L2

Energy June 19, 2012

Industry ReportLuc Mageau CFA | 403.509.0505 | [email protected]

Kristopher Zack CA, CFA | 403.221.0414 | [email protected]

Justin Bouchard P.Eng., CFA | 403.509.0523 | [email protected]

Matthew Stevenson M.Eng. (Associate) | 403.509.0518 | [email protected] Steppan CFA (Associate) | 403.221.0411 | [email protected]

Vincent Urness (Associate) | 403.509.0534 | [email protected]

Energy

Assessing the Cardium's Second Generation - A Look at Horizontal Well Performance by Area

The Cardium has been one of the largest areas of oil production in the WCSB for >55 years. It was first developed on primary

production with vertical wells, then started undergoing waterflood and polymer flooding to enhance recoveries. The next

generation of development came when horizontal wells and multi-stage fracing were implemented. This spurred a renewed

focus on the play, and because of it oil production has more than doubled over the last few years. Today, the field produces

~100,000 bbl/d (up from its low of 40,000 bbl/d) – the highest level since the mid-1970s.

After 5 years of horizontal well development, we have sufficient data to assess how the new generation of unconventional

Cardium has matured. Rather than looking at the Cardium as one contiguous play, however, we break it down into discrete

areas. Along with the production data from >1,150 horizontal wells, we have compared average well performance and overal

economics between areas. The eastern portion of the Pembina field (both ‘halo’ acreage and infill development) presents the

best discounted return on capital – despite having slightly lower IP rates than other parts of the play. Lochend and Garrington

are also among the strongest areas. Lochend has demonstrated the highest initial production rates, but Willesden Green/Ferrie

and western Pembina were not far behind.

In addition to our play analysis, we are initiating coverage on four oil-weighted producers with a primary or significant focus on

Cardium oil. All of these companies provide investors with exposure to different aspects and geographic concentrations of the

play, while holding considerable scale in their respective areas. We are initiating on:

Spartan Oil Corp with a $6.25 target price and a Strong Buy rating . Spartan has a large inventory of low-risk, repeatable

drilling opportunities at eastern Pembina that exhibit some of the best economics in the Cardium play. The company has astrong net cash balance and we feel it is one of the best positioned to efficiently capitalize its Cardium assets.

TriOil Resources with a $3.75 target price and an Outperform rating. The company holds 57 net sections of Lochend

Cardium lands, which have been posting some of the strongest initial production results in the Cardium. In addition, TriOil

has achieved encouraging initial results from its high impact Dunvegan light oil play at Kaybob.

Vero Energy with a $3.25 target price and an Outperform rating. Vero offers investors a sizeable land position of 111 net

sections in the Cardium play, focused on the Carrot Creek, Edson, and western Pembina areas. These assets are earlier

stage, however results have improved considerably over the last 6 months.

Whitecap Resources with an Outperform rating and an $11.00 target price. Whitecap is a 16,000 boe/d oil weighted

intermediate producer, largely grown through a targeted acquisition strategy. Its Cardium assets are at East Pembina and

Garrington where its well results have been better than average. It holds a large position in the Saskatchewan Viking.

Company Ticker Ticker Current Target Price Dividend Total Return Rating Primary Secondary Price (6-12 months) Yield To Target

Junior Oil & Gas Producers

Spartan Oil Corp. STO-TSX C$3.51 C$6.25 0% 78% Strong Buy 1

TriOil Resources Ltd. TOL-TSXV C$1.85 C$3.75 0% 103% Outperform 2

Vero Energy Inc. VRO-TSX C$1.96 C$3.25 0% 66% Outperform 2

Whitecap Resources Inc. WCP-TSX C$7.21 C$11.00 0% 53% Outperform 2

Raymond James Ltd.



Canada Research | Page 2 of 111 Energy

Raymond James Ltd. | 2200 – 925 West Georgia Street | Vancouver BC Canada V6C 3L2

Table of Contents

The Cardium Today – Our Findings and Conclusions .......................................................... 3

Cardium 101: Geology Refresher ........................................................................................ 6

A Sum of the Parts – Breaking Up the Cardium ................................................................ 10

COMPANY INITIATIONS

Spartan Oil Corp. .............................................................................................................. 31

TriOil Resources Ltd. ......................................................................................................... 49

Vero Energy Inc. ............................................................................................................... 67

Whitecap Resources Inc. .................................................................................................. 83



Energy Canada Research | Page 3 of 111


The Cardium Today – Our Findings and Conclusions

The Cardium has been one of the largest areas of oil production in the WCSB for >55

years. It was first developed on primary production with vertical wells, then started

undergoing waterflood and polymer flooding to enhance recoveries. The next

generation of development came when horizontal wells and multi-stage fracing was

implemented. This spurred a new generation of development. Now, after 5 years into

the horizontal well development cycle, we take a look at how the new generation ofunconventional Cardium has matured. Rather than looking at the Cardium as one

contiguous play, we break it down into discrete areas – consistent with the geologic

deposition that brought the formation into existence.

We present a summary of our economic and well performance findings in Exhibit 1. In

compiling this data we came to several conclusions with regards to each area as well as

the play in general, and found that certain areas were outperforming on a relative basis.

Our conclusions are as follows:

Production Profile: Each area has its own distinct production profile, although even

within areas there can be significant variability. Lochend and Willesden Green-

Ferrier present some of the strongest type curves. Buck Lake and Brazeau River

exhibit the steepest decline rates, whereas Pembina East – despite having one ofthe lower IP rates – has one of the shallowest decline rates.

Development: Pembina, Garrington, and Willesden Green-Ferrier have the most

horizontal well development to date, while Lochend and the North Cardium are still

in early stages.

Well Costs: For the most part, the Cardium tends to get deeper on the western

flank and shallower toward the eastern edge. For that reason, Pembina East and

Garrington tend to have less costly wells while Brazeau, Lochend, and Pembina

West are more expensive on average. The difference in depth between shallow

eastern Cardium and deeper western Cardium can range from 500 m to 1,000 m or

more across the play.

Gas Cut: In the Cardium, a lack of water in the system means that solution gas is the

primary reservoir drive source. On a production basis, a higher gas-oil ratio (GOR)

means higher production on a boe basis; on an economic basis this is dependent on

commodity price. Areas with a higher GOR include the North Cardium and

Willesden Green-Ferrier.

After looking at the well data, and our conclusions, we believe the criteria that make for

a strong Cardium oil horizontal play can be viewed from two perspectives. For outright

well performance, deeper parts of the play with thick pay zones, minimal recovery to

date, and high gas content will provide the highest initial rates. In terms of repeatability

and overall economics, shallower zones with lower well costs that lie within

conventional pool boundaries (tend to exhibit shallower declines) and have significantremaining recoverable resource are also quite attractive.

On an economic basis, we’ve taken all of these variables into account along with

horizontal well results from the play to date. Although all areas that produce Cardium oil

generate good economics under our base case commodity price scenario (i.e. US$90

WTI and US$3.50 Nymex Gas), there are areas of relative outperformance. We have

elected to use the Discounted Profit to Investment Ratio (DPIR) as a primary metric for

identifying these areas, since it normalizes the PV profit for every dollar of capital spent.

Based on this, the top areas are East Pembina, Garrington and Lochend. Areas which





rank lower on a DPIR basis include Brazeau River and Buck Lake-Wilson Creek. We have

left the North Cardium/Edson out of this discussion because of the wide swath which it

covers, and the limited development to date is insufficient for drawing definitive

conclusions.

Producers best positioned to take advantage of the more prospective areas of the

Cardium (from an economic perspective) include Spartan Oil Corp (Pembina East),

Whitecap Resources (Pembina East and Garrington), and TriOil Resources (Lochend).

Vero and Crocotta Energy both offer leverage to the emerging North Cardium, with

recent results (particularly at Edson) that have considerably outperformed the area

average.

The Cardium formation contains several individual layers and was deposited in

everything from a marine shelf to shoreface and coastal plain environment. For the

purposes of our analysis, however, we have identified two main sequences of interest;

the Cardium ‘A’ and the Cardium ‘B’. The Cardium ‘B’ is the deeper and more localized

of the two. It is also responsible for the linear high permeability trends at fields such as

Lochend and Garrington. Much more extensive is the sheet-like Cardium ‘A’ interval

which lies above the Cardium ‘B’ and blankets the giant Pembina and Willesden Green-

Ferrier fields, among others. Historically, the limits of conventional Cardium fields have

been defined by reservoir quality cutoffs (porosity and permeability) as opposed tophysical barriers (such as an oil/water/gas contacts). Horizontal multi-stage fracs serve

to significantly lower the permeability and porosity cutoffs, and in so doing significantly

expand the boundaries of prospective Cardium fields well beyond where vertical

development traditionally stopped. In addition to this ‘halo’ development, horizontal

multi-stage fracs can be used within conventional field boundaries by accessing lower,

tighter parts of the reservoir where the top high permeability layer has been exploited

vertically. In these ways, the application of multi-stage fracing and horizontal drilling has

the compound effect of both increasing the total oil in place (OOIP) within the Cardium

and serving to increase the recovery factors associated with current pools.

Given the variability in rock character, depth, and thickness in the Cardium it is not

surprising that completions techniques and frac designs have evolved considerably since

horizontal development began. In a number of areas of the Cardium, the trend has been

shifting toward slick-water fracs. In low permeability zones, these fracs allow for better

permeability post-frac and can help bias the frac downward into the tighter pay of the

Cardium ‘A’. Slick-water fracs require much less in the way of chemicals/polymers,

although higher fluid requirements can increase their expense for deeper plays. Also

popular are nitrified water foam fracs and gelled water which use slightly less water and

can help create increased frac width. On the completions side, monobore completions

are becoming popular at areas such as Pembina, as they allow for faster drilling times

and lower cost wells. Although deeper areas tend to still require an intermediate casing

style of drilling. This is for increased control through the drill process and is particularly

necessary for higher gas content wells. Horizontal legs in the Cardium typically vary from

1,000 m to 1,500 m or more, while individual fracs can range in size from 20 tons – 40

tons. The variance is based on specific well characteristics, depth, and reservoirparameters with no single rule being applied for any given circumstance.

Our summary economics for all areas (as well as type-curves) are shown in Exhibit 1.





Exhibit 1: Cardium Economics by Area

North Edson West East Buck Lake Willesden Green Garrington Brazeau LochendCardium Pembina Pembina Wilson Creek Ferrier

Input Assumptions

WTI ($US) $90.00 $90.00 $90.00 $90.00 $90.00 $90.00 $90.00 $90.00 $90.00

Nymex ($US) $3.50 $3.50 $3.50 $3.50 $3.50 $3.50 $3.50 $3.50 $3.50

FX ($C/$US) $0.98 $0.98 $0.98 $0.98 $0.98 $0.98 $0.98 $0.98 $0.98

We l l Cos t ($ml n) $3.5 mln $3.5 mln $3.9 mln $2.4 mln $3.3 mln $3.7 mln $2.9 mln $4.0 ml n $4.0 mln

Type Curve

IP30 (boe/d) 150 200 225 170 190 230 175 200 270

1s t Yr Decl ine (%) 65% 65% 75% 65% 75% 65% 70% 75% 75%

EUR (mboe) 160 180 220 160 200 230 220 200 250

Avg. % Gas 30% 30% 15% 8% 20% 30% 15% 20% 10%

Economics

NPV (BT, 10%) $1.0 mln $1.8 mln $2.3 mln $3.2 mln $1.8 mln $2.4 ml n $2.7 ml n $1.3 mln $3.5 ml n

IRR (BT, 10%) 11% 15% 15% 33% 14% 18% 21% 11% 20%

DPIR (X) 1.1x 1.3x 1.4x 1.9x 1.3x 1.4x 1.6x 1.2x 1.6x

Payback Pe ri od (yrs ) 4.9 3.0 3.4 1.4 3.8 2.7 2.5 5.1 2.3

Recycl e Ra tio (X) 1.6x 1.7x 2.4x 2.6x 2.5x 1.9x 3.2x 2.1x 2.6x

Horizontal Cardium Well Type Curves by Area

-

50

100

150

200

250

300

P r o d u c t i o n ( b o e / d )

Lochend

Willesden Green-

Ferrier

Pembina West

Brazeau River

Buck Lake-Wilson Creek

Edson

Garrington

Pembina East

North Cardium

Source: Raymond James Ltd.





Cardium 101: Geology Refresher

The Cardium formation of western Alberta represents one of the most prolific

hydrocarbon producing zones in North America and is home to the giant Pembina Field,

western Canada’s largest oil field. Oil production from the Cardium reached almost

100,000 bbl/d by the beginning of 2012. This is up from less than 40,000 bbl/d at the

beginning of 2010 due primarily to the onslaught of horizontal well technology. The

formation is estimated to contain an oil in place resource on the order of 10 bln bbls(~1.8 bln bbls have been produced to date). These OOIP numbers, however, are based

on legacy reservoir quality cutoffs associated with vertical development; horizontal

multi-frac technology lowers these cutoffs significantly, expanding pool boundaries and

increasing pay thicknesses. We estimate the OOIP number could increase on the order

of 40-60% or more leaving the amount of oil still recoverable very material. The Cardium

is also quite large in terms of areal extent, covering an arcuate strip 1,000 km long that

extends ~200 km into Alberta from the western edge of the basin. Our focus is on the

oil-prone portion of the formation which stretches along Alberta’s Deep Basin from

Edson and Pine Creek at the northern tip (~Township 60) down to just northwest of

Calgary at Lochend (Township 26). Exhibit 2 illustrates the location of the Cardium

formation, along with some detail on the various types of depositional environments

that coincide with it and a paleographic representation of what North America may

have looked like when the formation was deposited.

Exhibit 2: Cardium Paleogeography and Facies Map

Offshore

Shallow Shelf

Coastal Plain

Shoreface and

Shallow Marine

Source: Ron Blakey, NAU Geology, Alberta Geological Survey, Raymond James Ltd.

The Cardium is a Late Cretaceous age formation comprising of a wedge of clastic

sediments (primarily sandstone) laid down ~88 mln years ago. The formation thins from

a total gross thickness of ~150 m in the foothills (on the west side) to ~50 m in the

central Alberta plains until it disappears into the large mudstone formations that encase





it. The environment that the formation was laid down in varies from shallow marine

shelf, shoreface complexes, and tidal environments (i.e. shallow water) to estuarine and

fluvial coastal plains (i.e. river mouths). As a result of these diverse conditions, the

Cardium is quite complicated and the rock character varies from mudstone and siltstone

to sandstone and small intervals of conglomerate.

In terms of a hydrocarbon system, trapping in the Cardium is primarily stratigraphic in

nature. This allows for the collection of vast pools, such as those at Pembina, as well as

blanketing layers with resource style rock more amenable to horizontal development.

The source for the oil and gas is thought to be the underlying shale members that

neighbor the Cardium within the Cretaceous Colorado group. Notably, the Cardium

system has conspicuously low in-situ water, which effectively increases the oil in place

through higher oil saturations, and reduces risks associated with fracturing into mobile

aquifers. It also, however, removes water as a potential drive mechanism (or moving

force) for the oil. Offsetting this, however, is a significant amount of associated gas in

Cardium reservoirs. This provides a main source of reservoir drive energy, but requires

some additional infrastructure for gas conservation when production is originally being

ramped up. Generally speaking, gas content increases toward the western margin of the

play, as the formation is deeper and more thermally mature. There can also be local

areas of higher reported gas production in shallower areas where reservoir pressure is

lower, primarily because the lower pressure allows the gas to come out of solution moreeasily when the well is produced.

Exhibit 3 demonstrates the location of the Cardium within the Stratigraphic column and

breaks it up into some of its distinct members.

Exhibit 3: Cardium Stratigraphy

Conglomerate (Carrot Creek)

Cardium 'A' (Raven River)

Conglomerate Cap

Cardium 'B' (Burnstick)

Lower Cretacous (Mannville, Glauconite, Bluesky, Ellerslie, etc.)

Viking

Joli Fou

C o l o r a d o G r o u

p

Wapiabi Mudstones

C a r d i u m F o r m a t i o nCardium

Blackstone Mudstones

Second White Specks

Belle Fourche

Fish Scale

Westgate

Source: Alberta Geological Survey, Raymond James Ltd.

There are numerous individual layers within the Cardium formation, however from a

hydrocarbon storage perspective, we can identify two broad sedimentary sequences of

interest. The lowermost sequence correlates with the Cardium ‘B’ interval, also known

as the Burnstick Member or lower Pembina River. Above this we identify the Cardium

‘A’ sequence which correlates to the Raven River Member, or upper Pembina River. The

Cardium ‘A’ and Cardium ‘B’ are separated by a shale/mudstone interval, and each of

them consists of rock sequence types that become coarser and cleaner toward the top.





At the bottom of each sequence are muddy siltstones and tight sandstones, while the

top tends to have thicker fine-grained sandstones. At the top of each of these

sequences, there are often localized, variably thick conglomerate intervals which were

laid down along northwest-southeast shoreline trends. It is primarily in these localized,

but highly productive conglomerates and higher permeability sandstones that

conventional exploitation was focused on with vertical well technology.

The Cardium ‘B’ sand, also known as the Burnstick member, is primarily what has

formed the linear bar-like Cardium fields in areas such as Garrington, Lochend,

Crossfield, Ricinus, and Caroline. Legacy development of these fields has focused on a

conglomerate leg at the top of the Cardium ‘B’, which was deposited on top of the

muddy siltstones and sandstones during slowly rising sea levels. Wave action at the

shoreline would erode away northwest-southeast linear features, and rivers and

channels would deposit large grain gravel sediments along these shoreline ‘scours’. It is

these linear conglomerate trends that allowed vertical production from the Cardium ‘B’.

Because the more sheet-like Cardium ‘A’ zone often overlies the Cardium ‘B’ in these

areas, significant vertical well control on the ‘A’ sand exists.

In general, the Cardium ‘A’ is a separate silty sandstone sequence that lies above the

Cardium ‘B’, and is unique in that it was deposited in much broader shallow shelf,

shoreface, and coastal plain environment. For that reason, it tends to be much morecontinuous than the lower ‘B’ shoreline trends. In areas such as Pembina, Willesden

Green and Ferrier, the upper fine grained sandstone is often capped by a conglomerate

leg which varies from ~1 m - 3 m in thickness – this conglomerate correlates to the

Carrot Creek Conglomerate member which exists in up to 20 m thicknesses over the

Carrot Creek Cardium field on the northern edge of Pembina. Historical vertical

development of the ‘A’ zone has focused on the upper sandstone and conglomerate

legs, and field boundaries have been defined by reservoir quality (porosity and

permeability cutoffs). With the advent of horizontal drilling, these required cutoffs have

been lowered considerably. Not only does this allow the lateral limits of Cardium ‘A’

pools to be extended (in ‘halo’ plays), but also means that the lower portions of the ‘A’

zone are now accessible. The bottom layers of the Cardium ‘A’ sequence tend to be a

mix of muddy siltstone (i.e. lowest permeability and porosity) below a thicker layer of

bioturbated silty sandstones. Bioturbation is the displacement and mixing of sediment

particles by organisms and can make the reservoir more consistent in its properties as

well as increase permeability. It is the lower tight silty sandstones of the Cardium ‘A’

that are best targeted with horizontal multi-fracs, as the hydrocarbon storage potential

of these layers is high, while the permeability is lower. Across the Cardium, the tighter

‘A’ sands are predominantly the focus of producers today.

With some understanding of the various sub-intervals of the Cardium and how they

came to be, it is now important to understand the primary technical parameters which

can affect horizontal well performance in the Cardium.

• Depth: All other factors equal, wells which are deeper will encounter higher

reservoir pressures and produce at higher rates. Deeper wells will alsocorrespond to more expensive wells costs due to longer drill times and

potentially larger frac sizes required.

• Pay Thickness: Although self-explanatory, it is prudent to remind ourselves that

the thickness of the Cardium, and of its constituent intervals such as the ‘A’

sand vary in thickness and tend to generally thin as one moves to the east.

Thicker pay is associated with more oil in place, higher ultimate recoveries, and

potentially higher initial production rates depending on permeability.





• Gas to Oil Ratio: Much of the Cardium has significant solution gas, which serves

to increase both the initial production rates and the ultimate recoveries of

Cardium wells as it is a significant reservoir drive mechanism. Offsetting this

from an economics standpoint are the increased requirements for gas

conservation infrastructure and the negative impact on overall netbacks when

measured on a boe (energy equivalent) basis.

• Depletion: The ratio of current oil recovered versus ultimate oil recoverable.

The degree to which the reservoir has been depleted will be seen in lower

reservoir energy and correspondingly lower production rates. Although

depletion can lower oil in place, ultimate expected recovery is a moving target,

and can be increased through horizontal multi-frac technology, waterflood, and

Enhanced Oil Recovery (EOR).

• Target Zone and Rock Character: Conglomerate legs in the Cardium ‘B’ zone

and variably at the top of the Cardium ‘A’ sand can result in significantly higher

initial production rates due to enhanced permeability, depending on the

degree of reservoir depletion from previous vertical production. The lower,

tighter sequences of the Cardium ‘A’ sand often have significant bioturbation,

which can improve reservoir homogeneity and increase effective permeability.

It is also important to remember that even with the respective zones,permeability and porosity can vary considerably by area, section to section and

even well to well.

Based on this framework, higher well production performance typically coincides with

deeper intervals within the Cardium, larger net pay thicknesses, higher solution gas

ratios and lower current recovery factors. From an economic perspective, however, one

must consider how the well costs and required infrastructure increase with depth and

gas content. There are instances where lower cost shallower horizontal wells within

depleted zones can actually be more economic than higher performing wells,

particularly if these wells tap into thicker pay zones with less relative depletion (through

accessing the lower, tighter reservoir intervals) and they enjoy lower decline rates

associated with field maturity.





A Sum of the Parts – Breaking Up the Cardium

The Cardium formation blankets a vast swath of western Alberta, and is comprised of a

variety of discrete layers, depths, rock character, and degrees of prospectivity. To truly

understand the play we needed to break it down into more bite-sized pieces. By doing

this we are able to evaluate and compare it appropriately. Focusing on oil wells (there

are large areas of the Cardium which are gas-prone), we have elected to break up the

play into eight individual areas. These areas have been chosen based on similar geology,depth, and development history and are for the most part aligned with conventional

Cardium pools. We have also focused on areas which are now being considered for

unconventional development using horizontal multi-stage frac technology. A map of

how we broke down the areas is shown in Exhibit 4.

Exhibit 4: Our Definition of Cardium Areas

Source: Raymond James Ltd., GeoScout

In order to build a complete understanding of how the production from these areas

compares to each other and how the economics stack up, we have developed an in-

house tool to analyze the production results. This piece of software allows us to develop

type curves and summary data for each area based on existing well data. Moreimportantly, given that resource plays are statistical in nature, the tool takes a statistical

approach to analyzing the results. Specifically, our well analyzer inspects data for

consistency and significance so as to exclude data points that are clear outliers or are

unreliable due to factors such as unreasonably low monthly producing hours. With this

tool, we have analyzed GeoScout data for over 1,150 horizontal wells in the Cardium

over our 8 sub-areas. With this data in hand, we can more easily identify areas that are

outperforming. Exhibit 5 provides a sample of a type curve output from the well

analyzer tool.





Exhibit 5: Sample Well Data Analysis Output

0.0

1.0

2.0

3.0

4.0

5.0

0

60

120

180

240

300

N a t u r a l G a s P

r o d u c t i o n ( m m c f / d )

O i l P r o d u c t i o n ( b b l / d

) & T o t a l P r o d u c t i o n ( b o e / d )

0

5

10

15

20

0 6 12 18 24

N u m b e r o f W e l l s

Normalized Production MonthProduction (boe/d)

Oil (bbl/d)

Selection 1

Selection 2*

Producing Day Average

Rate (boe/d).

Producing Day Average

Rate (bbl/d - oil only).

# of wells considered in

each month's average

production ra te.

Months without data or unreliabl e data are

removed, and the next months da ta is adva nced.

Source: GeoScout, Raymond James Ltd.

The type curves we present are based on producing day averages and are compiled

from GeoScout, which uses publically available data. The accuracy of our results,

therefore, are limited to that of the originally reported data. We also note that even

over our individual areas, there is significant variability in reservoir quality and well

performance. East or West Pembina, for instance, includes both conventional in-pool

horizontal development, as well as halo development of thinner and potentially lower

quality peripheral reservoir. The numbers we present are based on broad averages, and

certainly can obscure or ignore localized areas of strong or weak results. Some key

aspects and assumptions used in our methodology are outlined below:

• Given that producing day averages are considered, we reject individual monthly

data points that do not have enough recorded hours to be considered reliable. This

is to avoid calculating an average production rate from a well that has been shut in

with an associated pressure drop, and then produced at a high rate for only a few

hours. This particularly impacts the calculation of IP30s, as the first month of a

well’s production history is most likely to have a minimal amount of hours recorded.

• We have also rejected monthly data points which lie outside of 5 standard

deviations of the mean for that month. While these results may be physically

consistent, they do not represent a fair expectation for a statistically defined

resource play and so are not used in the generation of an average type curve.

• When a monthly production data point is excluded for a well, the next month’s data

point is substituted for that month. In this way, a well is only entirely omitted from

the calculated average if all of its production data has been deemed unreliable.

• We have based the calculation of the production gas weighting on publically

available operator reported data. This can be affected by considerations other than

hydrocarbon composition and pressure, such as infrastructure available for gas

handling.





North Cardium & Edson

We have elected to combine the Edson, Pine Creek, and Carrot Creek areas of the

Cardium into one area. This area represents the region of the Cardium to the north of

Pembina which is home to several small linear conglomeritic trends and a more areally

extensive basal Cardium ‘A’ sand. It is the tighter ‘A’ sand which is the subject of

horizontal development in the halos around Edson, Pine Creek and Carrot Creek,

however development is still in its early stages with ~43 horizontal Cardium wells in ourdata set. We note that the western margin of the Cardium play in this area becomes

progressively more gas prone, however we have focused our analysis on the oil side of

the play. Companies with significant exposure to the Cardium in this area include Vero

and Crocotta Energy. Exhibit 6 summarizes some of the key attributes of the North

Cardium area.

Exhibit 6: North Cardium Overview

Data & Parameters# HZ Wells in Data Set 43

Avg. Vertical Depth (m) 1700-1900m

Net Pay Thickness (m) 3-8m

OOIP/Section 3-6 mmbbl

Avg. Well Cost ($mln) $3.5 mln

RJ Avg. IP30 (boe/d) 150

RJ Avg. EUR (boe) 160,000

Typical Gas % 20-30%


The North Cardium area as we have defined it is quite large, covering ~47 Townships inall. Compounding this, it is also one of the newer areas of horizontal Cardium oil

development, translating to an average horizontal well density of ~1 well/Township. As

a result, we caution that results vary dramatically, and the parameters in Exhibit 6

represent broad averages. Average well costs vary from $3.5 mln to $4 mln, which is a

function of both depth and the type of completion. A significant number of operators in

the area are using monobore completions with slick-water fracs, although nitrified foam

fracs and intermediate casing strings are also still in use. The average type curve for the

North Cardium area is given in Exhibit 7 below, with the resulting single well economics

in Exhibit 9. It is also important to mention that one bright spot here is Edson, which has

been posting results considerably above the average for the area. We have elected to

analyze the average type curve and single well economics of the Edson area separately,

as provided in Exhibit 8 and 10. Although we still only have less than 10 wells at Edson

(almost all with less than 1 year of data), the IP rates are nearly 50% higher, although

declines do appear steeper as well.

In general, the North Cardium area has gotten lower than average IP rates, but

considerably shallower decline curves than average. This implies to us that more work

needs to be done on proper stimulation (i.e. frac’ing) of the wells, so we believe some

upside to our type curve is likely. Given the relative infancy (and low drilling density) in

this area, this is consistent with other resource plays.





Exhibit 7: North Cardium Horizontal Cardium Well Results

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Exhibit 8: Edson Cardium Horizontal Well Results

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Exhibit 9: North Cardium Single Well Economics

Economic Outputs Price Deck Assumptions

NPV/well (10% B.T.) ($mln) $1.0

NPV/well (10% A.T.) ($mln) $0.5 WTI Oil (US$/bbl) $90.00

IRR/well (B.T.) (%) 11% Nymex Gas (US$/mcf) $3.50

DPIR* (X/well) 1.1x Exchange Rate (US$/C$) $0.98

Payback Period (Yrs) 4.9 Real Discount Rate (%) 10.0%

NPV/bbl (10% B.T.) ($/boe) $6.00

NPV/bbl (10% A.T.) ($/boe) $3.10

Implied F&D ($/boe) $21.88 Well Type Assumptions

Netback ($/boe) $36.06

Recycle Ratio (X) 1.6x Ini ti al Producti on (30-day) (boe/d) 150

Exit 6-month Rate (boe/d) 97

Model Inputs Exit 12-month Rate (boe/d) 57

Year 1 Decline Rate (%) 65.0%

Capex/ Well ($mln) $3.5 Year 2 Decline Rate (%) 20.0%

Differential** ($/boe) $20.13 Long-term Decline Rate (%) 7.0%

Full Life Avg Royalty (%) 22.1% Natural Gas Content (%) 30.0%

Op + Transport Costs ($/boe) $10.00 EUR/well (boe) 160,000

Corporate Tax Rate (%) 26.5%

Average North Cardium Horizontal Well Type Curve (Producing Day Average Rate) (boe/d)

*Discounted Profit to Investment Ratio - calculated as PV(cash flow)/Capex of Well

** Price Differential a ccounts for gas wei ghting of production in boe/d

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Production (boe/d) Cumulative (mmboe)


We have elected to bias our IP rates up slightly (but correct for it with slightly steeper

declines) in our economics. Despite the lower IP rates, the area still generates a DPIR

>1.0. It is important to note that the average IP rate for wells brought on production

after December 1, 2011 is closer to 200 boe/d and the NPV of wells under that scenario

would be closer to $1.8 mln.





Exhibit 10: Edson Cardium Single Well Economics


NPV/well (10% B.T.) ($mln) $1.8





NPV/bbl (10% B.T.) ($/boe) $9.73

NPV/bbl (10% A.T.) ($/boe) $6.01












Average Edson Cardium Horizontal Well Type Curve (Producing Day Average Rate) (boe/d)

*Discounted Profit to Investment Ratio - calculated as PV(cash flow)/Capex of Well

** Price Differential a ccounts for gas wei ghting of production in boe/d

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Pembina West

Given the extensive area covered by the giant Pembina Cardium field, we have elected

to break the area into a western and eastern half. Given the proximity, we have included

the Westpem strike area into our Pembina West area. As is the case for the Cardium in

general, recent horizontal drilling at Pembina West has focused on the halo, or outer

margin of the play, with lower and tighter portions of the Cardium ‘A’ zone being the

primary target. There has been some horizontal drilling, focused on increasing therecovery factors within thicker pay inside the conventional Pembina field boundaries.

The interesting conclusion is that wells inside the conventional pool boundary have

production rates that are lower than halo wells by ~0-60 boe/d. The reason for this is

that the horizontal wells have been targeting lower Cardium ‘A’ tight sands where

vertical wells have mainly targeted upper Cardium ‘A’ higher permeability sands and

conglomerates. So in-pool wells generate lower IP rates (offset by shallower declines),

but not as much as we initially thought would be the case.

The western Pembina area represents one of the deeper areas of the Cardium, and also

has some of the thickest pay – although this is somewhat offset by higher than average

well costs. Our data set for Pembina West is quite robust at ~380 horizontal wells

drilled since 2008, making it one of the most active parts of the Cardium. Companiesthat have drilled the most wells here (according to GeoScout data) include Penn West,

Vermillion and Petrobakken. Exhibit 11 summarizes some of the key attributes of the

Western Pembina area.

Exhibit 11: Western Pembina Summary








Typical Gas % 15%


With vertical depths reaching the 2,100 m mark, well costs lie in the $3.6 mln – $4.1 mln

range (on stream costs). Together with the type curve from our analysis of public wells

in the area (provided in Exhibit 12), this results in an estimated NPV per well of ~$2.3

mln (BT, 10%) at $90 WTI. Exhibit 13 provides a summary of the estimated single well

economics for this play.





Exhibit 12: Pembina West Horizontal Well Results

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Exhibit 13: Pembina West Single Well Economics


NPV/well (10% B.T.) ($mln) $2.3





NPV/bbl (10% B.T.) ($/boe) $10.45

NPV/bbl (10% A.T.) ($/boe) $6.64



Recycle Ratio (X) 2.4x Ini tial P roduction ( 30-day) (boe /d) 225

Exit 6-month Rate (boe/d) 126Model Inputs Exit 12-month Rate (boe/d) 63







Average Pembina West Cardium Horizontal Well Type Curve (Producing Day Average Rate) (boe/d)

*Discounted Profit to Investment Rati o - calculate d as PV(cash flow)/Capex of Well

** Price Differential a ccounts for gas weighting of production in boe/d

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Production (bbl/d) Cumulative (mmbbl)






Pembina East

As we have defined it, the Pembina East portion of the Cardium includes both the tight

Cardium ‘A’ halo, as well as the thicker and more conventional Cardium sands of the

eastern portion of Pembina. As a result the range of possible pay thicknesses and oil in

place estimates is quite large, as illustrated in Exhibit 14.

Exhibit 14: Eastern Pembina OverviewData & Parameters# HZ Wells in Data Set 313







Typical Gas % 8%


One of the most important characteristics of East Pembina, is that it represents the

shallowest portion of the Cardium oil play (outside of the foothills). As a result, well

costs are among the lowest in the Cardium at ~$2.2 mln - $2.5 mln. This bolsters the

economics of these wells – even though average IP rates tend to be lower (the result of

both lower pressure, thinner pay in the halo, and depletion from conventional

production within field boundaries). In addition to developing the halo at Pembina East,

horizontal multi-frac well design can also be used to greatly enhance recovery factors

within the conventional pool boundaries. While most of the legacy production fromPembina units has come from the top 1 m – 5 m of conglomerate and high permeability

clean sands, there can be up to 10 m – 15 m of lower Cardium which is tighter and more

amenable to horizontal wells and hydraulic fracturing. With significant oil in place

untapped below the high perm zone in existing fields, horizontal drilling and fracing can

increase the recovery factor in these fields by up to 15-20% by accessing this pay with

very little geological risk. East Pembina is an excellent example, therefore, of the

potential to increase OOIP through field boundary extension (i.e. halo) and increasing

recovery factors by accessing incremental oil from existing pools.

Exhibit 15 provides our average type curve results for Pembina East, with the resulting

single well economics given in Exhibit 16. With 313 horizontal wells in our data set, we

have a fair degree of confidence in the repeatability. We also note that with lower well

costs this area stands out on an economic basis, with an NPV of $3.2 mln (BT, 10%) and

IRR of >30%. It is worth highlighting that wells within conventional pools here may have

slightly lower initial rates, however the ensuing declines are usually also lower, and the

geologic risk is brought to almost nil more than offsetting the lower initial productivity.





Exhibit 15: Eastern Pembina Horizontal Well Results

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Exhibit 16: Pembina East Single Well Economics


NPV/well (10% B.T.) ($mln) $3.2





NPV/bbl (10% B.T.) ($/boe) $19.70

NPV/bbl (10% A.T.) ($/boe) $13.61



Recycle Ratio (X) 2.6x Ini ti al Producti on (30-day) (boe/d) 170Exit 6-month Rate (boe/d) 110








Average Pembina East Cardium Horizontal Well Type Curve (Producing Day Average Rate) (boe/d)

*Discounted Profit to Investment Ratio - calculated a s PV(cash flow)/Capex of Well

** Price Differential ac counts for gas weighting of production in boe/d

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Buck Lake – Wilson Creek

Lying to the south of the main Pembina field, and east of the Willesden Green – Ferrier

fields, the Buck Lake and Wilson Creek area of the Cardium lay along a linear shoreface

trend, with average vertical depths in the 1,500 m to 1,700 m range. The area also

includes Alder Flats and interest in these assets has been more recent. The first

horizontal well was drilled here in June 2010, but activity has picked up recently, with

Penn West drilling the most number of wells in the area (based on most recentGeoScout data). We already have 57 horizontal Cardium wells in our data set for the

area, and results have been encouraging. Good initial production rates are a function of

high reservoir energy from solution gas, and the relatively shallow nature of the area

helps to keep well costs reasonable. Exhibit 17 summarizes some of the key attributes of

the Buck Lake – Wilson Creek area.

Exhibit 17: Buck Lake – Wilson Creek Overview








Typical Gas % 20%


We present the results of our type curve analysis for Buck Lake and Wilson Creek inExhibit 18. Using average results and an on stream cost per well of $3.3 mln results in

our NPV/well (BT, 10%) of $1.8 mln at $90 WTI and $3.50 Nymex gas (Exhibit 19).

Although the area exhibits high initial results, steep declines are also demonstrated. This

has kept our NPV from being higher and payouts are also stretched to more than 3

years, as production rates are lower after the first year.





Exhibit 18: Wilson Creek – Buck Lake Horizontal Well Results

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Exhibit 19: Buck Lake – Wilson Creek Single Well Economics


NPV/well (10% B.T.) ($mln) $1.8





NPV/bbl (10% B.T.) ($/boe) $9.09

NPV/bbl (10% A.T.) ($/boe) $5.69












Average Buck Lake-Wilson Creek Cardium Horizontal Well Type Curve (Producing Day Average Rate)



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Brazeau River

Development of the tighter halo Cardium ‘A’ sand in the Brazeau River area began in

2010, and these Cardium wells lie on the western margin of the play (excluding the

Foothills). Average vertical depths lie between 2,000 m and 2,200 m, resulting in both

relatively high initial production rates and correspondingly higher well costs. The

Brazeau River Cardium covers a relatively small area, and our data set contains only 32

horizontal Cardium wells on stream since 2010. Exhibit 20 summarizes some of the keyattributes of the Brazeau area. Companies with the largest number of operated wells

(according to GeoScout) in the Cardium at Brazeau include PetroBakken, Sinopec

Daylight, and Vermillion.

Exhibit 20: Brazeau Overview








Typical Gas % 20%


Given the vertical depths associated with the Brazeau River Cardium, we have used

average well costs of ~$4.0 mln (on stream costs) in analyzing the economics of the play.

Together with the type curve from our analysis of public wells in the area (provided inExhibit 21), this results in an estimated NPV per well of ~$1.3 mln at $90 WTI. Exhibit 22

provides a summary of the estimated single well economics for this play.

Similar to Wilson Creek-Buck Lake area, the wells here exhibit high initial rates, but

decline by ~70-80% in the first year. Because of this, the wells in this area have

considerably lower NPVs and longer pay-out ratios (~5 years) than average.





Exhibit 21: Brazeau Horizontal Well Results

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Exhibit 22: Brazeau River Single Well Economics


NPV/well (10% B.T.) ($mln) $1.3





NPV/bbl (10% B.T.) ($/boe) $6.64

NPV/bbl (10% A.T.) ($/boe) $3.61











Average Brazeau River Cardium Horizontal Well Type Curve (Producing Day Average Rate) (boe/d)



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Willesden Green – Ferrier

The Willesden Green and Ferrier Cardium fields have counted among the most prolific

pools within the conventional Cardium play. This has been the result of depth and

considerable solution gas driving high production rates, combined with high pay

thicknesses providing large OOIP numbers. During its conventional exploitation, vertical

wells were drilled into an upper conglomeritic leg overlying the tighter sequences of the

Cardium ‘A’ sand. Recent horizontal development has been stepping out to the lowerand tighter portions of the ‘A’ sand along the western margins of the Willesden Green

and Ferrier fields (conventionally not exploited due to lower reservoir quality as

opposed to shale out on the eastern edges). We have data from approximately 140

horizontal Cardium wells drilled here since 2008. Companies most active in the area (as

defined by number of operated wells) are numerous, and include Bonavista, Penn West,

Yangarra, Devon, Anderson and Bellatrix, among others. Wells are typically drilled with

intermediate casing rather than monobore (given the depth, pressures and gas

presence) and nitrified foam, gelled water and hydrocarbon fracs are more common

than slick water given the depth. Exhibit 23 summarizes some of the key attributes of

the Willesden Green - Ferrier area.

Exhibit 23: Willesden Green – Ferrier Overview






Avg. IP30 (boe/d) 230

Avg. EUR (boe) 230,000

Typical Gas % 30%


With vertical depths in the 1,900 m to 2,300m range, slick-water fracs are rarely used

due to the pumping expense, and well costs lie in the $3.5 mln - $4.0 mln range,

completed and tied in. With the type curve from our analysis of public wells (provided in

Exhibit 24), we calculate a robust NPV (BT, 10%) per well of ~$2.4 mln at $90 WTI.

Exhibit 25 provides a summary of the estimated single well economics for this play.





Exhibit 24: Willesden Green – Ferrier Horizontal Well Results

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Exhibit 25: Willesden Green-Ferrier Single Well Economics


NPV/well (10% B.T.) ($mln) $2.4





NPV/bbl (10% B.T.) ($/boe) $10.52

NPV/bbl (10% A.T.) ($/boe) $6.81











Average Willesden Green - Ferrier Cardium Horizontal Well Type Curve (Prod Day Avg) (boe/d)



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Garrington

One of the original areas of interest for horizontal multi-stage fracturing was the

Garrington Cardium field. The conventional part of the play has traditionally been

defined by a long, linear conglomeritic trend at the top of the Cardium ‘B’ zone. As a

result, legacy vertical wells in the area have all penetrated the Cardium ‘A’ zone which

lies above the Cardium ‘B’, providing significant well control and confidence for

horizontal development of the Cardium ‘A’. Garrington is somewhat unique, however, inthat favourable reservoir parameters made legacy vertical development of the tighter

Cardium ‘A’ sand as well as the ‘B’ attractive, explaining why this area was one of the

original targets for horizontal multi-stage fracs. The first horizontal well was drilled here

in 2008 and more than 155 oil wells have been completed here since. Companies with

significant exposure to, or largest number of wells in the Cardium in this area include

Whitecap, Bonavista, Pengrowth (NAL), and Anderson Energy. Exhibit 26 summarizes

some of the key attributes of the Garrington area.

Exhibit 26: Garrington Summary








Typical Gas % 15%


With vertical depths in the 1,800 m to 2,100 m range, average well costs come in at

between $2.7 mln and $3.3 mln on average (on stream costs). Together with the

average type curve for the area, provided in Exhibit 27, this results in our NPV/well

estimate of $2.7 mln (BT, 10%) at $90 WTI (Exhibit 28) – which is one of the better

results from our analysis of the individual areas.





Exhibit 27: Garrington Horizontal Well Results

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Exhibit 28: Garrington Single Well Economics


NPV/well (10% B.T.) ($mln) $2.7





NPV/bbl (10% B.T.) ($/boe) $12.49

NPV/bbl (10% A.T.) ($/boe) $8.43











Average Garrington Cardium Horizontal Well Type Curve (Producing Day Average Rate) (boe/d)



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Lochend

The southern-most portion of the Cardium play in our data set is the Lochend area,

which lies only ~30 km to the northwest of downtown Calgary. This is one of the most

recent areas targeted by horizontal multi-stage fracturing development, however initial

results have been encouraging. The comparatively deeper Cardium wells have been

exhibiting high initial production rates, helping to bolster economics even when

adjusted for well costs. Like Garrington, the focus in Lochend is on horizontaldevelopment of the Cardium ‘A’ tight sand in the halo overlying conventional Cardium

‘B’ development - well control is significant due to legacy vertical wells. Currently TriOil,

PetroBakken, and Pengrowth (NAL) are the most significant companies by operated-well

in the Lochend Cardium, and to date have all been participating in infrastructure

investment in the area. Exhibit 29 summarizes some of the key attributes of the

Lochend area.

Exhibit 29: Lochend Overview








Typical Gas % 10%


Initially, companies tried a variety of completions techniques at Lochend, including

gelled oil, however results to date have indicated that slick-water fracs are the most

effective and most companies have migrated to this method as a result. Interestingly,

despite being deeper this area has a very low gas ratio. Higher declines are also a result,

but well performance beyond year 1 is still slightly better than the average Cardium

well. With vertical depths in the 2,100 m - 2,400 m range, well costs lie in the $3.5 mln -

$4.0 mln range (on stream costs). Together with the type curve from our analysis of

public wells in the area (provided in Exhibit 30), this results in an estimated NPV per well

of ~$3.5 mln (BT, 10%) at $90 WTI. This represents the highest NPV area of our Cardium

study, which is a function of the high production rates displayed to date. We caution

that this play is still early days, however. Exhibit 31 provides a summary of the

estimated single well economics for this play.





Exhibit 30: Lochend Horizontal Well Results

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Exhibit 31: Lochend Single Well Economics


NPV/well (10% B.T.) ($mln) $3.5





NPV/bbl (10% B.T.) ($/boe) $13.97

NPV/bbl (10% A.T.) ($/boe) $9.37











Average Lochend Cardium Horizontal Well Type Curve (Producing Day Average Rate) (boe/d)



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Company Citations

Company Name Ticker Exchange Currency Closing Price RJ Rating RJ Entity

Anderson Energy Ltd. AXL TSX NC

Bellatrix Exploration Ltd. BXE TSX NC

Bonavista Energy Corporation BNP TSX C$ 14.00 3 RJ LTD.

Crocotta Energy Inc. CTA TSX C$ 2.39 2 RJ LTD.

Devon Energy Corporation DVN NYSE US$ 56.70 2 RJ & Associates

Pengrowth Energy Corporation PGF TSX C$ 7.02 2 RJ LTD.

Penn West Petroleum Ltd. PWT TSX US$ 12.75 NC

PetroBakken Energy Ltd. PBN TSX C$ 11.85 3 RJ LTD.

Vermilion Energy Inc. VET TSX C$ 42.95 2 RJ LTD.

Yangarra Resources Ltd. YGR TSXV C$ 0.30 2 RJ LTD.

Notes: Prices are as of the most recent close on the indicated exchange and may not be in US$. See Disclosure section for

rating definitions. Stocks that do not trade on a U.S. national exchange may not be approved for sale in all U.S. states. NC=not

covered.





Spartan Oil Corp. June 19, 2012

STO-TSX Company Report - Initiation of CoverageLuc Mageau CFA | 403.509.0505 | [email protected]

Matthew Stevenson M.Eng. (Associate) | 403.509.0518 | [email protected]


Uniquely Positioned in the East CardiumEventWe are initiating coverage on Spartan Oil with a $6.25 target price and a Strong

Buy rating.

RecommendationSpartan holds a unique land position at East Pembina. We believe that existing

well control and established infrastructure, combined with strong cash

balances puts the company in a very good position to ramp production and

cash flow over the short-term. We recommend investors buy Spartan.

AnalysisSpartan’s primary asset is a 29,239 net acre contiguous land block at East

Pembina (Keystone). The block is part of the main Pembina Cardium pool andhas been extensively delineated (although less than 5% of oil has been

recovered to date). Included in this land base is ~11.5 net sections of halo lands

surrounding the Keystone block. In total the company has booked 20.7 mmboe

of reserves at Keystone, and with additional drilling we believe the ultimate

recoverable resource on the land base could be closer to 37 mmbbl. The

company also holds lands in southeast Saskatchewan, primarily targeting

Bakken and Mississippian oil. The exploration land base is still in early stages of

development so we view it primarily as option value at this point, but with

34,410 total net acres held in the area, the potential could be large.

As of 1Q12 Spartan had a net cash position of $61 mln ($0.73/share). With an

aggressive 2012 program planned for the Cardium (including drilling 46.6 net

Cardium wells) the company is on track to exit 2012 at 4,300-4,500 boe/d (fromcurrent production rates of 2,600 boe/d). Even post the 2012 program we

expect Spartan to have a net cash balance, setting the company up well for

continued strong growth into 2013.

ValuationOur $6.25 target price is based on our 2012E SUPER NAV estimate of $6.05 and

a 6.0x times multiple (in-line with the company’s historical trading range) on

our 2013E cash flow per share estimate of $1.04. We have applied a 50%

weighting to each in arriving at our target price.

CFPS 1Q 2Q 3Q 4Q Full Revenues NAVPS

Mar Jun Sep Dec Year (mln)

2011A C$0.00 C$0.02 C$0.04 C$0.11 C$0.16 C$17

2012E 0.12A 0.13 0.15 0.21 0.61 71 6.05

2013E 0.23 0.23 0.26 0.31 1.04 119 na

Source: Raymond James Ltd., Thomson One

Rating & Target

Strong Buy 1

Target Price (6-12 mos): C$6.25

Current Price ( Jun-14-12 ) C$3.51

Total Return to Target 78%

52-Week Range C$4.73 - C$2.05Market Data

Market Capitalization (mln) C$292

Current Net Debt (mln) -C$61

Enterprise Value (mln) C$231

Shares Outstanding (mln, f.d.) 83.2

Average Daily Volume (000s) 271

Dividend/Yield C$0.00/0.0%

Key Financial Metrics

2011A 2012E 2013E

P/CFPS

21.9x 5.7x 3.4x

P/NAV

0.6x na

WTI (US$/bbl)

US$95.13 US$91.82 US$80.00HHub (US$/mmbtu)

US$4.03 US$2.39 US$3.25

Production (boe/d)

1,028 2,752 4,734

Production: Oil (%)

80% 85% 86%

Capex (mln)

C$86 C$127 C$115

EBITDA (mln)

C$15 C$50 C$86

Net Debt (mln)

C$(27) C$(8) C$21

Net Debt/Trailing Cash Flow

-2.4x -0.1x 0.2x

Company Description

Spartan Oil is focused on the horizontal developmen

southeast Saskatchewan.





Table of Contents

Investment Overview ........................................................................................................ 33

Company Overview ........................................................................................................... 34

Valuation & Recommendation ......................................................................................... 39

Appendix 1: Financial Statements .................................................................................... 43

Appendix 2: Management & Board of Directors .............................................................. 46

Risks .................................................................................................................................. 48





Investment Overview

Initiating Coverage – Strong Buy Rating and $6.25 Target Price

We are initiating coverage on Spartan Oil with a $6.25 target price and a Strong Buy

rating. Our target price represents a return to target of 78% based on the June 14, 2012

close price of $3.51. Our target price is based on our 2012E Risk Adjusted SUPER NAVestimate and a 6.0x times multiple on our 2013E cash flow per share estimate. The

multiple is based on the company’s historical trading range since inception, and is in-line

with other junior oil-weighted companies in our coverage universe. Our SUPER NAV

estimate assumes development of the Keystone Cardium lands (unitized and halo) held

at East Pembina. We have not included an incremental resource NAV for the southeast

Saskatchewan wells and although we believe the lands could have considerable

potential, at this point we believe they represent option value given the earlier stage of

development.

Exhibit 1: Spartan Target Price Calculation

Estimate Multiple Target Weight Component

CFPS (2013E) $1.04 6.0x $6.24 50% $3.12

NAVPS (2012E) $6.05 $6.05 50% $3.03

$6.15

Target Price $6.25 Source: Raymond James Ltd.

Investment Summary

Spartan has assembled a concentrated land position at East Pembina; an attractive

portion of the Cardium light oil play. In addition to a large reserves base, this land also

provides the company with the capability to achieve a dramatic growth profile from a

large, repeatable inventory of low-risk Cardium locations. Other reasons for our

investment thesis are as follows:

• Keystone Cardium Unitized Lands – The company’s unitized Cardium lands provide

a large reserves base, but with current recovery at only ~5% of OOIP, there is

significant resource upside as well. Horizontal development will allow for increased

recovery factors, in addition to expanding accessible oil pay within the unitized

lands and waterflood build-out.

• Top-Tier Cardium Economics – Although initial production rates at East Pembina can

be lower than other parts of the Cardium, low well costs, repeatability, and

shallower declines create some of the best rates of return in the Cardium play.

Shorter payback periods make Spartan assets particularly valuable for an organic

growth strategy.

• Halo Cardium Upside – In addition to low-risk, repeatable locations at its unitizedCardium, the company also has ~11.5 net sections of non-unit halo Cardium lands

which provide high-impact resource upside to the company’s opportunity

inventory.

• Strong Balance Sheet – With total credit facilities of $50 mln (undrawn), and our

estimated 2012E exit net cash position of $8 mln ($61 mln of net cash at 1Q12), the

company has the financial flexibility to pursue an aggressive growth profile.





Company Overview

Spartan Oil currently has two core operating areas – East Pembina Cardium and

southeast Saskatchewan. In the Cardium, the company holds a contiguous land block of

29,239 net acres with significant well control and established infrastructure. At

southeast Saskatchewan, the company has 34,410 net acres of land with production

primarily coming from Mississippian and Bakken formations.

Spartan originally went public in January 2010 (as Spartan Exploration). The company at

that time had amassed its current land base in southeast Saskatchewan, some

Shaunavon lands in southwest Saskatchewan and ~14 net sections of Cardium rights. By

mid-2010 the company reached the 1,500 boe/d mark (up from ~400 boe/d at IPO) and

held nearly 20 sections of Cardium rights. At year-end 2010, the company increased its

Cardium production to ~2,150 boe/d. In April 2011, Spartan Exploration was acquired

and a spin-out transaction created the current-day Spartan Oil. Through concurrent

acquisitions, Spartan Oil emerged as an 800 boe/d company with its current assets in

Keystone (Unit 1&2), its southeast Saskatchewan lands, and 22 net sections of

southwest Saskatchewan assets. Shortly after, the company sold its southwest

Saskatchewan assets (with associated production of 190 boe/d) for $21 mln and

commenced its Cardium focused development at East Pembina.

Asset Overview

East Pembina Cardium - Keystone

Spartan holds 45.7 net sections (29,239 net acres) of land in the East Pembina area

called Keystone. The land is characterized by two unitized parcels – Unit 1 (6.5 gross

sections; 25.26% non-operated interest), Unit 2 (33.5 gross sections; 97.12% operated

interest), and 16 (11.5 net) sections on non-unitized halo lands. The lands are virtually

all contiguous and have very good vertical well control to define the amount of oil in

place and recoverable. Exhibit 2 shows a map of the company’s Cardium lands held at

East Pembina.





Exhibit 2: Spartan East Pembina Land Base

Source: Spartan Oil Corp., Raymond James Ltd.

The unitized lands have been extensively drilled with vertical wells. On average 1

vertical well has been drilled on each quarter section (160 acre spacing). This has de-

risked the land block and provides a high degree of confidence about the amount of oil

present and recoverable. Not only does this lower the risk profile of Spartan’s play in

our mind, it also puts the company in a somewhat unique position as it relates to other

junior oil-weighted producers. Outside of the unitized lands there is also considerable

vertical well control, although not as much as inside the unit.

The key to increasing the recovery of oil and increasing production from Keystone lands

is drilling horizontal wells. Drilling both between existing producers and on halo lands

will allow access to Cardium pay that vertical wells are not able to exploit. To date,

Spartan has drilled or participated in 32 (25.7 net) horizontal Cardium wells – 27 ofwhich have at least 30 days of production. Wells have been drilled as both in-fills on the

unitized lands (effectively proving downspacing capability) and on the halo lands

(proving prospectivity) with successful results. The average IP30 for these wells has been

~170 boe/d. Results of Spartan horizontal wells to date are shown in Exhibit 3 (data

from GeoScout, current to April 2012).





Exhibit 3: Horizontal Well Results at East Pembina

0.0

1.0

2.0

3.0

4.0

5.0

0

60

120

180

240

300


O i l P r o d u c t i o n

( b b l / d ) & T o t a l P r o d u c t i o n ( b o e / d )

0

5

10

15

20

0 6 12 18 24



Oil (bbl/d)

Selection 1

Selection 2* Source: Raymond James Ltd., GeoScout

Spartan has estimated Original Oil In Place (OOIP) on its Cardium lands at 459 (382.2

net) mmbbl. With vertical and horizontal well development to date the play has

recovered ~20 mmbbl (5.3%). However, even with this amount there is significant oil

still to be recovered. Spartan has been assigned 2P reserves based on a total recovery

factor of 9.8%, or another 17.2 mmbbl left to be recovered. Using other Cardium pools

as analogues we believe a 15% ultimate recovery factor could be achievable on primary

production; translating to a total of 37 mmbbl. Based on this, the lands hold unbooked

reserve potential of 19.8 mmbbl, or nearly 2 times what has already been recovered.

The lands also have potential for waterflood recovery (minimal waterflood has been

implemented here to date). There are several areas of the Pembina pool that have been

exploited with waterflood and estimated recoveries under those schemes are 20% or

higher meaning significant potential exists for Spartan if a similar regime were successful

at Keystone. This said, we would expect waterflood response for this field to takeslightly longer than average since there will be a high voidage replacement requirement

(i.e. need to replace the 20 mmbbl that has been recovered to date).

Spartan’s East Pembina land base also holds a significant advantage in existing

infrastructure. To date, over 250 km of pipelines have been installed in the field. All

wells are pipeline connected so produced fluids are transported with minimal need for

trucking; this lowers operating costs at the field level. Also, the company owns its own

oil and gas treatment facilities capable of handling all production in the area (3,500

bbl/d oil battery and a 20.59 mmcf/d gas plant). Not only does this ensure all oil and gas

production is sold under the most economic scenario, it provides opportunity for third

party processing to boost revenues (associated gas in this play accounts for ~15% of

production so gas handling infrastructure is necessary to produce oil). Based on a 15%

recovery factor of OOIP, we estimate a total horizontal well inventory in this area at

250-300 net to Spartan.





Southeast Saskatchewan – Ceylon, Viewfield, Torquay

Spartan has a sizeable land position at southeast Saskatchewan. In all the company

holds 34,410 net acres of land. The land base is shown in Exhibit 4. Although the

southeast Saskatchewan land base is not as material as Pembina is today (given its

current stage of development) it does provide considerable exploration upside potential

for the company.

Exhibit 4: Spartan Southeast Saskatchewan Land Base


Most of the immediate development focus is at the Torquay land base. The area is welldeveloped with 3D seismic coverage and has a large amount of well control. At Torquay,

the company is expected to have another 15-20 Mississippian horizontal well targets

remaining in inventory.

The Viewfield area is similar to Torquay – the land base is well developed for Bakken oil.

Although there is minimal room for additional horizontal wells, the land base could

become part of a waterflood unit later in development.

The company also holds 21 (10.5 net) sections of Bakken exploration acreage at Ceylon.

The company drilled its first vertical exploration well here in late 2011. Despite not

being frac’d the well has produced 24 bbl/d of oil for 3 months. The company is

following up the discovery with 3 (1.5 net) more wells during 2012 (of which 1 (0.5 net)was drilled during 1Q12; completion scheduled for 2Q12). Although it is still early days

for this exploration acreage, the initial results are encouraging. We expect that by the

end of 2012 the company will have better delineated the potential of this play and we

will be in a position to assess the value it could provide – until then we view this land as

option value.





Corporate Outlook

Throughout 2012, Spartan has laid out a $127 mln capital program that is expected to

see the drilling of 56 (50.1 net) wells. 49 (46.6 net) of these are expected to be Cardium

wells and 7 (3.5 net) are expected to be southeast Saskatchewan wells. Production

guidance is expected to average 2,600-2,800 boe/d and exit guidance has been set at

4,300-4,500 boe/d. The program is expected to be fully funded out of cash flow and

existing bank lines; and based on the current net cash balance of $61 mln, we expect the

company to exit the year with ~$8 mln of net cash and an undrawn $50 mln bank line.





Valuation & Recommendation

Our valuation of Spartan Oil is based on a blend of cash flow multiple and net asset

value. Consistent with the company’s historical trading range since inception and other

oil-weighted junior producers, we have used a target multiple of 6.0x times 2013E cash

flow per share. We combine this with our Risk Adjusted SUPER NAV estimate to arrive at

our target price of $6.25, which is outlined in Exhibit 5. In Exhibit 6 we also show the

implied metrics this translates to for the company.

Exhibit 5: Spartan Target Price Calculation


CFPS (2013E) $1.04 6.0x $6.24 50% $3.12

NAVPS (2012E) $6.05 $6.05 50% $3.03

$6.15

Target Price $6.25 Source: Spartan Oil Corp., Raymond James Ltd.

Exhibit 6: Implied Target Metrics

Natural Gas Oil & NGL Consolidated

Production (2012E) boe/d 426 2,325 2,752


2P Reserves (2011A, mmboe) 21.4

Cash Flow Per Share (2012E, $/share) $0.61


EBITDA (2012E, $mln) $50


Target EV/boe/d (2012E)* $186,060

Target EV/boe/d (2013E)* $108,152

Target EV/boe of 2P Reserves* $23.93

Target EV/EBITDA (2012E)* 10.3x


* Assuming 20 12E Year End Net Debt Source: Raymond James Ltd.

Financial Estimates

Our cash flow estimates assume that the company successfully completes its 2012

capital program of $127 mln. It also assumes that the company drills 49 (46.6 net)

Cardium wells and 7 (3.5 net) southeast Saskatchewan wells. As a result, we assume

that the company achieves an exit rate of ~4,400 boe/d (~20% gas; in-line with guidance

of 4,300-4,500 boe/d) and posts average production of ~2,750 boe/d. For 2013, we

assume the company executes a slightly scaled back program of $115 mln. We havemade this assumption given our lower commodity assumptions, but even with this size

of program we expect the company to exit 2013 with only ~$21 mln of net debt. Our

average production estimate for 2013 is of 4,734 boe/d, with an exit rate of ~6,500

boe/d.

Because of Spartan’s relatively high oil weighting the company generates strong

corporate realized price. We have used an average realized price per boe of $69.87 for

2012 and $68.81 for 2013. Also, since the company has very well established

infrastructure at its Pembina lands, operating costs are low; offset somewhat by slightly





higher royalties because of its higher oil weighting. On a netback basis, the company is

expected to be in the top-tier at $49.78/boe for 2012 and $50.42/boe for 2013. This is

the driving force behind our cash flow estimate of $51 mln ($0.61/share) for 2012 and

$86 mln ($1.04/share) for 2013. Our key operating assumptions are summarized in

Exhibits 7 and 8. These are supplemented by our detailed Financial Summary in

Appendix 1.

Exhibit 7: Key Assumptions

2011E 2012E 2013E

WTI (US$/bbl) $95.13 $91.82 $80.00

Cdn Par ($/bbl) $95.61 $86.00 $78.33

NYMEX (US$/mcf) $4.03 $2.39 $3.25

AECO ($/mcf) $3.55 $2.00 $2.86

FX (US$/C$) $1.02 $0.96 $0.96

Cash Flow ($mln) $11 $51 $86

CFPS (diluted) $0.16 $0.61 $1.04

Production (boe/d) 1,028 2,752 4,734

% Gas 20.2% 15.5% 14.2%

% Growth na 167.6% 72.0%

Capex ($mln) $86 $127 $115

Multiple of Cash Flow 7.66x 2.51x 1.33x

Y/E Net Debt ($mln) ($27) ($8) $21

Debt/Cash flow (T12) -2.4x -0.2x 0.2x


Exhibit 8: Forecasted Production Growth

2011E 2012E 2013E

Oil & NGLs (bbl/d) 821 2,325 183.2% 4,062 74.7%

Natural Gas (mmcf/d) 1.2 2.6 105.6% 4.0 57.6%

Total boe/d 1,028 2,752 167.6% 4,734 72.0%


In our NAV we have assumed development of the company’s Cardium and southeast

Saskatchewan reserves in our Base NAV – this represents the 2P reserves component of

our NAV valuation. We have also taken a risked upside calculation based on incremental

recovery potential from the Cardium lands – this is the risked growth portion of our NAV

calculation. Our resulting NAV is $6.05. This is shown in Exhibit 9.





Exhibit 9: Spartan Net Asset Value (2012E)

Spartan Oil Corp: Year End 2012 NAV EstimateAnalyst: Luc Mageau: Ph. 403-509-0505

Associate: Matthew Stevenson: Ph. 403-509-0518

Base Operations Risk Adjustment

10% A.T. NPV

(C$ m ln) $/Shar e

10% A.T. NPV

( C$ m ln ) $/Sh ar e

Base Gas 100% 3 $0.03 3 $0.03Base Oil 100% 291 $3.49 291 $3.49

Total Reserves NAV 293 $3.52 293 $3.52

Growth NAV

Cardium Grow th NAV 75% 148 $1.78 198 $2.38

Total Growth NAV 148 1.78 198 2.38

Net Debt 62 0.74 62 0.74

Total Corporate Net Asset Value 504 $6.05 553 $6.65

Cur ren t Fu l l y D i l u ted Shares Ou ts tand ing (m lns ) 83.2 83.2

Year End 2012 SUPER NAVPS Estimate $6.05 $6.65

Risking Factor Explanation:100% - 2P Reserves only modelled

90% - Area w ell delineated; resource pool edges mostly well know n; extensions and resource upside less likely

75% - Development in area ongoing; good production base - ex tensions possible w ith exploration60% - Ramp-up of resource in progress ; extensive amount of exploration w ells and some infrastructure in area; total potential not defined

30% - New area of development; minimal infrastructure; s ome exploration wells; relatively new frontier but development seen as near-term

10% - Brand new resource play; productive potential not known

Unrisked NAVPS EstimateRisk Adjusted NAVPS Estimate


In our Base Oil NAV we have assumed the company drills and brings on stream all 149

net wells currently booked in the 2011 reserves report. In all we assume that the 2P

reserves base of 21.43 mmboe is produced out over 13 years. We have also assumed it

takes ~5 years to fully capitalize this reserves base. Although the company is significantly

outspending our Base NAV assumptions for 2012 (our Base NAV assumes spending of

$60 mln for the year), we have assumed the remaining capital to our Growth NAV

component. This assumes that the company works to prove up additional lands, drillingwells not currently booked in its reserve report. For our Growth NAV component, we

have assumed the company is able to achieve a 15% recovery rate from its Cardium

lands (this is reasonable given other mature Cardium pools have recovered >15% on

primary) achieved primarily through in-fill drilling – rather than assuming higher

EUR/well. This represents an incremental 158 net wells (or 19.8 mmbbl) that will

ultimately be drilled and not included in the reserves report. We have assumed a slightly

longer timeline for capitalization (i.e. 8 years) and have risked this value at 75%.

We have not included any unbooked value for the company’s southeast Saskatchewan

assets. Specifically at Ceylon, we see considerable option value not currently captured in

our Base NAV. The company is planning a 3 vertical well exploration program during

2012 (1 drilled in 1Q12, 2 planned for 2Q12) to better define and quantify the potential

on these lands. Although we see considerable potential if the exploration wells aresuccessful, at this point we have elected not to include it in our NAV calculation.

Incorporating our previously discussed capital spending and well type assumptions for

Spartan’s growth areas into our SUPER NAV generates a risk adjusted production profile

for the company – this is shown in Exhibit 10.





Exhibit 10: Spartan Estimated Production Profile (boe/d)

0

2,000

4,000

6,000

8,000

10,000

12,000

2012 2017 2022 2027

Base Gas Base Oil Cardium Growth


Lastly, we have broken down the corporate cash flow generated by our production

profile in Exhibit 11. We have assumed that capital spending (post 2013) is at or less

than total cash flow. This ensures debt is maintained at reasonable levels throughoutthe development horizon without requiring external funding.

Exhibit 11: Spartan Estimated Cash Flows ($ mln)

0

50

100

150

200

2012 2017 2022 2027Base Gas Base Oil Cardium Growth Capital Spend






Appendix 1: Financial Statements

SPARTAN OIL CORP - Financial Summary (C$)

2011A 2012E 2013E

Commodity Price Assumptions

WTI Oil (US$/bbl) $95.13 $91.82 $80.00

Canadian Par (C$/bbl) $95.61 $86.00 $78.33NYMEX Gas (US$/mcf) $4.03 $2.39 $3.25

AECO Gas (C$/mcf) $3.55 $2.00 $2.86

FX (US$/C$) $1.02 $0.96 $0.96

Realized Price

Oil & NGL ($/bbl) $90.70 $79.01 $74.84

Natural Gas ($/mcf) $4.28 $3.34 $5.40

Production

Oil & NGL ($/bbl) 821 2,325 4,062

Natural Gas (mmcf/d) 1.2 2.6 4.0

Total (boe/d 6:1) 1,028 2,752 4,734

% Oil 79.8% 84.5% 85.8%

Growth na 167.6% 72.0%

Production Per Share ( 000s, f.d.) 5.4 12.1 20.8

Netback ($/boe)

Corporate Price $77.58 $69.87 $68.81

Royalties $9.94 $6.77 $6.19

Operating + Transportation Costs $13.08 $11.44 $10.86

Field Operating Netback $48.55 $49.78 $50.42

% Change 30.4% 2.5% 1.3%

Cash Flow ($mln) $11 $51 $86

CFPS ($/share, basic) $0.16 $0.61 $1.04

CFPS ($/share, diluted) $0.16 $0.61 $1.04

Year-end Shares Outstanding (mln)Basic 70.2 83.2 83.2

Diluted 70.2 83.2 83.2

Capital Spending ($mln)

Land & Seismic $4 $3 $1

Dril ling, Completions & Other $17 $107 $108

Well Equipment & Facilities $13 $16 $7

Other $4 $2 $0

Acquisitions $49 $0 $0

Total Capex $86 $127 $115

Capex as a % of Cash Flow 766% 251% 133%

Net debt ($mln)

Net Debt ($27) ($8) $21

Net Debt/CF (T12) (2.4) (0.2) 0.2x

Net Debt/CF (Annualized 4Q) (0.9) (0.1) 0.2x

Net Debt/EV (Market) (0.1) (0.0) 0.1x






SPARTAN OIL CORP - Financial Summary (C$) (Cont'd)

2011A 2012E 2013E

Conventional Reserves - Net Proved Plus Probable

Proved Developed 2.7

Proved Undeveloped 12.1

Probable 6.6Total 2P Reserves (mmboe) 21.4 26.7 31.3

Conventional 2P Finding and Development Costs ($/boe, includes FDC)

Exploration and Development $16.72 $17.00 $17.00

Recycle Ratio (including FDC)

Exploration and Development 2.9x 2.9x 3.0x

Tax Pools ($mln)

Total $116

Multiple of Cash Flow (annualized 1Q11) 2.3x

Net Undeveloped Land (000 Acres)

Southeast Saskatchewan 34,271Alberta 12,631

Total Undeveloped Land 46,902






SPARTAN OIL CORP - Financial Summary (C$) (Cont'd)

2011A 2012E 2013E

Assets ($mln)

Cash and Cash Equivalents $32 $67 $67

Accounts Receivable $11 $11 $11

Prepaid Expense and Other $5 $5 $5Current Assets ($mln) $48 $83 $83

Property, Plant and Equipment $69 $175 $253

Other $10 $10 $10

Total Assets ($mln) $126 $267 $346

Liabilities ($mln)

Accounts Payable $21 $21 $21

Short-term Debt $0 $54 $83

Other Current Liabil ities $0 $0 $0

Current Liabilities ($mln) $21 $75 $103

Long-term Debt $0 $0 $0

Future Income Tax $1 $2 $2Asset Retirement Obligation $4 $4 $4

Other Long-term Liabil ities $0 $0 $0

Total Liabilities ($mln) $25 $80 $109

Shareholders' Equity ($mln)

Share Capital $121 $180 $180

Retained Earnings $9 $37 $86

Accumulated Surplus ($29) ($29) ($29)

Total Shareholders' Equity ($mln) $101 $187 $236

Total Liabilities and S/H Equity ($mln) $126 $267 $346






Appendix 2: Management & Board of Directors

Management

Richard McHardy, B.Comm., LLB. - President & CEO

Mr. McHardy has over 17 years of experience in M&A and securities matters in oil and

gas. Previously he was the President and CEO of Spartan Exploration Ltd., President of

Titan Exploration Ltd. and a Partner at McCarthy Tetrault LLP.

Michelle Wiggins - Vice President, Finance & CFO

Ms. Wiggins has over 20 years of experience in oil and gas. Previous companies include

Titan, Rocky Mountain Energy, CEC Resources, Redux Energy, and Drillwest Resources.

Most recent roles included Vice President Finance & CFO of Spartan Exploration Ltd. and

Vice President, Finance & CFO of Titan Exploration Ltd.

Albert Stark, M. Eng., P.Eng - Vice President, Operations

Mr. Stark has over 18 years of experience in oil and gas. Previous companies include

Titan, Devon, Northstar and Amoco. Most recent roles included Vice President

Operations at Spartan Exploration Ltd., VP Engineering & COO at Titan Exploration Ltd.

and Manager of Prod. & Asset Opt. at Devon Canada

Fotis Kalantzis, P.Geoph., Ph.D. - Vice President, Exploration

Mr. Kalantzis has over 20 years of oil and gas experience with companies including

Innova, Petro-Canada, Aramco, Suncor, Wascana and Home Oil. Most recent roles

included Vice President, Exploration at Spartan Exploration Ltd., Exploration Manager

and Geophysicist at Innova Exploration Ltd., President at FK Geo-Consulting and

Exploration Specialist with Saudi Aramco.

Ed Wong, P. Eng. - Vice President, Engineering

Mr. Wong has over 20 years of oil and gas experience with companies including Samson

and BP Canada/Amoco. Most recent roles have included Vice President, Engineering at

Spartan Exploration Ltd., Hoadley Business Unit Manager at Samson Canada

Resources Ltd. and Area Manager at Samson Exploration Ltd.

Barry McNamara, P. Geol., Ph.D. - Vice President, Development

Mr. McNamara has over 22 years of oil and gas experience with companies including

Chevron, Gulf Canada, Vintage, Innova and Pegasus. Most recent roles have included

Vice President, Geology at Spartan Exploration Ltd., Chief Geologist at Pegasus

Exploration Ltd. and Technical Team Lead at Santos.





Board of Directors

Michael Stark

Chairman

Independent Businessman

Don Archibald

Independent Businessman

Reg Greenslade

President, Tuscany International

Wade Becker

President & CEO, Pinecrest Energy Inc.

Richard (Rick) McHardy

See management write-up

Grant Greenslade

President, Greenslade Consulting Group





Risks

Key risks to Spartan include:

i) Cash flow exposure to fluctuations in energy prices. In this case the company is

specifically exposed to lower oil prices (WTI and Edmonton Par) and gas prices

(HHub and AECO pricing).

ii)

Foreign exchange rates, more specifically the relationship between the Canadianand US dollar.

iii) Due to the nature of its operations, Spartan also faces risks associated with

weather-related interruptions, dry holes, restricted access to facilities, unplanned

pipeline shutdowns and unexpected production delays.

iv) The company is exposed to the risk that there could be unexpected increases in

decline rates specific to its wells or plays. It is also exposed to potentially lower

corporate production volumes, resulting in lower cash flow.

v) Unexpected cost overruns or increasing costs of drilling/completing wells and

infrastructure.

vi) Change in government policies (local, provincial and federal); specifically as it

relates to royalty rates and the treatment of oil and gas production.

vii) Interest rate fluctuations could also negatively impact net income and cash flow.

viii) Some of Spartan’s acreage is non-operated in nature, therefore the company is atrisk of changes in corporate direction by the operator.

Company Citations


BP plc BP NYSE US$ 39.39 1 RJ & Associates

Chevron Corp. CVX NYSE US$ 101.92 1 RJ & Associates

Devon Energy Corporation DVN NYSE US$ 56.70 2 RJ & Associates

Pinecrest Energy Inc. PRY TSXV NC

Samson Oil & Gas Limited SSN NYSE NC

Suncor Energy Inc SU TSX C$ 28.52 2 RJ LTD.Tuscany International Drilling Inc. TID TSX C$ 0.48 2 RJ LTD.



covered.





TriOil Resources Ltd. June 19, 2012

TOL-TSXV Company Report - Initiation of CoverageLuc Mageau CFA | 403.509.0505 | [email protected]



Lochend Cardium Producer with Dunvegan Upside

EventWe are initiating coverage on TriOil Resources with a $3.75 target price and an

Outperform rating.

RecommendationTriOil has assembled a sizeable land position in two oil plays and has had good

success so far. We believe the Lochend land offers excellent exposure to the

Cardium play and the Dunvegan lands hold significant potential for future

value. We recommend clients buy TriOil, but remain at an Outperform rating

due to the early development of the Dunvegan play.

AnalysisTriOil has two major core areas – Lochend Cardium and Kaybob Dunvegan. At

Lochend the company holds 57 net sections of land. This area has been getting

significantly better production results in the Cardium than average and despite

slightly higher costs to drill, it is one of the most economic. TriOil holds a

dominant land position in the play and is well positioned to execute on it. At

Kaybob, the company has recently started developing a Dunvegan oil pool with

horizontal wells. The play (although less than a year old) has been getting

excellent results and the company holds 32.6 net sections in the area. The

company has only 2 wells booked in its reserves here and with 16 (8.5 net)

wells planned during 2012, there is large potential for healthy reserve additions

this year.

At 1Q12 the company had a net cash position of $13 mln and an undrawn bank

line of $50 mln. The company expects to spend $100 mln during 2012, drill 34

(18.3 net) wells and bring production to 3,400-3,600 boe/d by the end of the

year. Using the mid-point, this represents a production growth rate of 50%

from current levels and 80% from the 2011 exit rate of 1,950 boe/d.


a 4.0x times multiple (in-line with the company’s 1.5-year historical trading

range) on our 2013E cash flow per share estimate of $0.93. We have applied a

50% weighting to each in arriving at our target price.

CFPS 1Q 2Q 3Q 4Q Full Revenues NAVPSMar Jun Sep Dec Year (mln)

2011A C$0.05 C$0.07 C$0.08 C$0.10 C$0.31 C$27

2012E 0.09A 0.10 0.15 0.20 0.52 55 3.55

2013E 0.21 0.22 0.24 0.26 0.93 87 na


Rating & Target

Outperform 2


Current Price ( Jun-14-12 ) C$1.85Total Return to Target 103%

52-Week Range C$3.80 - C$1.12

Market Data


Current Net Debt (mln) -C$13






2011A 2012E 2013E

P/CFPS

6.0x 3.5x 2.0x

P/NAV

0.5x na

WTI (US$/bbl)

US$95.13 US$91.82 US$80.00

HHub (US$/mmbtu)

US$4.03 US$2.39 US$3.25

Production (boe/d)

1,287 2,385 3,726

Production: Oil (%)

52% 75% 79%

Capex (mln)

C$37 C$100 C$57

EBITDA (mln)

C$(8) C$27 C$50

Net Debt (mln)

C$(8) C$30 C$36


-0.8x 1.0x 0.7x

Company Description

TriOil Resources is an oil-weighted junior produce

primarily focused on the Cardium at Lochend, with

additional Dunvegan Potential at Kaybob, all in

western Alberta.





Table of Contents






Risks .................................................................................................................................. 66





Investment Overview

Initiating Coverage – Outperform Rating and $3.75 Target Price

We are initiating coverage on TriOil Resources with a $3.75 target price and an

Outperform rating. Our target price represents a return to target of 103% based on the

June 14, 2012 close price of $1.85. Our target price is based on our 2012E Risk Adjusted

SUPER NAV estimate and a 4.0 times multiple on our 2013E cash flow per shareestimate. The multiple is based on the company’s historical trading range over the last

1.5 years, and is in-line with other junior oil-weighted companies in our coverage

universe. Our SUPER NAV estimate assumes development of the company’s Lochend

Cardium land base and development of the Dunvegan oil opportunity at Kaybob.

Exhibit 1: TriOil Target Price Calculation


CFPS (2013E) $0.93 4.0x $3.72 50% $1.86

NAVPS (2012E) $3.55 $3.55 50% $1.78

$3.64

Target Price $3.75


Investment Summary

TriOil has assembled large land positions in two high impact oil plays, which we believe

provides investors with exposure to the potential for rapid near-term production

growth. The company has significantly de-risked its Cardium lands at Lochend,

optimizing its completions along the way, while its Dunvegan assets at Kaybob represent

an earlier stage opportunity with significant option value built in. Other reasons for our

investment thesis are as follows:

• Lochend Wells Outperforming – Relative to other areas of the Cardium play in

Alberta, the Lochend area has been posting the strongest initial production rates.With historical development focused on the ‘B’ sand, there is significant vertical

well control on the Cardium ‘A’ at Lochend despite very low current recovery

factors. Deep wells, good pay thicknesses, and a relatively undepleated reservoir all

point to continued strength in well results from Lochend.

• Kaybob Dunvegan – The company also has 32.6 net sections of land prospective for

Dunvegan light oil at Kaybob. Vertical well control on these lands is strong and

initial wells have posted IP30’s of 101-795 boe/d. While these are very early data

points, they point to the potential for impressive results. The company has

identified an inventory of 42 net locations here and has already drilled 9 (5.8 net)

Dunvegan horizontal wells in 1H12 – pointing to their confidence in the play.

• Financial Strength Drives Growth – At 1Q12, TriOil had a net cash position of $13mln, leaving their bank lines of $50 mln untouched. This amount of financial

flexibility supports the company’s 2012E capital program of $100 mln, and we

expect it could result in ~80% growth in exit production y/y to 3,400 – 3,600 boe/d

by the end of 2012.





Company Overview

TriOil is currently producing ~2,300 boe/d (75% oil and liquids) and is focused in two

areas – Cardium oil at Lochend and the Dunvegan oil at Kaybob. The company has built

up a 57 net section land position at Lochend, which is one of the furthest south areas of

Cardium oil development in Alberta. The area has been delineated with 200+ vertical

wells and the company is now working to increase production using horizontal wells.

The Dunvegan at Kaybob is also an area that has undergone vertical well developmentand the company has started developing the field with horizontal wells. Although the

Dunvegan is an earlier stage play, results so far have been very encouraging.

TriOil went public in January 2010. At that time production was largely gas weighted at

~400 boe/d. Throughout the year the company made a series of asset, corporate and

open land acquisitions to establish its land base. Acquisitions included Canext Energy, a

17 section Lochend undeveloped land acquisition from an intermediate oil and gas

producer, a 14 section land acquisition as well as a gas plant and pipelines at Lochend;

followed by several successful bids in provincial land sales. By August 2010 the company

had amassed its current land position in the Lochend area, as well as its asset base at

Sweeney and Pouce Coupe. Drilling at Lochend began in 2010 and after several wells

being completed with oil-based frac’s the company changed its completion fluid to slick-

water in 2011. The result of which has significantly increased IP rates and wellperformance. In October, 2011 the company announced its Dunvegan Kaybob discovery

and began building up its land position in this second core area. By December the

company had secured its 31.8 net section land position at Kaybob (now owns or has

rights to earn 32.6 net sections).

Asset Overview

Lochend Cardium

This area has been TriOil’s primary focus since mid-2010. The company has assembled a

land base of 82 (57 net) sections (36,480 net acres) over this play. As of May, 2012 there

were ~49 horizontal wells drilled in this area, with 45 of these on stream. The play is the

southern most of the Cardium oil sand bar deposits in our data set, located

approximately due west of Calgary. It shares the same depositional environment as

Garrington, although it is less developed. Similar to other Cardium oil trends, this area

produces oil from the Cardium “A” and “B” sands, with the “B” sand benefiting from the

majority of development so far. A map of the trend, along with TriOil’s land base, is

shown in Exhibit 2.





Exhibit 2: TriOil Lochend Cardium Land Base

Source: TriOil Resources Ltd.

Because the area is less developed than other parts of the Cardium, the amount of

infrastructure is also less. TriOil owns a 5 mmcf/d gas processing facility and gas

pipelines on the northeastern trend. This plant currently processes most of the

associated gas production in the area. TriOil holds a 99% interest in the plant and

expansion discussions are underway with area partners. Oil infrastructure is also less

developed. Most production is currently trucked from single well batteries although a

central battery is expected to be expanded shortly (operated by NAL Energy Corp.) to

accommodate production. Oil can then be transported on the nearby Plains pipelinethat runs through the company’s land base. There are 200+ vertical wells (mostly on the

eastern side of the land base) which have significantly de-risked the development profile

of the play; this is also where most of the horizontal activity has been undertaken to

date. The west side, is far less developed, with little infrastructure and only a handful of

horizontal wells drilled but the couple of wells we have production data on are in-line

with the type curve for the area. The company does not include any locations from this

land base in its location inventory. The first well here (04-12) produced at a 30-calendar

day average rate of 370 boe/d (77% oil) and after 5 months is still producing a 30-day

calendar day rate of 170 boe/d. This is better than our type curve for the area.





We have production data on 34 horizontal wells in this area (source: Geoscout).

Originally oil-based frac’s were used as the completion method of choice here, but when

the company switched to water-based completions production results were materially

better. Since 2011, the company has been using water-based frac’s for well completion

and have 14 wells since then. Calculated and reported IP30’s on 7 wells with sufficient

production time have averaged 211-425 boe/d (excluding the high of 657 boe/d and the

low of 147 boe/d) with decline rates in the first year of 65-70% (in-line for Cardium

wells).

With the vertical and horizontal well control already in hand, TriOil has identified an

inventory of 122 (67 net) horizontal well locations. The company has 18 (9.9 net) wells

planned for 2012 – several of which are targeting new areas of development. So far 5

(2.8 net) wells have been drilled and put on production, 1 (0.4 net) is being drilled, and 1

(0.4 net) is still to be drilled. The 2012 program should significantly de-risk additional

locations, with the northwest portion of the land base (~6 net sections) in particular. We

expect that this could prove up another 24-36 net locations into the inventory.

Kaybob Dunvegan

Since 2011, TriOil owns or has secured rights to earn a 54 (32.6 net) section land base in

the Kaybob area that is prospective for Dunvegan oil. The Dunvegan formation ischaracterized by a delta complex, which means that it has some regional extent. The

formation here has an average pay thickness of 6-8 m, permeability of 1-5 mD and 10-

18% porosity (all good measures by standard resource play metrics). The company

quickly built up its land position in this area over 2011. Exhibit 3 shows a map of the

Kaybob lands.

Exhibit 3: TriOil Kaybob Lands

Source: TriOil Resources Ltd., Raymond James Ltd.

The development of the play has been delineated by several vertical wells producing

from deeper formations. The company drilled its discovery well (a horizontal) in

November, 2011 – a horizontal well (1,200 m horizontal leg) that was put on-stream

with an IP30 of ~800 boe/d (90% oil). During 1H12 the company drilled 9 (5.8 net)

horizontal wells – 8 wells have been tested and 5 have at least 30-days of production

results. The company has released IP30’s from 5 horizontal wells in total. 30-day rates

have ranged from 101-795 boe/d (median of 351 boe/d and a mean of 387 boe/d).





The development of this play – although well-developed vertically – is still early days

from a horizontal perspective. To that end, we expect that good results will mix with

poor results. This will be the result of companies perfecting and tweaking

drill/completion techniques (this is also typical of any oil play). TriOil has been

employing nitrified foam frac’s for its horizontal wells and although success has been

very good so far, there have been 3 wells of 10 drilled (9 from 2012 and 1 from the 2011

discovery) that have had operational difficulties during completion that kept production

from reaching full potential. We believe these results are not indicative of the play,

rather a result of step-out drilling and gaining experience. Details on the wells:

- Well #5: Oil gravity was lower than other wells and the gas-oil-ratio has been

higher than immediately offsetting wells. Early results do not look analogous to

offsetting wells and the company is evaluating the well. Despite this, the IP30

of the well was 101 boe/d.

- Well #6: A damaged frac liner is restricting production rates. The well

encountered 10 m of Dunvegan pay and offsets a well that had an IP30 of 429

boe/d. Well 6 had a test rate of 225 boe/d.

- Well #9: Only half of the horizontal well is under production (an obstruction in

the well is causing production from half of the well to be shut-in). The well hasaveraged ~140 boe/d over the first several weeks despite only being drilled into

2 m of Dunvegan pay.

Outside of these three wells (and excluding the initial well that was significantly better

than average), the average IP30 for TriOil’s wells are ~350 boe/d. On average we expect

the company’s Dunvegan wells to have average IP30’s of 300-400 boe/d and generate

average EUR’s of 250-300 mboe each. They cost ~$4.2 mln (D,C&T), so at US$85 WTI

(our long-term WTI assumption), they would have NPVs in the $3.5 mln - $4.5 mln range

each.

Because of a long history of gas production, this area has very well established gas

infrastructure. Associated gas is produced and pipelined into the K3 or KA plant. Both

plants have significant free capacity to handle increased production. Oil production is

not as well established, although partners in the area (Trilogy Energy is the other major

player in this trend) have entered discussions to build a central facility for current and

future oil production.

Based on wells drilled so far in 1H12, the company is on track for aggressive growth

from this area. In all, TriOil has identified a total well inventory of 42 net locations, of

which only 1 (0.31 net) has been booked in reserves. Based on this we see a large

potential for reserve additions here in 2012. Although large land additions are not likely,

the existing land base holds enough locations to double or triple the company’s current

corporate production base.

Other Areas

The company holds various non-core assets that account for ~6-700 boe/d of production

(~60% natural gas). Notable assets include Montney lands at Pouce Coupe – 12.9 net

sections of land and ~300 boe/d of production (90% gas); Clear Prairie/Sweeney – a

Nordegg/Baldonnel oil play that produces ~250 boe/d (85% oil); and Tableland – 22 net

sections of Midale/Bakken/Sanish that is on the North Dakota/Saskatchewan border,

these lands have been listed for divestiture with bids due in mid-April.





Corporate Outlook

TriOil is planning to spend a total of $100 mln during 2012. The program is expected to

include 34 (18.4 net) horizontal wells, split relatively equally between Lochend and

Kaybob. At Lochend the company plans to drill 18 (9.9 net) Cardium wells and at Kaybob

the plan is for 16 (8.5 net) Dunvegan wells. Based on this budget the company expects

production to average 2,300-2,500 boe/d (82% oil and liquids) and exit the year at

3,400-3,600 boe/d (88% oil and liquids).

Reserves

At year-end 2011 the company had 10.25 mmboe of total 2P reserves booked. Of these,

5.43 mmbbl was oil and NGL based reserves (representing 53%). At Lochend, 2P

Cardium reserves stood at 3.6 mmboe. These reserves were assigned over 21 (9.5 net)

wells. With 67 net wells identified (and significant potential still existing on the west

part of the leases), we see significant upside to this number in future year’s booking. In

the Dunvegan, the company only booked 2 (0.62 net) wells in the reserve report – 1 PDP

and 1 PUD. Based on the results so far, and 9 (5.8 net) wells already drilled during 2012,

we expect this will be a large component of reserve additions for this year.






Our valuation of TriOil Resources is based on a blend of cash flow multiple and net asset

value. Consistent with the company’s 1.5-year historical trading range and other oil

weighted junior producers, we have used a target multiple of 4.0 times 2013E cash flow

per share. We combine this with our Risk Adjusted SUPER NAV estimate to arrive at our

target price of $3.75, which is outlined in Exhibit 4. In Exhibit 5 we also show the implied

metrics this translates to for the company.

Exhibit 4: TriOil Target Price Calculation


CFPS (2013E) $0.93 4.0x $3.72 50% $1.86

NAVPS (2012E) $3.55 $3.55 50% $1.78

$3.64

Target Price $3.75 Source: TriOil Resources Ltd., Raymond James Ltd.










Target EV/boe/d (2012E)* $99,162






Financial Estimates


capital program of $100 mln. Included in this program, we assume that the company

drills 18.5 net wells – 10 net Lochend Cardium wells and 8.5 net Kaybob Dunvegan wells.

This is in-line with the company’s guidance, but we believe that if the Dunvegan results

continue to outperform, some capital will be diverted to this play during 2H12. As a

result of the program, we assume that the company achieves an exit rate of ~3,400boe/d (80% oil; in-line with guidance) and posts average production of ~2,400 boe/d.

For 2013, we assume the company executes a smaller program of $57 mln, including the

drilling of 11 net wells. This is due to our commodity price outlook. This program is

expected to result in average production of ~3,725 boe/d and translate to an exit rate of

~4,200 boe/d.

Because of TriOil’s oil weighting the company generates healthy corporate netbacks. We

have used an average netback of $38.27/boe for 2012. Moving into 2013, despite our

lower commodity price outlook, higher production is expected to translate into lower





operating costs on a $/boe basis. As a result, the company’s corporate netback is

expected to remain approximately flat y/y. These estimates are the driving force behind

our cash flow estimate of $29 mln ($0.52/share) for 2012 and $51 mln ($0.93/share) for

2013. Our key operating assumptions are summarized in Exhibits 6 and 7. These are

supplemented by our detailed Financial Summary in Appendix 1.


2011E 2012E 2013EWTI (US$/bbl) $95.13 $91.82 $80.00

Cdn Par ($/bbl) $95.61 $86.00 $78.33

NYMEX (US$/mcf) $4.03 $2.39 $3.25

AECO ($/mcf) $3.55 $2.00 $2.86

FX (US$/C$) $1.02 $0.96 $0.96

Cash Flow ($mln) $10 $29 $51

CFPS (diluted) $0.31 $0.52 $0.93

Production (boe/d) 1,287 2,385 3,726

% Gas 48.5% 24.7% 20.9%

% Growth 4.7% 85.3% 56.2%

Capex ($mln) $37 $100 $57

Multiple of Cash Flow 3.75x 3.47x 1.11x

Y/E Net Debt ($mln) ($8) $30 $36

Debt/Cash flow (T12) -0.8x 1.0x 0.7x



2011E 2012E 2013E

Oil & NGLs (bbl/d) 663 1,796 170.9% 2,948 64.2%

Natural Gas (mmcf/d) 3.7 3.5 -5.7% 4.7 32.1%

Total boe/d 1,287 2,385 85.3% 3,726 56.2%


In our NAV we have assumed development of the company’s 2P reserves base in our

Base NAV. We have also taken a risked upside calculation based on the company’s

indicated well inventory at Lochend and Kaybob – this is the risked growth portion of

our NAV calculation. Our resulting NAV is $3.55. This is shown in Exhibit 8.





Exhibit 8: TriOil Net Asset Value (2012E)

TriOil Resources: Year End 2012 NAV EstimateAnalyst: Luc Mageau: Ph. 403-509-0505



10% A.T. NPV

(C$ m ln) $/Share

10% A.T. NPV

(C$ mln) $/Shar e

Base Gas 100% 31 $0.57 31 $0.57Base Oil 100% 90 $1.63 90 $1.63


Growth NAV

Lochend Grow th NAV 75% 46 $0.83 61 $1.11Kaybob Grow th NAV 30% 16 $0.28 52 $0.94


Net Debt 13 0.24 13 0.24


Cur r ent Ful l y Di lu ted Shares Outs tandi ng (mln s) 55.1 55.1


Risking Factor Explanation:

100% - 2P Reserves only modelled

90% - Ar ea w ell delineated; resource pool edges mostly w ell know n; extensions and resourc e upside less likely

75% - Development in area ongoing; good production base - extensions possible w ith exploration

60% - Ramp-up of resource in progress ; extensive amount of exploration w ells and some infras tructure in area; total potential not defined

30% - New area of development; minimal infrastruc ture; some exploration w ells; relatively new frontier but development seen as near-term

10% - Brand new r esource play; productive potential not known

Unrisk ed NAVPS EstimateRisk Adjusted NAVPS Estimate


In our base NAV, we assume that the 2P reserves base of 10.2 mmboe is produced out

over 11 years. We have also assumed it takes ~5 years to fully capitalize this reserves

base. Although the company is significantly outspending our Base NAV assumptions for

2012 and 2013 (our Base NAV assumes spending of $40 mln for each year), we have

diverted the remaining capital to our Growth NAV component. This assumes that the

company works to prove up additional lands not currently booked in its reserve report.

For our Growth NAV component, we have assumed the company drills its unbooked

locations (57.5 net) at Lochend. We assume that capitalization of this project takes 7-8

years. Although we believe that significant upside exists to this location number

(particularly given the company’s 57 net sections of land in the area), we have not

quantified it at this point. Instead, we have elected to wait for further delineation to be

completed (particularly on the west side of the land base). We have risked this value at

75%. For the Kaybob Dunvegan lands, we have used the company’s estimated net

prospective sections (14), and have assumed 3 wells/section spacing. This yields a total

well inventory of 42 net wells (of which 2 are booked – 1 PDP and 1 PUD). We have

assumed a similar timeline for capitalization (i.e. 7-8 years), but given the relative

infancy of this play we have elected to risk it at 30%.

We have not included any unbooked value for the company’s Tableland assets in

Saskatchewan (22 net sections of land). Instead, we prefer to view it as option value at

this point (the land is currently listed for divestiture). We have also not included any

unbooked value for Pouce Coupe or Clear Prairie/Sweeney as these properties are not a

focus for the company at this point.






TriOil’s growth areas into our SUPER NAV generates a risk adjusted production profile

for the company – this is shown in Exhibit 9.

Exhibit 9: TriOil Estimated Production Profile (boe/d)

0

2,000

4,000

6,000

8,000

10,000

2012 2017 2022 2027

Base Gas Base Oil Kaybob Growth Lochend Growth



profile in Exhibit 10. We have assumed that capital spending exceeds cash flow for the

first year (i.e. 2012) and only marginally exceeding cash flow for the second (i.e. 2013),

but is restrained to within cash flow afterward. Based on this we assume debt increases

to $36 mln by exit 2013 (or 0.7x D/CF).

Exhibit 10: TriOil Estimated Cash Flows ($ mln)

0

50

100

150

2012 2017 2022 2027Base Gas Base Oil Kaybob Growth Lochend Growth Capital Spend







TRIOIL RESOURCES LTD - Financial Summary (C$)

2011A 2012E 2013E


WTI Oil (US$/bbl) $95.13 $91.82 $80.00

Canadian Par (C$/bbl) $95.61 $86.00 $78.33

NYMEX Gas (US$/mcf) $4.03 $2.39 $3.25

AECO Gas (C$/mcf) $3.55 $2.00 $2.86

FX (US$/C$) $1.02 $0.96 $0.96

Realized Price

Oil & NGL ($/bbl) $87.51 $80.04 $75.83

Natural Gas ($/mcf) $3.95 $2.16 $3.06

Production

Oil & NGL ($/bbl) 663 1,796 2,948


Total (boe/d 6:1) 1,287 2,385 3,726

% Oil 51.5% 75.3% 79.1%Growth 4.7% 85.3% 56.2%


Netback ($/boe)

Corporate Price $56.58 $63.48 $63.84

Royalties $8.26 $9.22 $8.30



% Change 63.9% 25.8% 4.9%

Cash Flow ($mln) $10 $29 $51

CFPS ($/share, basic) $0.31 $0.52 $0.93


Year-end Shares Outstanding (mln)

Basic 43.2 55.1 55.1

Diluted 43.2 55.1 55.1



Dril ling, Completions & Other $27 $76 $47


Other $1 $0 $0


Total Capex $37 $100 $57


Net debt ($mln)Net Debt ($8) $30 $36

Net Debt/CF (T12) (0.8) 1.0x 0.7x

Net Debt/CF (Annualized 4Q) (0.6) 0.7x 0.6x

Net Debt/EV (Market) (0.1) 0.2x 0.3x






TRIOIL RESOURCES LTD - Financial Summary (C$) (Cont'd)

2011A 2012E 2013E









Tax Pools ($mln)

Total $255


Net Undeveloped Land (000 Acres)

Alberta 82,164Saskatchewan 14,301

British Columbia 6,093







TRIOIL RESOURCES LTD - Financial Summary (C$) (Cont'd)

2011A 2012E 2013E

Assets ($mln)





Other $0 $35 $35


Liabilities ($mln)



Other Current Liabil ities $2 $3 $3




Other Long-term Liabil ities $8 $8 $8




Retained Earni ngs ($89) ($85) ($69)

Accumulated Surplus $6 $9 $11









Management

Russell J. Tripp, LLB, P. Land – President, CEO and Director

Mr. Tripp has over 30 years of oil and gas experience, including leadership roles with a

number of public companies. Mr. Tripp was the founding CEO and Director of TriGas

Exploration Ltd., Bear Creek Energy Ltd., Ketch Resources Trust, Bear Ridge Resources

Ltd., and TriOil Resources Ltd.

Andrew Z. Wiacek, M.Sc., P. Geoph. – VP, Exploration

Mr. Wiacek was instrumental in the discovery of a number of significant unconventional

tight gas resource plays while in a management role at Rocor Resources Inc., Bear Ridge

Resources Ltd., Ketch Resources Trust, and Bear Creek Energy Ltd. Mr. Wiacek has over

20 years of experience, and was most recently Vice President and Chief Geophysicist at

Rocor Resources Inc. He is a founding executive of TriOil Resources Ltd.

Shaun Wyzykoski, P. Eng. – VP, Engineering

Mr. Wyzykoski is a Professional Engineer with over 15 years of oil and gas experience.

Most recently, Mr. Wyzykoski was a founding member and Vice President Engineering

of Fairmount Energy Inc., and prior thereto held positions with Crescent Point Energy

Trust and Compton Petroleum Inc.

Craig Haavardsrud, B. Comm. – VP, Business Development and Land

Mr. Haavardsrud is a landman with over 14 years of corporate development and land

experience. Most recently, Mr. Haavardsrud was a founding member and VP, Land of

Fairmount Energy Inc., and prior thereto held various land and property acquisition roles

with Crescent Point Energy Trust, Vintage Petroleum and Petro-Canada Oil and Gas Ltd.

Cheryne Lowe, CA, MPAcc – VP, Finance & CFO

Ms. Lowe has 9 years of experience in oil and gas, capital markets, and public

accounting. Most recently, Ms. Lowe was Manager, Financial Reporting at Highpine Oil

and Gas, and prior thereto held progressively senior roles at Anderson Energy, Tristone

Capital, Ketch Resources Trust and KPMG LLP.

Keith Mychaluk, MBA, P. Geol. - Exploration Manager

Mr. Mychaluk has over 16 years of Western Canada exploration and acquisition

experience, predominantly in tight gas resource plays with start-up and junior

companies, including Birchcliff Energy Ltd., Blizzard Energy Ltd., Baytex Energy Ltd. and

Petromet Resources Ltd.





Board of Directors

Russell J. Tripp

See management write-up

Glenn Hockley

Mr. Hockley is a registered Professional Geologist and an independent businessman

with over 35 years of experience in oil and gas. Mr. Hockley was the CEO of Eravista

Energy Ltd. from November 1998 to February 2004 and Chairman, director and memberof the Audit Committee of Aquest Energy Ltd. from February 2004 to August 2005.

Andy Mah

Mr. Mah is a registered Professional Engineer and a member of APEGGA with over 28

years of experience in oil and gas. Mr. Mah has been the CEO and a director of

Advantage Oil & Gas Ltd. since January 2009. Mr. Mah was the President and COO and a

director of Advantage Oil and Gas Ltd. and its predecessors since June 2006. Prior

thereto, Mr. Mah was President of Ketch Resources Trust from September 2005 until

June 2006, and was COO since January 2005. From 1998 to 2005, Mr. Mah was the

Executive Officer and VP, Engineering and Operations of Northrock Resources Ltd.

Paul McGarvey

Mr. McGarvey is an independent businessman specializing in investments in the energy

sector. Mr. McGarvey was a founder and President of Resource Capital Partners. He was

a marketing equity analyst covering E&P companies for Newcrest (now TD Newcrest)

where he was a director, Griffiths McBurney (now GMP) where he was a founding

partner, Goepel Shields (now Raymond James) and Nesbitt Thompson (now BMO

Nesbitt Burns). Prior thereto, he worked in the oil and gas industry and in the

automotive industry as a research and development engineer. Mr. McGarvey has a

Bachelor of Mechanical Engineering and a Masters of Industrial Engineering, both from

University College Dublin, Ireland.

Glen Gretzky

Mr. Gretzky is an independent businessman. Mr. Gretzky is the Executive Director of the

Wayne Gretzky Foundation, Executive Director of the Ford Wayne Gretzky Gold Classic,and Director or Wayne Gretzky Estates Winery.

Korby Zimmerman

Mr. Zimmerman is a landman with over 18 years of experience in oil and gas. Mr.

Zimmerman has been the VP, Business Development and Land, and a director of

PineCrest Energy Inc. since May 2010. Mr. Zimmerman has been an officer of two

publicly traded companies, most recently filling role of VP, Land and Business

Development of Ketch Resources Ltd., administrator to Ketch Resources Trust. Mr.

Zimmerman has a Bachelor of Commerce from the University of Calgary.

Robert Herdman

Mr. Herdman is a Chartered Accountant with over 35 years of financial experience. Mr.

Herdman was a partner of PricewaterhouseCoopers in Calgary for 21 years and retired

in 2010. Mr. Herdman currently serves as Chair of the Audit Committee on the Board of

Directors of four other public companies. Mr. Herdman also serves on the Board of

Governors of the Glenbow Museum and has extensive volunteer experience with the

Institute of Chartered Accountants of Alberta.





Risks

Key risks to TriOil include:




ii)


iii) Due to the nature of its operations, TriOil also faces risks associated with weather-

related interruptions, dry holes, restricted access to facilities, unplanned pipeline

shutdowns and unexpected production delays.



corporate production volumes, resulting in lower cash flow. Some of the company’s

operations are in unexplored/less explored areas and the risk for dry holes or lower

production wells could be higher. For TriOil, this specifically relates to the western

portion of the Lochend Cardium lands and some of the Kaybob Dunvegan play.


infrastructure.

vi) Change in government policies (local, provincial and federal); specifically as itrelates to royalty rates and the treatment of oil and gas production.


viii) Some of TriOil’s acreage is non-operated in nature, therefore the company is at risk

of changes in corporate direction by the operator. The company is also at risk of

higher funding requirements if operators in the area increase the number of wells

to drill.

Company Citations


Advantage Oil & Gas Ltd. AAV TSX C$ 2.92 2 RJ LTD.Anderson Energy Ltd. AXL.T TSX NC

Bank of Montreal BMO NC

Baytex Energy Corp. BTE TSX C$ 43.50 2 RJ LTD.

Birchcliff Energy Ltd. BIR TSX C$ 6.04 3 RJ LTD.

Compton Petroleum CMT TSX C$ 1.39 UR RJ LTD.

Crescent Point Energy CPG TSX C$ 39.97 3 RJ LTD.

GMP Capital Inc. GMP.T TSX NC

NAL Energy Corporation NAE.T TSX NC

Pinecrest Energy Inc. PRY.V TSXV NC

The Toronto-Dominion Bank TD.T TSX NC

Triology Energy Corp. TET.T TSX NC

Notes: Prices are as of the most recent close on the indicated exchange and may not be in US$. See Disclosure section forrating definitions. Stocks that do not trade on a U.S. national exchange may not be approved for sale in all U.S. states. NC=not

covered.





Vero Energy Inc. June 19, 2012

VRO-TSX Company Report - Initiation of CoverageLuc Mageau CFA | 403.509.0505 | [email protected]


Junior Oil & Gas ProducersRevitalized and Focusing on the Cardium

EventWe are initiating coverage on Vero Energy with a $3.25 target price and an

Outperform rating.

RecommendationFollowing the disposition of its gas assets, Vero has successfully re-positioned

itself as a Cardium focused oil producer. A large land base in the Edson area

(where recent results have been strong) is expected to help the company grow

production over the next several years and we believe that the company offers

good long-term value for that reason.

AnalysisOn January 3, 2012 Vero completed the sale of its gas assets representing 7,296

boe/d of production. Since that time the company has been a pure-play

Cardium producer. The company’s land base covers 111 net sections and spans

the Edson trend, where recent results have been strong. Although this area is

not as well developed for horizontal wells (it is a relatively large land area with

35.4 net horizontal Vero wells drilled so far), results have been good and have

shown improving rates y/y. In particular, the company’s move to slick-water

frac’s and tighter frac intervals late in 2011 has been a step change for

production results. Also, with minimal reserves currently booked in the area,

we expect several years of strong reserves booking as the company works to

delineate the Cardium potential here.

We expect 2012 will continue to be a transformational year for Vero. The

company plans to drill 28-30 (16-17 net) wells (up to 50% of these are expected

to be drilled where no reserves are currently booked) and this should increase

production to 3,000-3,300 boe/d by the end of the year. This translates to an

impressive y/y increase in average 4Q production of 78% (based our 4Q12

estimates and the estimated average 4Q11 production rate of 1,634 boe/d).


a 4.0x times multiple (in-line with the company’s 2-year historical trading

range) on our 2013E cash flow per share estimate of $0.94. We have applied a

50% weighting to each in arriving at our target price.

Cash 1Q 2Q 3Q 4Q Full Revenues NAVPS

Flow/Share Mar Jun Sep Dec Year (mln)

2011A C$0.34 C$0.39 C$0.31 C$0.28 C$1.34 C$127

2012E 0.14A 0.14 0.17 0.19 0.66 57 2.82

2013E 0.22 0.21 0.24 0.25 0.94 68 na


Rating & Target

Outperform 2



52-Week Range C$5.76 - C$1.66

Market Data


Current Net Debt (mln) C$24






2011A 2012E 2013E

P/CFPS

1.5x 3.0x 2.1x

P/NAV

0.7x na

WTI (US$/bbl)

US$95.13 US$91.82 US$80.00

HHub (US$/mmbtu)

US$4.03 US$2.39 US$3.25

Production (boe/d)

9,238 3,090 3,373

Production: Oil (%)

24% 57% 67%

Capex (mln)

C$119 C$(128) C$51

EBITDA (mln)

C$(32) C$24 C$42

Net Debt (mln)

C$(19) C$33 C$38


-0.3x 1.0x 0.8x

Company Description

Vero is a Cardium focused, oil-weighted junio

producer with a total Cardium land position of 111 ne

sections focused along shoreline trends to the north o

the Pembian field.





Table of Contents






Risks .................................................................................................................................. 82





Investment Overview


We are initiating coverage on Vero with a $3.25 target price and an Outperform rating.

Our target price represents a return to target of 66% based on the June 14, 2012 close

price of $1.96. Our target price is based on our 2012E Risk Adjusted SUPER NAV

estimate and a 4.0x times multiple on our 2013E cash flow per share estimate. Themultiple is based on the company’s 2-year historical trading range, and is in-line with

other junior oil-weighted companies in our coverage universe. Our SUPER NAV estimate

assumes development of the company’s Cardium acreage at Edson/Carrot Creek/West

Pembina.

Exhibit 1: Vero Target Price Calculation


CFPS (2013E) $0.94 4.0x $3.76 50% $1.88

NAVPS (2012E) $2.82 $2.82 50% $1.41

$3.29

Target Price $3.25


Investment Summary

After disposing of its natural gas-focused assets in early 2012, Vero has emerged as a

pure-play Cardium light oil producer. The company has a large amount of land relative

to its production base and offers investors concentrated exposure to an extensive

unbooked oil inventory in an emerging portion of the unconventional Cardium resource

play. In addition, the company has been continually improving well results from the

Cardium and has the financial flexibility to fund a strong production growth profile over

the near-term. Other reasons for our investment thesis are as follows:

• Cardium Inventory – With 111 net sections of Cardium lands, primarily focused onhalo acreage to the north of Pembina, the company has a large inventory of 220

(123 net) horizontal Cardium oil locations. With only ~20% of these locations

booked in the company’s reserves, it provides investors with exposure to a

significant amount of oil resource upside as the company delineates its land base

and de-risks further locations.

• Well Results Improving – The northern portion of the Cardium play is still early in

development and completions continue to be optimized. Since Vero adopted slick-

water fracs and tighter inter-frac spacing, the company’s average Cardium well

results have improved materially, representing some of the best results to date in

the area. Wells brought on stream since October, 2011 have achieved an average

IP30 of ~240 boe/d (over 6 wells), a significant improvement y/y when IP rates were

averaging ~140 boe/d.





Company Overview

Vero Energy was started in late 2005. The company was formed as a spin-out entity

from True Energy Trust. Vero at that time was primarily a west central Alberta focused

company producing ~1,000 boe/d. In early 2006 the company acquired a similar sized

junior producer (Ledge Resources), bringing its total production to ~2,000 boe/d and

increasing its presence in west central Alberta. Since then the company has successfully

grown production organically, without any other significant acquisitions. In 2011 totalcorporate production had increased to 9,238 boe/d (~75% natural gas).

On January 3, 2012 the company announced the disposition of its natural gas focused

assets to a private company. The disposition included 7,296 boe/d of production (86%

natural gas), 26.5 mmboe of reserves, all deep basin lands, facilities and west central

Alberta lands (excluding surface to base Cardium rights). The transaction gave Vero net

proceeds of $196 mln, which was used to settle all outstanding debt and make a

$0.30/share distribution to shareholders. Post-disposition, Vero became a pure-play

Cardium producer with land and production at West Pembina, Carrot Creek, and Edson.

Total production was ~1,600 boe/d (67% oil and liquids) and the company had an

unutilized $45 mln bank line (now increased to $65 mln) to fund its capital program.

Asset Overview

Edson/Carrot Creek/West Pembina Cardium

Vero holds a total of 174 (111 net) sections of land along the Edson/Carrot Creek/West

Pembina fairway. The land is extensively delineated with existing vertical wells (both

producing from the Cardium and wells with by-passed pay producing from other zones)

and Vero has drilled a total of 46 (35.4 net) horizontal wells to date. Based on this well

control data, the company has established a 220 (123 net) horizontal Cardium well

inventory. A map of the company’s land base in this area is shown in Exhibit 2.

Exhibit 2: Vero Cardium Land Base

Source: Vero Energy Inc., Raymond James Ltd.





Vero’s Cardium lands are primarily characterized by halo-style drilling. Several blocks are

100%, but the company does share some working interest with Vermilion Energy,

PetroBakken Energy, and Torc on some West Pembina lands (closer to the main

Pembina pool), as well as Torc and Direct Energy in Edson.

Vero originally started development of the lands in 2009. At that time they were

producing 262 boe/d (28% oil and liquids) from the area. Since then, the company has

grown production to ~2,475 boe/d (71% oil and liquids) in May 2012 and expects to

average 2,500-2,700 boe/d (70% oil and liquids) for 2012 – a y/y increase of 80%. To

date the company has drilled 46 (35.4 net) horizontal Cardium wells over its land base,

successfully identifying and de-risking future areas of Cardium development. Currently

the company has a horizontal well inventory of 220 (123 net) locations – 176 (99 net) of

which are not currently booked in reserves.

Well results have shown continuous improvement over time. Based on wells Vero has

drilled to date, the average IP30 of its Cardium wells pre-June, 2011 (when slick-water

fracs became more prevalent) was ~140 boe/d. Rates have improved significantly since

that time – using just these wells the company has posted an average IP30 of ~190

boe/d. Using just wells drilled after October, 2011, IP30s increase even further to 240

boe/d. Horizontal well results from this area have also had considerable variation, but

given the large land base that these wells cover this is not surprising to us. Also, sincenewer wells have used water based frac’s in the completion process, there is a tendency

for these wells to show a “clean-up” effect (where month 2 or month 3 production rates

are higher than month 1). Exhibit 3 shows the company’s well results to date in the

Cardium. The Exhibit shows that wells brought on stream after June, 2011 show a

marked increase in average performance – attributable to optimization of completions.

Exhibit 3: Vero Cardium Well Results Pre-June 2011 versus Post-June 2011

0.0

1.0

2.0

3.0

4.0

5.0

0

60

120

180

240

300


O i l P r o d u c t i o n ( b b l / d ) & T o t

a l P r o d u c t i o n ( b o e / d )

0

5

10

15

20

25

30

35

40

0 6 12 18 24



Selection 1

Selection 2*

Source: Raymond James Ltd., GeoScout

The Edson area has been commercially developed for some time. As a result

infrastructure is generally well established. Major gas pipelines have available room and

gas processing plants have significant spare capacity so processing oil and gas volumes is

easily accommodated.





Of the 220 (123 net) locations identified in inventory, Vero has only booked 47 (24 net),

or ~20% of total identified inventory. The company is also in early stages of delineation

and has only included wells into inventory that have offsetting production to confirm

productivity. Based on the 111 net sections of land, there is likely significant upside to

the inventory and reserves numbers booked today. On the inventory side, we believe a

total number of over 200 net wells is possible. This would represent nearly a 100%

growth to the current inventory. We also see immediate upside potential to the

reserves numbers for 2012. With a focused Cardium program this year the company is in

a good position to grow reserves materially. In 1Q12 alone the company drilled 3.9 net

wells where no associated reserves have been booked. The company estimates that this

drilling alone could potentially add 10.1 net locations to the reserves base in 2012.

Based on Sproule’s type curve for the area (similar to Vero’s average booking for 2011),

we calculate that this would amount to 1.4 mmboe of incremental reserves (or an

increase of 15% to the current reserves base).

Corporate Outlook

For 2012 Vero has planned a $62.5 mln capital program focused on drilling its Cardium

lands. The program is expected to include utilization of 2 rigs and 28-30 (16-17 net)

Cardium horizontal wells. The company exited 2011 at ~1,800 boe/d, but with this

program the company has set exit guidance for 2012 at 3,000-3,300 boe/d (70% liquids).

This translates to a y/y growth rate in fourth quarter average production of 78% (using

our estimate for 4Q12) and a capital efficiency of ~$34,000/boe/d. Corporate

production in 1Q12 increased to 2,167 boe/d (69% oil and liquids) and production in

May, 2012 increased further to 2,475 boe/d (71% liquids). Based on this, the company is

on-track to meet or exceed its guidance targets in our view.






Our valuation of Vero is based on a blend of cash flow multiple and net asset value.

Consistent with the company’s 2-year historical trading range and other oil weighted

junior producers, we have used a target multiple of 4.0 times 2013E cash flow per share.

We combine this with our Risk Adjusted SUPER NAV estimate to arrive at our target

price of $3.25, which is outlined in Exhibit 4. In Exhibit 5 we also show the implied

metrics this translates to for the company.

Exhibit 4: Vero Target Price Calculation


CFPS (2013E) $0.94 4.0x $3.76 50% $1.88

NAVPS (2012E) $2.82 $2.82 50% $1.41

$3.29

Target Price $3.25 Source: Vero Energy Inc., Raymond James Ltd.



Production (2012E) boe/d 1,314 1,776 3,090

Production (2013E) boe/d 1,105 2,268 3,373












Financial Estimates


capital program of $62.5 mln. It also assumes that the company drills 28-30 (16-17 net)

Cardium wells. As a result, we assume that the company achieves an exit rate of ~3,000

boe/d (~70% oil; in-line with guidance of 3,000-3,300 boe/d) and posts average

production of ~2,500 boe/d (excluding pre-disposition volumes included in 1Q12

results). For 2013, we assume the company executes a slightly smaller program than2012 – resulting in average production of 3,400 boe/d and an exit rate of ~3,700 boe/d.

Because of Vero’s higher oil weighting, the company generates above average corporate

realized prices. The company also has lower operating costs which is somewhat offset

by slightly higher gas-cuts from its Cardium wells. Based on our price deck, we expect

the company to post corporate netbacks of ~$35.99/boe for 2012, and $39.55/boe for

2013 (the 2013 netback increases due to a higher oil production mix). This netback is

expected to generate cash flow of $33 mln ($0.66/share) for 2012 and $46 mln

($0.94/share) for 2013. Our key operating assumptions are summarized in Exhibits 6 and

7. These are supplemented by our detailed Financial Summary in Appendix 1.






2011E 2012E 2013E

WTI (US$/bbl) $95.13 $91.82 $80.00

Cdn Par ($/bbl) $95.61 $86.00 $78.33

NYMEX (US$/mcf) $4.03 $2.39 $3.25

AECO ($/mcf) $3.55 $2.00 $2.86

FX (US$/C$) $1.02 $0.96 $0.96

Cash Flow ($mln) $66 $33 $46

CFPS (diluted) $1.34 $0.66 $0.94

Production (boe/d) 9,238 3,090 3,373

% Gas 75.9% 42.5% 32.8%

% Growth 8.4% -66.5% 9.1%

Capex ($mln) $119 ($128) $51

Multiple of Cash Flow 1.82x -3.94x 1.10x

Y/E Net Debt ($mln) ($19) $33 $38

Debt/Cash flow (T12) -0.3x 1.0x 0.8x



2011E 2012E 2013E

Oil & NGLs (bbl/d) 2,226 1,776 -20.2% 2,268 27.7%

Natural Gas (mmcf/d) 42.1 7.9 -81.3% 6.6 -15.9%

Total boe/d 9,238 3,090 -66.5% 3,373 9.1%


In our NAV we have assumed development of the company’s reserves in our Base

component – this represents the 2P reserves portion of our NAV valuation. We have

also taken a risked upside calculation based on the number of locations on the

company’s Cardium land base that are not included in the 2P reserves base – this is therisked growth portion of our NAV calculation. Our resulting NAV is $2.82. This is shown

in Exhibit 8.





Exhibit 8: Vero Net Asset Value (2012E)Vero Year End 2012 NAV EstimateAnalyst: Luc M ageau: Ph. 403-509-0505



10% A.T. NPV

(C$ m ln) $/Shar e

10% A.T. NPV

( C$ m ln) $/Sh ar e

Base Gas (Most Associated w ith Oil) 100% 10 $0.21 10 $0.21ase . .


Growth NAVCardium Grow th NAV 75% 22 $0.45 29 $0.59


Net Debt (24) -0.49 (24) -0.49


Cur ren t Fu l l y D i l u ted Shares Ou ts tand ing (m lns ) 49.0 49.0




90% - Area w ell delineated; resource pool edges mostly w ell know n; extensions and resource upside less likely

75% - Development in area ongoing; good production base - extensions possible w ith exploration

60% - Ramp-up of r esource in progress; extensive amount of exploration wells and some infras tructure in area; total potential not defined30% - New area of development; minimal infrastr ucture; some exploration w ells; relatively new frontier but development seen as near-term


Unrisked NAVPS EstimateRisk Adjusted NAVPS Estimate


In our Base Oil NAV we have assumed the company drills and brings on stream all 24 net

Cardium wells currently booked in the 2011 reserves report. In all, we assume that the

2P reserves base of 9.0 mmboe is produced out over 11 years. We have also assumed it

takes ~3 years to fully capitalize this reserves base. Although the company is

outspending our cash flow expectations for this year, only a portion of that is going

toward capitalizing the reserves base. The remainder of the capital is used to capitalize

the Growth NAV component. In this component, we have assumed the company drills

the 99 net unbooked locations currently in inventory (although we believe the ultimatenumber of well locations on the land base could be higher than this, we have not

quantified this in our NAV at this point). Based on this, we have assumed that an

incremental 8.0 mmboe is recoverable that that is not currently included in the reserves

report. We have assumed this takes ~4-5 years to capitalize and we have risked this

value at 75%.


Vero’s growth areas into our SUPER NAV generates a risk adjusted production profile for

the company – this is shown in Exhibit 9.





Exhibit 9: Vero Estimated Production Profile (boe/d)

0

2,000

4,000

6,000

2012 2017 2022 2027

Base Gas Base Oil Cardium Growth



profile in Exhibit 10. We have assumed that capital spending outstrips cash flow for

2012 and only marginally for 2013, but is constrained by cash from then on. Based onthis, our 2013E exit net estimate stands at $38 mln, or 0.8x trailing D/CF.

Exhibit 10: Vero Estimated Cash Flows ($ mln)

0

50

100

2012 2017 2022 2027Base Gas Base Oil Cardium Growth Capital Spend







VERO ENERGY INC - Financial Summary (C$)

2011A 2012E 2013E


WTI Oil (US$/bbl) $95.13 $91.82 $80.00


NYMEX Gas (US$/mcf) $4.03 $2.39 $3.25

AECO Gas (C$/mcf) $3.55 $2.00 $2.86

FX (US$/C$) $1.02 $0.96 $0.96

Realized Price

Oil & NGL ($/bbl) $81.29 $76.70 $72.89

Natural Gas ($/mcf) $3.96 $2.35 $3.11

Production

Oil & NGL ($/bbl) 2,226 1,776 2,268


Total (boe/d 6:1) 9,238 3,090 3,373

% Oil 24.1% 57.5% 67.2%Growth 8.4% -66.5% 9.1%


Netback ($/boe)

Corporate Price $37.62 $50.09 $55.13

Royalties $4.26 $4.45 $5.34



% Change 8.6% 52.7% 9.9%

Cash Flow ($mln) $66 $33 $46

CFPS ($/share, basic) $1.34 $0.66 $0.94



Diluted 49.0 49.0 49.0



Drilling, Completions & Other $103 $56 $46


Other $0 $0 $0

Acquisitions ($6) ($190) $0

Total Capex $119 ($128) $51

Capex as a % of Cash Flow 182% -394% 110%

Net debt ($mln)

Net Debt ($19) $33 $38

Net Debt/CF (T12) (0.3) 1.0x 0.8x

Net Debt/CF (Annualized 4Q) (0.3) 0.9x 0.8x

Net Debt/EV (Market) (0.2) 0.3x 0.3x






VERO ENERGY INC- Financial Summary (C$) (Cont'd)

2011A 2012E 2013E






Exploration and Development na $16.00 $16.00


Exploration and Development 2.2x 2.5x

Tax Pools ($mln)

Total $143


Land Base (000 Acres)

Gross Cardium Land 111,360 Net Cardium Land 71,040






VERO ENERGY INC - Financial Summary (C$) (Cont'd)

2011A 2012E 2013E

Assets ($mln)





Other $20 $14 $10


Liabilities ($mln)



Other Current Liabilities $19 $1 $1




Other Long-term Liabilities $0 $0 $0




Retained Earnings ($69) $9 $29










Management

Doug Bartole – President and CEO

Mr. Bartole has been President and CEO since inception in November 2005. From 2001

to 2005 Mr. Bartole held various positions with True Energy with his latest being VP,

Operations. From 1997 to 2000 Mr. Bartole held various positions with Renaissance

Energy Ltd. which subsequently became a part of Husky Oil Ltd. During his tenure heincreased his overall responsibilities with ultimate direction of an area of 30,000 boe/d.

Prior, Mr. Bartole worked with Pan Canadian Petroleum since 1992 and prior thereto

held various operational positions with major and junior oil and gas companies. He

received a B.Sc. in Engineering from the University of Alberta in 1992 and a diploma in

Petroleum Technology from SAIT in 1986.

Kevin Yakiwchuk – VP, Exploration

Mr. Yakiwchuk joined Vero at its inception in November 2005. Prior to joining Vero, Mr.

Yakiwchuk had various positions with True Energy from 2001 to 2005 with the latest as

VP, Exploration. In April of 2000, Mr. Yakiwchuk was a Geologist at Crestar Energy Inc.

and prior to that at Renaissance Energy Ltd. from December 1996. Mr. Yakiwchuk

completed his B.Sc. Geology in 1992 and M.Sc. Geology in 1994 at the University of

Alberta.

R.S. (Bob) Bachynski – VP, Land

Mr. Bachynski has over 22 years of experience in all facets of petroleum and natural gas

land management ranging from mineral negotiations to surface operations. Mr.

Bachynski has held management positions for various oil and gas exploration companies

in western Canada most recently for the past four years as Land Manager of Apache

Canada. Prior Mr. Bachynksi worked for Forest Oil, Serenpet, and started with Home Oil

in 1982. Mr. Bachynski is a licensed Alberta Land Agent.

Gerry Gilewicz – VP, Finance and CFO

Mr. Gilewicz joined Vero in November of 2005. Mr. Gilewicz is a Certified Management

Accountant (CMA) and has been the CFO of a junior oil and gas company for the past sixyears. Prior to that he was a Senior Manager in the tax group of Deloitte & Touche LLP

providing tax planning and compliance services to resource based corporations and

income trusts. Before that Mr. Gilewicz was an Audit Manager with Canada Revenue

Agency conducting audits of, or providing guidance to, a team of auditors reviewing the

operations of large multi-national resource based companies. Mr. Gilewicz also holds a

Bachelor of Commerce from the University of Saskatchewan.

Shane Manchester – VP, Operations

Mr. Manchester joined Vero Energy April 1, 2006 as VP, Operations. Mr. Manchester has

over 12 years of industry experience including time with Renaissance Energy Ltd., Husky

Energy Ltd., and National Fuel Exploration Corporation. He most recently served the role

of Production and Engineering Manager at True Energy Trust. He received a B.Sc. in

Engineering from the University of Saskatchewan in 1995 and a diploma in

Instrumentation Engineering Technology from Northern Alberta Institute of Technology

in 1990.





Board of Directors

Paul R. Baay (Chairman) – Managing Director, Abacus Energy; Chairman of the Vero

Energy Inc. since November 1, 2005.

Clinton T. Broughton, P. Eng – EVO of True Energy Trust; Director of Vero Energy Inc.

since November 1, 2005.

Douglas J. Bartole, P. Eng – See management section.

Kenneth P. Acheson, C.A. – President, Kennington Properties Ltd; Director of Vero

Energy Inc. since November 1, 2005.

Paul C. Allard, B.A., M.B.A. – Principal, DIA Holdings Ltd; Director of Vero Energy Inc.

since March 29, 2010.

Robert G. Rowley – Businessman; Director of Vero since August 31, 2000.





Risks

Key risks to Vero include:




ii)


iii) Due to the nature of its operations, Vero also faces risks associated with weather-

related interruptions, dry holes, restricted access to facilities, unplanned pipeline

shutdowns and unexpected production delays.





production wells could be higher.


infrastructure.

vi) Change in government policies (local, provincial and federal); specifically as it

relates to royalty rates and the treatment of oil and gas production.vii) Interest rate fluctuations could also negatively impact net income and cash flow.

viii) Some of Vero’s acreage is non-operated in nature, therefore the company is at risk

of changes in corporate direction by the operator. The company is also at risk of


to drill.

Company Citations


Apache Corporation APA NYSE US$ 86.01 1 RJ & Associates

Forest Oil Corp. FST NYSE US$ 7.20 3 RJ & AssociatesHusky Energy HSE TSX NC

PetroBakken Energy Ltd. PBN TSX C$ 11.85 3 RJ LTD.

Vermilion Energy Inc. VET TSX C$ 42.95 2 RJ LTD.



covered.





Whitecap Resources Inc. June 19, 2012

WCP-TSX Company Report - Initiation of CoverageLuc Mageau CFA | 403.509.0505 | [email protected]


Junior Oil & Gas ProducersDouble Focus on Cardium as well as Great Viking Exposure

EventWe are initiating coverage on Whitecap Resources with an $11.00 target price

and an Outperform rating.

RecommendationWhitecap has assembled a strong Cardium land position at East Pembina and

Garrington. We believe that the recently added Viking lands and its mature oil

pool at Valhalla also provide good torque to oil prices. We recommend clients

buy Whitecap.

AnalysisThe company has assembled a strong land position in the Cardium play at East

Pembina and Garrington. At East Pembina the company has identified 110 net

locations, but based on the estimated oil in place we believe this number could

ultimately be as high as 275 net wells. The recent acquisition of Midway Energy

gave Whitecap a dominant position at Garrington. The company has identified

144 net wells here, but we estimate that this could ultimately be as high as

210. Not only is the company’s land base in two of the stronger areas of

Cardium performance based on our analysis, Whitecap has consistently been

drilling wells that outperform the average. For that reason we continue to

believe it is one of the best positioned Cardium producers.

In early 2012, the company purchased Compass Petroleum – adding a new core

area in the Viking. As part of our Viking analysis, we previously highlighted

Compass’ lands at Lucky Hills as an area that has consistently outperformed.

Production from the area has increased to 1,600 boe/d (February 2012) and is

expected to increase to north of 2,000 boe/d by year-end. The company has

identified 235 net wells in the area and holds 92 net sections of land.

Total corporate production is 16,000 boe/d (68% oil and liquids). Based on our

price deck we expect Whitecap to spend ~$225 mln in E&P activities this year

and exit at ~17,000 boe/d. Although this is lower than guidance at this point,

we are also assuming lower commodity prices for the balance of the year.

ValuationOur $11.00 target price is based on our 2012E SUPER NAV estimate of $10.27

and a 6.0x times multiple (in-line with the company’s 1.5-year historical trading

range) on our 2013E cash flow per share estimate of $2.03. We have applied a50% weighting to each in arriving at our target price.

CFPS 1Q 2Q 3Q 4Q Full Revenues NAVPS

Mar Jun Sep Dec Year (mln)

2011A C$0.20 C$0.26 C$0.32 C$0.45 C$1.16 C$137

2012E 0.38A 0.31 0.41 0.42 1.42 301 10.27

2013E 0.46 0.48 0.50 0.55 2.03 392 na

Source: Raymond James Ltd., Thomson One. EPS is shown as f.d., from continuing ops. 1Q12 is IFRS.

Rating & Target

Outperform 2



52-Week Range C$0.00 - C$0.00

Market Data


Current Net Debt (mln) C$356

Enterprise Value (mln) C$1,284





2011A 2012E 2013E

P/CFPS

6.2x 5.1x 3.6x

P/NAV

0.7x na

WTI (US$/bbl)

US$95.13 US$91.82 US$80.00

HHub (US$/mmbtu)

US$4.03 US$2.39 US$3.25

Production (boe/d)

5,658 14,168 17,813

Production: Oil (%)

63% 69% 75%

Capex (mln)

C$354 C$903 C$230

EBITDA (mln)

C$88 C$192 C$271

Net Debt (mln)

C$164 C$335 C$309


1.9x 1.8x 1.2x

Company Description

Whitecap is an intermediate sized oil-weighted

producer with core assets in the Cardium at Eas

Pembina and Garrington, the Viking at Lucky Hills and

mature Montney oil pool at Valhalla.





Table of Contents





Appendix 2: Management & Board of Directors ............................................................ 100

Risks ................................................................................................................................ 102





Investment Overview


We are initiating coverage on Whitecap with an $11.00 target price and an Outperform

rating. Our target price represents a return to target of 53% based on the June 14, 2012

close price of $7.21. Our target price is based on our 2012E Risk Adjusted SUPER NAV

estimate and a 6.0 times multiple on our 2013E cash flow per share estimate. Themultiple is based on the company’s 1.5-year historical trading range, and is in-line with

other oil-weighted companies in our coverage universe. Our SUPER NAV estimate

assumes development of the company’s Pembina and Garrington Cardium lands, as well

as the full development of Saskatchewan Viking lands. Due to the early nature of

development at the company’s Beaverhill Lake lands and the early implementation of

the waterflood at Valhalla (although results have been encouraging), we have not

included any potential resource upside for these lands. Rather, we have chosen to wait

for additional information and well results before attempting to quantify this potential.

Exhibit 1: Whitecap Target Price Calculation


CFPS (2013E) $2.03 6.0x $12.18 50% $6.09NAVPS (2012E) $10.27 $10.27 50% $5.13

$11.22

Target Price $11.00 Source: Raymond James Ltd.

Investment Summary

Through an aggressive acquisition strategy, Whitecap has evolved into an intermediate

sized oil-focused producer. The company’s asset base consists of both high-impact

Cardium, repeatable Viking, and low decline conventional Montney oil. This allows

Whitecap significant flexibility to adapt its development strategy to current conditions

and diversifies its geologic and technical risk. More importantly, the company offers

investors with a stable oil-weighted production base of ~16,000 boe/d, while providingexposure to significant oil resource upside. Other reasons for our investment thesis are

as follows:

• Strong Cardium Economics – Whitecap’s Cardium assets are focused at East

Pembina and Garrington, which we have identified as providing among the best

rates of return, highest NPVs, and shortest payback periods within the larger

Cardium play. The company’s current inventory of ~254 net locations in the

Cardium not only has the potential to grow dramatically, but well results to date

have demonstrated better repeatability and higher production than the average for

their respective areas.

• Lucky Hills Viking – The Viking assets that the company acquired in west central

Saskatchewan have historically outperformed the average for the Saskatchewan

Viking. With low well costs, owned infrastructure, and better than average type

curves, the economics provide strong recycle ratios and NPVs.

• Stable Production Base – The company’s Valhalla Montney pool represents a low

decline rate oil pool, complementing the higher decline nature plays like the

Cardium and Viking. With the potential for waterflood expansion, the company sees

potential to grow production from this asset and reach an ultimate recovery factor

in the order of ~40%.





Company Overview

Whitecap went public in June 2010, with the reverse take-over of Spitfire Energy. At that

time, the company was producing oil from its Valhalla Montney pool (~850 boe/d) and

acquired Spitfire’s southwest Saskatchewan production (~300 boe/d). The company

made its initial move into the Cardium when it purchased Onyx in July 2010, acquiring

19 sections of East Pembina lands. In June 2011, Whitecap acquired Spry, which added

to its Pembina Cardium land base and increased production by 2,500 boe/d. In additionto a busy acquisition strategy, the company grew organic production from September

2009 to December 2011 by ~5,200 boe/d. So far in 2012, the company has completed

two major acquisitions: Compass Petroleum (establishing a solid footing in the

Saskatchewan Viking with 92 net sections of land and ~1,600 boe/d of production) and

Midway Energy (adding the Garrington area to its Cardium base, with ~5,400 boe/d of

production, 59.4 net section of Cardium lands and 18 net sections of Beaverhill Lake

lands).

Asset Overview

Cardium Oil - East Pembina

Whitecap established its presence in this area with the acquisition of Onyx in mid-2010

and Spry in early-2011. At East Pembina Whitecap has assembled 45.8 net sections

(29,312 net acres) of land. Most of the lands are on the halo area of East Pembina,

where most of the horizontal oil well development has been to date. A map of the

company’s East Pembina lands is shown in Exhibit 2.

Exhibit 2: Whitecap East Pembina Land Base

Source: Whitecap Resources Inc.





The company now has 76 horizontal wells producing over its lands and estimates that 4

wells per section are attainable – total estimated development well inventory based on

this is 171 (110 net) wells. Similar to other areas of the Cardium, the company is working

on potential for further in-fill drilling and expects that an ultimate well spacing density

of 6 or more wells could be achievable.

Our review of Whitecap’s wells show that the company compares slightly better than

the industry average according to GeoScout – consistently achieving higher IP and

longer term rates that are in-line with the average. We also reviewed well results over

time; the company has shown a measurable increase in well productivity y/y both on

IP30 and longer-term. Exhibit 3 shows Whitecap’s East Pembina well results (on a boe/d

basis) and how they compare from 2010 (selection 1) to 2011 (selection 2). The

improvement in well results can mainly be attributed to drilling and completion

efficiencies (i.e. now using Nitrogen frac’s rather than oil or slick-water).

Exhibit 3: Whitecap East Pembina Wells in 2011 versus 2010

0.0

1.0

2.0

3.0

4.0

5.0

0

60

120

180

240

300

N a t u r a l G a s P r o d u c t i o n ( m

m c f / d )

O i l P r o d u c t i o n ( b b l / d ) & T o t a l P r o

d u c t i o n ( b o e / d )

05

10

15

20

25

30

35

40

0 6 12 18 24

N u

m b e r o f W e l l s


Selection 1

Selection 2*


Because the Pembina area is one of the longest producing oil pools in the WCSB,

pipelines, oil treating and gas handling is very well established. Most new production

can be brought on-stream in reasonably short order. In addition, short tie-ins mean that

most production can be pipeline connected (helping operating and transport costs).

The company has estimated that over its lands there are 465 (321 net) mmbbl of OOIP

(0.4% or 1.8 mmbbl recovered to date). The company also estimates that a primary

recovery factor of 10-15% is achievable – translating to remaining recoverable oil over

the East Pembina lands of 32-48 mmbbl (or ~200-300 net wells left to drill) net to

Whitecap. Based on this, if the company were to focus 100% of its efforts at East

Pembina, we estimate that it would take 4-6 years to drill through all the wells; giving

the company a deep inventory in this area alone. The company has ~13 mmbbl of net 2P

reserves booked in this area and has been assigned 50 mmbbl of net Best Estimate

Contingent Resource.





Cardium Oil - Garrington

Whitecap acquired its position at Garrington through the recently completed Midway

acquisition. The company now holds 59 net sections of land along this Cardium trend. It

has been successfully delineated with 60 horizontal wells (drilled by Midway) to date

and drilling here is also characterized by halo style development around existing vertical

production (although vertical production is not as prominent or mature as it is at

Pembina). A map of the Garrington land base is shown in Exhibit 4. The company’s well

results from the area are shown in Exhibit 5; similar to Pembina, Whitecap has been

getting better results in the area than average.

Exhibit 4: Whitecap Garrington Land Base






Exhibit 5: Whitecap Garrington Area Well Results

0.0

1.0

2.0

3.0

4.0

5.0

0

60

120

180

240

300

N a t u r a l G a s P r

o d u c t i o n ( m m c f / d )


0

10

20

30

40

50

60

0 6 12 18 24



Oil (bbl/d)

Selection 1

Selection 2

*


Whitecap has identified net OOIP for this land base of 374 (292 net) mmbbl (~5

mmbbl/section). The company has identified an inventory of 199 (144 net) horizontal

wells which equates to ~30 mmbbl of recoverable oil. Using a recovery factor of 10-15%

we estimate that recoverable oil (primary) remaining could be 29-44 mmbbl, translating

to a horizontal well inventory of ~140-210 wells. Based on development to date the

company has booked 12.7 mmbbl in net 2P reserves and has been assigned 45 mmbbl of

net contingent resource.

Whitecap also controls significant oil and gas infrastructure in this area, as well as

gathering pipelines. These facilities can easily be expanded to accommodate

incremental production as it comes online.

Valhalla Montney

The Valhalla asset was the first area of operation for Whitecap. The company first

acquired a working interest in the asset as a private company and expanded the interest

to 50% in January 2011. The Valhalla asset consists of a mature Montney light oil pool

currently under waterflood. A map of the asset is shown in Exhibit 6.





Exhibit 6: Valhalla Montney Pool


The pool has been under development for some time and currently has several vertical

water injector wells along with vertical and horizontal producers. The pool produces

2,800 boe/d (1,400 boe/d net to Whitecap) and with additional waterflood/in-fill

drilling, Whitecap expects that field production could ultimately increase to 5,000 boe/d

(2,500 boe/d net to Whitecap). The field has estimated OOIP of 120.5 mmbbl (60.3

mmbbl net to Whitecap) and has recovered 7.8 mmbbl (4.5 mmbbl net) to date. The

company has booked a 20% recovery factor into its 2P reserves, which translates to

~16.6 mmbbl (8.3 mmbbl net to Whitecap). The field has been assigned contingent

resource of 26.3 mmbbl (13.2 mmbbl net to Whitecap) translating to a 40% recovery

factor, so incremental recovery for this field could be very material to the company.

Saskatchewan Viking

Whitecap acquired Compass Petroleum in December, 2011. The acquisition represented

Whitecap’s foray into the Saskatchewan Viking. The transaction was for $98 mln and

included 92 net sections of Viking lands, 1,400 boe/d (at the time; 74% oil and liquids)

and 5.56 mmboe of 2P reserves (including 44 locations that have been booked in the 2P

reserves report). The company estimates that 389 (235 net) horizontal wells can be

drilled on the land base, translating to an average of 2.5 wells/section (however

locations are included for delineated lands only). Production primarily comes from the

Lucky Hills area (west of Dodsland) and exploration lands are held at Lucky Hills,

Kindersley, Fiske, Elrose, and Forgan. A map of the Viking lands is shown in Exhibit 7.





Exhibit 7: Whitecap Saskatchewan Viking Lands


Compass drilled 38 horizontal wells on its land base before being acquired by Whitecap.

This has significantly de-risked the Lucky Hills area (where most of the horizontal wells

were drilled) and established an exploration play in the Forgan area (Compass drilled 2

horizontal wells here). The Lucky Hills field has most of the infrastructure needed to

support long-term development – including gas gathering pipelines, gas processing

infrastructure, and central oil batteries – so additional production from the area can be

captured by drilling wells.

Lucky Hills has been an area of the Saskatchewan Viking that has consistently achieved

above average results since Compass began drilling in it. The wells typically will have anIP30 north of 60 boe/d and are expected to recover ~70 mboe each (75% oil and

liquids). Whitecap has identified a total horizontal well inventory of 389 (235 net) wells

on its land base and we estimate that the ultimate inventory could be as high as 350-

400 net wells.

Over the remainder of 2012, we expect Whitecap to drill 20-25 horizontal wells on its

Viking lands. This is expected to increase production from the area to over 2,000 boe/d

by exit 2012. Over the longer-term, Whitecap expects that production from these assets

can ultimately be increased to 4,000 boe/d, representing ~185% growth from the level

that they were purchased from.

Other Assets

Southwest Saskatchewan – Roseray/Cantuar

Whitecap acquired this area when it completed its go-public transaction with Spitfire.

The assets are producing ~300 bbl/d and include a mature, low-decline oil pool that is

currently under primary recovery. The formations are relatively shallow (<1,000 m deep)

so drilling is inexpensive ($0.7 mln for a vertical, $1.0 mln for a horizontal), and drill

times are short. Although the area is not likely to be a contributor of production growth,

given the low declines and favourable royalty structure, it should provide stable cash





flow to help fund growth from other assets. The company has identified 13 undrilled

locations on the land base and had 10 booked in the reserves report at year-end so

unbooked potential for reserves is also minimal.

Swan Hills Beaverhill Lake

As part of the Midway acquisition, Whitecap acquired 38 (18 net) sections of Beaverhill

Lake lands in the Swan Hills area. Midway acquired these lands as part of a farm-in

agreement in 3Q11. Under the agreement, the company earned 4 sections by drilling its

first well and earns 2.5 sections with the drilling of its second. Although the lands are

early stage, Midway had 1 vertical well (averaging 51 bbl/d of light oil over 1Q11) and 1

horizontal well (brought on-stream in 2Q11 and produced up to 350 bbl/d) drilled.

Whitecap holds a 50% interest in these lands (the remaining 50% is held by Crescent

Point).

Corporate Outlook

Following the completion of the Midway acquisition (February 2012), corporate

production increased to ~16,000 boe/d (68% oil and liquids). The credit facility was also

increased to $400 mln from $250 mln, so the company has considerable room to fund

its growth program going forward.

For 2012 the company’s current guidance is to spend $260 mln - $265 mln and drill 120

gross wells. Based on this, the company’s guidance is for average production of 15,000-

15,500 boe/d (~70% oil and liquids) and exit at 18,000-19,000 boe/d (~70% oil and

liquids). This said, the company has considerable flexibility in the budget if commodity

prices remain low. Given our outlook on prices, we have chosen to pare back our capital

program assumptions by ~$40 mln. As such, we expect the 2012 program to include ~75

net wells – 45-50 Cardium wells, 20-30 net Viking wells and 4-6 Valhalla wells. This is

expected to translate to full-year average production of 14,000-14,500 boe/d and exit

production of ~17,000 boe/d.






Our valuation of Whitecap is based on a blend of cash flow multiple and net asset value.

Consistent with the company’s 1.5-year historical trading range, we have used a target

multiple of 6.0 times 2013E cash flow per share. We combine this with our Risk Adjusted

SUPER NAV estimate to arrive at our target price of $11.00, which is outlined in Exhibit

8. In Exhibit 9 we also show the implied metrics this translates to for the company.

Exhibit 8: Whitecap Target Price Calculation


CFPS (2013E) $2.03 6.0x $12.18 50% $6.09

NAVPS (2012E) $10.27 $10.27 50% $5.13

$11.22

Target Price $11.00 Source: Whitecap Energy Inc., Raymond James Ltd.



Production (2012E) boe/d 4,402 9,766 14,168 Production (2013E) boe/d 4,515 13,299 17,813






Target EV/boe/d (2012E)* $123,568






Financial Estimates

Our cash flow estimates assume that the company successfully completes an E&D

capital program of $225 mln during 2012. It also assumes that the company drills 75 net

wells. This includes 45-50 net Cardium wells, 20-30 net Viking wells, and 4-6 net Valhalla

Montney oil wells. As a result, we assume that the company achieves an exit rate of

~17,000 boe/d (~30% gas) and posts average production of ~14,150 boe/d. For 2013, we

assume the company executes a similar, but slightly ramped up program from 2012 –

resulting in average production of ~17,800 boe/d and an exit rate of ~20,000 boe/d.

Because of Whitecap’s relatively high oil weighting the company generates strong

corporate realized price. Because the southwest Saskatchewan oil production is a

heavier crude, prices are slightly lower despite the high oil weighting. We have used an

average realized price per boe of $58.02 for 2012 and $60.33 for 2013. The increase is

primarily attributable to the higher oil weighting in 2013 over 2012. On a netback basis,

the company is expected to be well above average at $37.06/boe for 2012 and

$40.85/boe for 2013. This is the driving force behind our cash flow estimate of $183 mln





($1.42/share) for 2012 and $261 mln ($2.03/share) for 2013. Our key operating

assumptions are summarized in Exhibits 10 and 11. These are supplemented by our

detailed Financial Summary in Appendix 1.


2011A 2012E 2013E

WTI (US$/bbl) $95.13 $91.82 $80.00

Cdn Par ($/bbl) $95.61 $86.00 $78.33

NYMEX (US$/mcf) $4.03 $2.39 $3.25

AECO ($/mcf) $3.55 $2.00 $2.86

FX (US$/C$) $1.02 $0.96 $0.96

Cash Flow ($mln) $86 $183 $261

CFPS (diluted) $1.16 $1.42 $2.03

Production (boe/d) 5,658 14,168 17,813

% Gas 36.6% 31.1% 25.3%

% Growth 294.8% 150.4% 25.7%

Capex ($mln) $354 $903 $230

Multiple of Cash Flow 4.12x 4.94x 0.88xY/E Net Debt ($mln) $164 $335 $309

Debt/Cash flow (T12) 1.9x 1.8x 1.2x



2011A 2012E 2013E

Oil & NGLs (bbl/d) 3,588 9,766 172.2% 13,299 36.2%

Natural Gas (mmcf/d) 12.4 26.4 112.7% 27.1 2.6%

Total boe/d 5,658 14,168 150.4% 17,813 25.7%

Source: Whitecap Energy Inc., Raymond James Ltd.

In our NAV we first assumed development of the company’s 2P reserves base of 70.7

mmboe (our Base NAV). To capture the company’s growth prospects, we have assumed

incremental recovery factors for the Cardium and Viking land base. Although the

Valhalla Montney land base does have additional waterflood upside, we have not

incorporated this into our Growth NAV. Similarly, we view the Beaverhill Lake land base

as good option value at this point, but given its relative infancy we have not modeled

the play in our NAV estimate. The company has substantially its entire southwest

Saskatchewan land base booked so we have not included a growth NAV component for

this area (but is captured in our Base NAV).

For the Cardium, we have assumed a total recovery factor of 15% on the company’s

lands. The company currently has ~5% recovery factor booked in its 2P reserve report –

this translates to ~25.7 mmbbl of oil. To get to our Growth NAV case, we have assumed

an incremental 65.8 mmbbl of oil is recoverable on the company’s land base. We have

also assumed a blended EUR for East Cardium and Garrington of 180 mbbl/well

translating to 365 net wells to be drilled that are not currently booked in the 2P

reserves. We have assumed it takes ~7 years to capitalize the land base and we have

risked the value at 75%.

In our Viking Growth NAV, we have included the net unbooked wells that Whitecap

counts in its inventory. In all, the company has identified 235 net locations in its





inventory, of which 44 are booked in the 2P reserves report. Therefore, we have

included 190 net wells in our Growth NAV estimate. We have also risked this Growth

NAV value at 75%. Our resulting NAV is $10.27. This is shown in Exhibit 12.

Exhibit 12: Whitecap Net Asset Value (2011E)

WhiteCap Year End 2012 NAV EstimateAnalyst: Luc Mageau: Ph. 403-509-0505

Associate: Matthe w Stevens on: Ph. 403-509-0518


10% A.T. NPV

(C$ m ln) $/Share

10% A.T. NPV

(C$ mln) $/Shar e

Base Gas 100% 75 $0.58 75 $0.58Base Oil 100% 916 $7.12 916 $7.12


Growth NAV

Cardium Grow th NAV 75% 516 $4.01 688 $5.34Viking Grow th NAV 75% 171 $1.33 227 $1.77

Total Grow th NAV 686 $5.33 915 $7.11

Net Debt (356) (2.77) (356) (2.77)

Total Corporate Net Asset Value 1,321 $10.27 1,550 $12.04

Cur r ent Ful l y Di lu ted Shares Outs tandi ng (mln s) 128.7 128.7




90% - Area w ell delineated; resource pool edges mostly w ell know n; extensions and resource upside less likely

75% - Development in area ongoing; good production base - ex tensions possible w ith exploration

60% - Ramp-up of resource in progress; ex tensive amount of exploration wells and some infrastructure in area; total potential not defined

30% - New area of development; minimal infrastructure; some exploration w ells; relatively new frontier but development seen as near-term


Unrisked NAVPS EstimateRisk Adjusted NAVPS Estim ate



Whitecap’s growth areas into our SUPER NAV generates a risk adjusted production

profile for the company – this is shown in Exhibit 13.





Exhibit 13: Whitecap Estimated Production Profile (boe/d)

0

10,000

20,000

30,000

40,000

2012 2017 2022 2027

Base Gas Base Oil Viking Growth Cardium Growth



profile in Exhibit 14. We have assumed that capital spending only minimally outstrips

cash flow for the first two years, but is constrained to within cash flow in subsequent

years. Production growth – combined with our commodity price outlook – boosts cash

flow from that point and the company becomes a free cash flow entity. We estimate

that the company exits 2012 with ~$335 mln of net debt on a $400 mln revolver –

translating to a D/CF ratio (using 4Q12 annualized cash flow) of 1.6x.

Exhibit 14: Whitecap Estimated Cash Flows ($ mln)

0

150

300

450

600

750

2012 2017 2022 2027Base Gas Base Oil Viking Growth Cardium Growth Capital Spend







WHITECAP RESOURCES INC- Financial Summary (C$)

2011A 2012E 2013E


WTI Oil (US$/bbl) $95.13 $91.82 $80.00


NYMEX Gas (US$/mcf) $4.03 $2.39 $3.25

AECO Gas (C$/mcf) $3.55 $2.00 $2.86

FX (US$/C$) $1.02 $0.96 $0.96

Realized Price

Oil & NGL ($/bbl) $90.47 $78.38 $74.56

Natural Gas ($/mcf) $3.84 $2.14 $3.06

Production

Oil & NGL ($/bbl) 3,588 9,766 13,299


Total (boe/d 6:1) 5,658 14,168 17,813

% Oil 63.4% 68.9% 74.7%Growth 294.8% 150.4% 25.7%


Netback ($/boe)

Corporate Price $65.80 $58.02 $60.33

Royalties $7.93 $7.26 $6.93



% Change 89.9% -15.8% 10.2%

Cash Flow ($mln) $86 $183 $261

CFPS ($/share, basic) $1.19 $1.44 $2.05



Diluted 74.0 128.7 128.7



Drilling, Completions & Other $108 $198 $214


Other $0 $1 $0


Total Capex $354 $903 $230


Net debt ($mln)

Net Debt $164 $335 $309

Net Debt/CF (T12) 1.9x 1.8x 1.2x

Net Debt/CF (Annualized 4Q) 1.2x 1.6x 1.1x

Net Debt/EV (Market) 0.2x 0.3x 0.2x

Source: Whitecap Resources Inc., Raymond James Ltd.





WHITECAP RESOURCES INC- Financial Summary (C$) (Cont'd)

2011A 2012E 2013E


Total Proved 48.4

Probable 22.3

Total 2P Reserves (mmboe) 70.7 76.3 81.0





Tax Pools ($mln)

Total $504


Net Undeveloped Land (000 Acres)*

Alberta 180,802

Saskatchewan 105,346 Other


* Includes Midway and Compass lands






WHITECAP RESOURCES INC - Financial Summary (C$) (Cont'd)

2011A 2012E 2013E

Assets ($mln)




Property, Plant and Equipment $549 $1,326 $1,400

Other $59 $75 $75

Total Assets ($mln) $642 $1,433 $1,508

Liabilities ($mln)



Other Current Liabilities $5 $5 $5




Other Long-term Liabilities $0 $0 $0




Retained Earnings $15 $54 $127


Total Shareholders' Equity ($mln) $380 $976 $1,051

Total Liabilities and S/H Equity ($mln) $642 $1,433 $1,508







Management

Grant Fagerheim – President and CEO

Mr. Fagerheim has 29 years of experience in both the upstream and downstream areas

of oil and gas. Prior to establishing Whitecap in June 2009, Mr. Fagerheim was the

President, Chief Executive Officer and a Director of Cadence Energy Inc. (formerly

Kereco Energy Ltd.) from January 2005 to September 2008, as well as President and CEO

of Ketch Energy and Ketch Resources from April 2000 to January 2005.

Joel Armstrong – VP Production and Operations

Mr. Armstrong has 26 years of engineering and operations experience in oil and gas.

Prior to Whitecap Mr. Armstrong worked with Ridgeback Exploration Ltd., Blue

Mountain Energy Ltd., Star Oil & Gas Ltd., Kerr-McGee Canada Ltd., and Suncor Inc.

Dan Christensen – VP Exploration

Mr. Christensen has 28 years of exploration, prospect development, and management

experience with senior integrated and private E&D growth companies in oil and gas.

Darin Dunlop – VP Engineering

Mr. Dunlop has 24 years of domestic and international engineering experience with

Chevron, Wascana, Santos, Genesis, and two private companies.

Thanh Kang – VP Finance and CFO

Mr. Kang has 12 years of financial and management experience in the oil and gas

industry, including 4 years with energy trust and small private companies. Previously he

was a Manager in PricewaterhouseCoopers’ audit and business advisory practice.

Gary Lebsack – VP Land

Prior to Whitecap Mr. Lebsack was an Officer at Glamis Resources Ltd., a negotiator at

StarPoint Energy Trust, StarPoint Energy Ltd., Burlington Resources Ltd. and Northrock

Energy Ltd.

Dave Mombourquette – VP Business Development

Mr. Mombourquette has 26 years engineering and evaluation experience. Prior toWhitecap he was an Officer of Ketch Energy Ltd., Ketch Resources Ltd. and Kereco

Energy Ltd.





Directors

Grant Fagerheim

Chairman – see management write-up.

Donald Cowie

Mr. Cowie is currently President of JOG Capital Inc., a private equity partnership focused

on junior oil and gas companies in western Canada. He has over 25 years of experience

in the financial oil and gas industry. From 1992 to 2002, Mr. Cowie was the head of

corporate and investment banking for the Bank of America. Prior to 2002, he served as

an officer or director for several junior oil and gas companies and several other financial

companies specializing in the oil and gas sector. Mr. Cowie has a Bachelor of Commerce

degree, with a major in finance. Mr. Cowie also serves as an independent director for a

number of private companies and public companies listed on either the Toronto Stock

Exchange or TSX Venture Exchange. Mr. Cowie was elected to the board on April 20,

2011.

Gregory Fletcher

Mr. Fletcher has over 39 years of experience in the oil and gas industry and is currently

President of Sierra Energy Inc., a private oil and gas production company that he

founded in 1997. Mr. Fletcher is a member of the Audit Committee and a member of

the Reserves Committee and has been a Director since September 14, 2010.

Glen McNamara

Mr. McNamara is the Chief Executive Officer of Petromanas Energy Inc. From August

2005 to August 2010, he was the President of BG Canada (part of the BG Group PLC, a

public gas company with its head office in the United Kingdom, trading on the London

Stock Exchange). Prior to that he was President of ExxonMobil Canada Energy, a wholly

owned affiliate of ExxonMobil. Mr. McNamara is Chairman of the Reserves Committee

and a member of the Corporate Governance and Compensation Committee and has

been a Director since September 14, 2010.

Steven Nikiforuk

Mr. Nikiforuk is the Corporate Business Manager of 1173373 Alberta Ltd. and also the

President of MyOwnCFO Inc. (both private companies) since July 2009; prior thereto he

was Vice President Finance and Chief Financial Officer of Cadence Energy Inc. (formerly,

Kereco Energy Ltd.) from January 2005 to March 2008. Mr. Nikiforuk is Chairman of the

Audit Committee and has been a Director since August 17, 2009.

Grant Zawalsky

Mr. Zawalsky is a Partner of Burnet Duckworth & Palmer LLP, Barristers and Solicitors.

Mr. Zawalsky is a member of the Corporate Governance and Compensation Committee

and has been a Director since June 3, 2008.





Risks

Key risks to Whitecap include:




ii)


iii) Due to the nature of its operations, Whitecap also faces risks associated with

weather-related interruptions, dry holes, restricted access to facilities, unplanned

pipeline shutdowns and unexpected production delays.





production wells could be higher. For Whitecap, this specifically relates to the

Beaverhill Lake lands, some of its East Pembina Cardium lands and some of its

exploratory Viking lands.


infrastructure.vi) Change in government policies (local, provincial and federal); specifically as it

relates to royalty rates and the treatment of oil and gas production.


viii) Some of Whitecap’s acreage is non-operated in nature, therefore the company is at

risk of changes in corporate direction by the operator. The company is also at risk of


to drill.

Company Citations

Company Name Ticker Exchange Currency Closing Price RJ Rating RJ EntityBank of America Corporation BAC NYSE US$ 7.66 1 RJ & Associates

BC Group PLC BG LSE NC

Chevron Corp. CVX NYSE US$ 101.92 1 RJ & Associates

Crescent Point Energy CPG TSX C$ 38.97 3 RJ LTD.

Exxon Mobil Corp. XOM NYSE US$ 82.13 2 RJ & Associates

Genesis Energy, L.P. GEL NYSE NC

Petromanas Energy Inc. PMI TSXV C$ 0.20 2 RJ LTD.

Suncor Energy Inc SU TSX C$ 28.52 2 RJ LTD.



covered.





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Ratings and Definitions

Raymond James Ltd. (Canada) definitions

Strong Buy (SB1) 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 (MO2) The stock is expected to appreciate and

outperform the S&P/TSX Composite Index over the next twelve months. Market Perform (MP3) The stock is expected to

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Raymond James & Associates (U.S.) definitions

Strong Buy (SB1) Expected to appreciate, produce a total return of at least 15%, and outperform the S&P 500 over the next

six to 12 months. For higher yielding and more conservative equities, such as REITs and certain MLPs, a total return of at

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Raymond James Latin American rating definitions

Strong Buy (SB1) Expected to appreciate and produce a total return of at least 25.0% over the next twelve months.

Outperform (MO2) Expected to appreciate and produce a total return of between 15.0% and 25.0% over the next twelve

months. Market Perform (MP3) Expected to perform in line with the underlying country index. Underperform (MU4)

Expected to underperform the underlying country index. Suspended (S) The rating and price target have been suspended

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relied upon.

Raymond James Euro Equities, SAS rating definitions

Strong Buy (1) Expected to appreciate, produce a total return of at least 15%, and outperform the Stoxx 600 over the next 6

to 12 months. Outperform (2) Expected to appreciate and outperform the Stoxx 600 over the next 12 months. Market

Perform (3) Expected to perform generally in line with the Stoxx 600 over the next 12 months. Underperform (4) Expected

to underperform the Stoxx 600 or its sector over the next 6 to 12 months. Suspended (S) The rating and target price have

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merits of other available investments.

Suitability Categories (SR)





For stocks rated by Raymond James & Associates only, the following Suitability Categories provide an assessment of

potential risk factors for investors. Suitability ratings are not assigned to stocks rated Underperform (Sell). Projected 12-

month price targets are assigned only to stocks rated Strong Buy or Outperform.

Total Return (TR) Lower risk equities possessing dividend yields above that of the S&P 500 and greater stability of principal.

Growth (G) Low to average risk equities with sound financials, more consistent earnings growth, possibly a small dividend,

and the potential for long-term price appreciation.

Aggressive Growth (AG) Medium or higher risk equities of companies in fast growing and competitive industries, with lesspredictable earnings and acceptable, but possibly more leveraged balance sheets.

High Risk (HR) Companies with less predictable earnings (or losses), rapidly changing market dynamics, financial and

competitive issues, higher price volatility (beta), and risk of principal.

Venture Risk (VR) Companies with a short or unprofitable operating history, limited or less predictable revenues, very high

risk associated with success, and a substantial risk of principal.

Rating Distributions

Coverage Universe Rating Distribution Investment Banking Distribution

RJL RJA RJ LatAm RJEE RJL RJA RJ LatAm RJEE

Strong Buy and Outperform (Buy) 71% 54% 34% 56% 35% 14% 7% 0%

Market Perform (Hold) 27% 38% 56% 29% 28% 8% 0% 0%

Underperform (Sell) 2% 8% 10% 15% 50% 0% 0% 0%

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from all companies under research coverage within the next three months.

Company Name Disclosure

Crocotta Energy Inc. Raymond James Ltd. has managed or co-managed a public offering of securities within the

last 12 months with respect to Crocotta Energy Inc..

Raymond James Ltd. has provided investment banking services within the last 12 months

with respect to Crocotta Energy Inc..

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last 12 months with respect to Crocotta Energy Inc..

Devon Energy Corporation Raymond James & Associates received non-investment banking securities-related

compensation from DVN within the past 12 months.

Pengrowth Energy Corporation Raymond James Ltd. has managed or co-managed a public offering of securities within the

last 12 months with respect to Pengrowth Energy Corporation.


with respect to Pengrowth Energy Corporation.


last 12 months with respect to Pengrowth Energy Corporation.

PetroBakken Energy Ltd. Raymond James Ltd - the analyst and/or associate has viewed the material operations of

PetroBakken Energy Ltd..

Spartan Oil Corp. Raymond James Ltd - the analyst and/or associate has viewed the material operations of

Spartan Oil Corp..

TriOil Resources Ltd. Raymond James Ltd - the analyst and/or associate has viewed the material operations of

TriOil Resources Ltd..





Company Name Disclosure

Vermilion Energy Inc. Raymond James Ltd. has managed or co-managed a public offering of securities within the

last 12 months with respect to Vermilion Energy Inc..


with respect to Vermilion Energy Inc..


last 12 months with respect to Vermilion Energy Inc..

Vero Energy Inc. Raymond James Ltd - the analyst and/or associate has viewed the material operations of

Vero Energy Inc..

Whitecap Resources Inc. Raymond James Ltd - the analyst and/or associate has viewed the material operations of

Whitecap Resources Inc..

Yangarra Resources Ltd. Raymond James Ltd. has received compensation for investment banking services within the

last 12 months with respect to Yangarra Resources Ltd..

Stock Charts, Target Prices, and Valuation Methodologies

Valuation Methodology: The Raymond James methodology for assigning ratings and target prices includes a number of

qualitative and quantitative factors including an assessment of industry size, structure, business trends and overall

attractiveness; management effectiveness; competition; visibility; financial condition, and expected total return, amongother factors. These factors are subject to change depending on overall economic conditions or industry- or company-

specific occurrences.

Target Prices: The information below indicates target price and rating changes for the subject companies included in this

research.

Price RatingChange Target PriceChange

Coverage Suspended Target Price andRatingChange Split Adjustment

$1.00

$1.30

$1.60

$1.90

$2.20

$2.50

$2.80$3.10

$3.40

$3.70

$4.00

$4.30

$4.60

$4.90

J u n - 1 9 - 0 9

J u l - 2 0 - 0 9

A u g - 1 7 - 0 9

S e p - 1 5 - 0 9

O c t - 1 3 - 0 9

N o v - 1 0 - 0 9

D e c - 0 9 - 0 9

J a n - 0 8 - 1 0

F e b - 0 8 - 1 0

M a r - 0 9 - 1 0

A p r - 0 7 - 1 0

M a y - 0 5 - 1 0

J u n - 0 3 - 1 0

J u l - 0 1 - 1 0

J u l - 3 0 - 1 0

A u g - 2 7 - 1 0

S e p - 2 7 - 1 0

O c t - 2 5 - 1 0

N o v - 2 0 - 1 0

D e c - 1 7 - 1 0

J a n - 1 4 - 1 1

F e b - 1 1 - 1 1

M a r - 1 1 - 1 1

A p r - 0 8 - 1 1

M a y - 0 7 - 1 1

J u n - 0 4 - 1 1

J u l - 0 1 - 1 1

J u l - 3 0 - 1 1

A u g - 3 0 - 1 1

S e p - 2 8 - 1 1

O c t - 2 7 - 1 1

N o v - 2 4 - 1 1

D e c - 2 2 - 1 1

J a n - 2 4 - 1 2

F e b - 2 2 - 1 2

M a r - 2 1 - 1 2

A p r - 1 9 - 1 2

M a y - 1 7 - 1 2

J u n - 1 3 - 1 2

S e c u r i t y P r i c e

( C $ )

Spartan Oil Corp. (STO) 3 yr. Stock PerformanceSpartan Oil Corp. (STO) 3 yr. Stock Performance

Date: June 142012

Analyst Recommendations & 12 Month Price ObjectiveSB1: Strong Buy MO2: OutperformMP3: Market Perform MU4: UnderperformNR : Not Rated R: Restricted

U p d a t e

D a t e

C l o s i n g

P r i c e

T a r g e t

P r i c e

R a t i n g

Valuation Methodology: Our valuation is based on a blended approach using net asset value and P/CF multiple, which

takes into account growth potential and risk profile.







$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

J u n - 1 9 - 0 9

J u l - 2 0 - 0 9

A u g - 1 7 - 0 9

S e p - 1 5 - 0 9

O c t - 1 3 - 0 9

N o v - 1 0 - 0 9

D e c - 0 9 - 0 9

J a n - 0 8 - 1 0

F e b - 0 8 - 1 0

M a r - 0 9 - 1 0

A p r - 0 7 - 1 0

M a y - 0 4 - 1 0

J u n - 0 3 - 1 0

J u l - 0 1 - 1 0

A u g - 0 2 - 1 0

A u g - 3 1 - 1 0

S e p - 3 0 - 1 0

O c t - 2 9 - 1 0

N o v - 2 6 - 1 0

D e c - 2 4 - 1 0

J a n - 2 6 - 1 1

F e b - 2 4 - 1 1

M a r - 2 4 - 1 1

A p r - 2 1 - 1 1

M a y - 2 0 - 1 1

J u n - 1 8 - 1 1

J u l - 1 9 - 1 1

A u g - 1 7 - 1 1

S e p - 1 5 - 1 1

O c t - 1 4 - 1 1

N o v - 1 1 - 1 1

D e c - 0 9 - 1 1

J a n - 1 1 - 1 2

F e b - 0 8 - 1 2

M a r - 0 8 - 1 2

A p r - 0 5 - 1 2

M a y - 0 4 - 1 2

J u n - 0 1 - 1 2

S e c u r i t y P

r i c e ( C $ )

TriOil Resources Ltd. (TOL) 3 yr. Stock PerformanceTriOil Resources Ltd. (TOL) 3 yr. Stock Performance

Date: June 142012


U p d a t e

D a t e

C l o s i n g

P r i c e

T a r g e t

P r i c e

R a t i n g





$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

J u n - 1 9 - 0 9

J u l - 2 0 - 0 9

A u g - 1 8 - 0 9

S e p - 1 6 - 0 9

O c t - 1 5 - 0 9

N o v - 1 2 - 0 9

D e c - 1 1 - 0 9

J a n - 1 3 - 1 0

F e b - 1 1 - 1 0

M a r - 1 2 - 1 0

A p r - 1 2 - 1 0

M a y - 1 0 - 1 0

J u n - 0 9 - 1 0

J u l - 0 9 - 1 0

A u g - 0 9 - 1 0

S e p - 0 8 - 1 0

O c t - 0 6 - 1 0

N o v - 0 4 - 1 0

D e c - 0 2 - 1 0

J a n - 0 1 - 1 1

F e b - 0 1 - 1 1

M a r - 0 2 - 1 1

M a r - 3 0 - 1 1

A p r - 2 8 - 1 1

M a y - 2 7 - 1 1

J u n - 2 4 - 1 1

J u l - 2 3 - 1 1

A u g - 2 3 - 1 1

S e p - 2 1 - 1 1

O c t - 2 0 - 1 1

N o v - 1 7 - 1 1

D e c - 1 5 - 1 1

J a n - 1 7 - 1 2

F e b - 1 4 - 1 2

M a r - 1 4 - 1 2

A p r - 1 2 - 1 2

M a y - 1 0 - 1 2

J u n - 0 6 - 1 2

S e c u r i t y P r i c e ( C $ )

Vero Energy Inc. (VRO) 3 yr. Stock PerformanceVero Energy Inc. (VRO) 3 yr. Stock Performance

Date: June 142012


U p d a t e

D a t e

C l o s i n g

P r i c e

T a r g e t

P r i c e

R a t i n g









$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

$10.00

$11.00

J u n - 1 9 - 0 9

J u l - 2 0 - 0 9

A u g - 1 7 - 0 9

S e p - 1 5 - 0 9

O c t - 1 3 - 0 9

N o v - 1 0 - 0 9

D e c - 0 9 - 0 9

J a n - 0 8 - 1 0

F e b - 0 8 - 1 0

M a r - 0 9 - 1 0

A p r - 0 7 - 1 0

M a y - 0 5 - 1 0

J u n - 0 3 - 1 0

J u n - 3 0 - 1 0

J u l - 3 0 - 1 0

A u g - 3 0 - 1 0

S e p - 2 9 - 1 0

O c t - 2 8 - 1 0

N o v - 2 5 - 1 0

D e c - 2 3 - 1 0

J a n - 2 5 - 1 1

F e b - 2 3 - 1 1

M a r - 2 3 - 1 1

A p r - 2 0 - 1 1

M a y - 1 9 - 1 1

J u n - 1 7 - 1 1

J u l - 1 6 - 1 1

A u g - 1 6 - 1 1

S e p - 1 4 - 1 1

O c t - 1 3 - 1 1

N o v - 1 0 - 1 1

D e c - 0 8 - 1 1

J a n - 1 0 - 1 2

F e b - 0 7 - 1 2

M a r - 0 7 - 1 2

A p r - 0 4 - 1 2

M a y - 0 3 - 1 2

M a y - 3 1 - 1 2

S e c u r i t y P

r i c e ( C $ )

Whitecap Resources Inc. (WCP) 3 yr. Stock PerformanceWhitecap Resources Inc. (WCP) 3 yr. Stock Performance

Date: June 142012


U p d a t e

D a t e

C l o s i n g

P r i c e

T a r g e t

P r i c e

R a t i n g



Risk Factors

General Risk Factors: Following are some general risk factors that pertain to the projected target prices included on

Raymond James research: (1) Industry fundamentals with respect to customer demand or product / service pricing could

change and adversely impact expected revenues and earnings; (2) Issues relating to major competitors or market shares or

new product expectations could change investor attitudes toward the sector or this stock; (3) Unforeseen developments

with respect to the management, financial condition or accounting policies or practices could alter the prospective

valuation.

Risks - Spartan Oil Corp.

Key risks include cash flow exposure to fluctuations in energy prices and foreign exchange rates, more specifically the

relationship between the Canadian and U.S. dollar. Due to the nature of its operations, Spartan also faces risks associated

with weather-related interruptions, dry holes, restricted access to facilities, unplanned pipeline shutdowns and unexpected

production delays. Also, the company is exposed to the risk that unexpected increases in decline rates lower production

volumes, resulting in lower cash flow. Unexpected cost overruns, change in government policies (local, provincial and

federal) and interest rate fluctuations could also negatively impact net income and cash flow. Some of Spartan’s acreage is

non-operated in nature, therefore the company is at risk of changes in corporate direction by the operator.

Risks - TriOil Resources Ltd.


relationship between the Canadian and U.S. dollar. Due to the nature of its operations, TriOil also faces risks associated with

weather-related interruptions, dry holes, restricted access to facilities, unplanned pipeline shutdowns and unexpected



federal) and interest rate fluctuations could also negatively impact net income and cash flow. Some of TriOil’s acreage is


Risks - Vero Energy Inc.


relationship between the Canadian and U.S. dollar. Due to the nature of its operations, Vero also faces risks associated with

weather-related interruptions, dry holes, restricted access to facilities, unplanned pipeline shutdowns and unexpected



federal) and interest rate fluctuations could also negatively impact net income and cash flow. Some of Vero’s acreage is






Risks - Whitecap Resources Inc.


relationship between the Canadian and U.S. dollar. Due to the nature of its operations, Whitecap also faces risks associated

with weather-related interruptions, dry holes, restricted access to facilities, unplanned pipeline shutdowns and unexpected



federal) and interest rate fluctuations could also negatively impact net income and cash flow. Some of Whitecap’s acreage

is non-operated in nature, therefore the company is at risk of changes in corporate direction by the operator.

Additional Risk and Disclosure information, as well as more information on the Raymond James rating system and suitability

categories, is available for Raymond James at rjcapitalmarkets.com/SearchForDisclosures_main.asp and for Raymond James

Limited at www.raymondjames.ca/researchdisclosures.

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Notes .............................................................................................................................................. .............................................................................................................................................. .............................................................................................................................................. .............................................................................................................................................. .............................................................................................................................................. .............................................................................................................................................. .............................................................................................................................................. .............................................................................................................................................. .............................................................................................................................................. .............................................................................................................................................. .............................................................................................................................................. .............................................................................................................................................. .............................................................................................................................................. .............................................................................................................................................. .............................................................................................................................................. .............................................................................................................................................. .............................................................................................................................................. .............................................................................................................................................. .............................................................................................................................................. .............................................................................................................................................. ..............................................................................................................................................




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CONSUMER PRODUCTS & RETAIL

KENRIC TYGHE, MBA 416.777.7188

SARA KOHBODI, CFA (ASSOCIATE) 416.777.4916

ENERGY

OIL & GAS ENERGY SERVICES, HEAD OF ENERGY RESEARCH

ANDREW BRADFORD, CFA 403.509.0503

NICK HEFFERNAN (ASSOCIATE) 403.509.0511

INTERNATIONAL OIL & GAS

RAFI KHOURI, B.SC, MBA 403.509.0560

CYNTHIA YEE (ASSOCIATE) 403.221.0355

ANA WESSEL (ASSOCIATE) 403.509.0541

OIL & GAS TRUSTS | OIL & GAS PRODUCERS

KRISTOPHER ZACK, CA, CFA 403.221.0414

GORDON STEPPAN, CFA (ASSOCIATE) 403.221.0411

OIL SANDS | OIL & GAS PRODUCERS

JUSTIN BOUCHARD, P.ENG, CFA 403.509.0523

VINCENT URNESS (ASSOCIATE) 403.509.0534

OIL & GAS PRODUCERS

LUC MAGEAU, CFA 403.509.0505

MATTHEW STEVENSON (ASSOCIATE) 403.509.0518

INDUSTRIAL

INDUSTRIAL | AEROSPACE & AVIATION, HEAD OF INDUSTRIAL RESEARCH

BEN CHERNIAVSKY 604.659.8244THEONI PILARINOS, CFA (ASSOCIATE) 604.659.8234

GREG JACKSON (ASSOCIATE) 604.659.8262

INFRASTRUCTURE & CONSTRUCTION

FREDERIC BASTIEN, CFA 604.659.8232

JAMIL MURJI, CFA (ASSOCIATE) 604.659.8261

TRANSPORTATION | AGRIBUSINESS & FOOD PRODUCTS

STEVE HANSEN, CMA, CFA 604.659.8208

ARASH YAZDANI, MBA (ASSOCIATE) 604.659.8280

MINING

PRECIOUS METALS, HEAD OF MINING RESEARCH

BRAD HUMPHREY 416.777.4917

PHIL RUSSO (ASSOCIATE) 416.777.7084

TOM HALTON (ASSOCIATE) 416.777.6419

BASE METALS & MINERALS

ADAM LOW, CFA 416.777.4943

TRACY REYNOLDS (ASSOCIATE) 416.777.7042

BASE METALS & MINERALS | PLATINUM GROUP METALS

ALEX TERENTIEW, MBA, P.GEO 416.777.4912

ROSS YAKOVLEV, CA, MBA (ASSOCIATE) 416.777.7144

PRECIOUS METALS

GARY BASCHUK 416.777.7098

GORDON LAWSON (ASSOCIATE) 416.777.7102

URANIUM & JUNIOR EXPLORATION

DAVID SADOWSKI 604.659.8255

INSTITUTIONAL EQUITY SALESHEAD OF SALES

MIKE WESTCOTT 416.777.4935

MICHELLE MARGUET (MARKETING COORDINATOR) 416.777.4951

TORONTO (CAN 1.888.601.6105 | USA 1.800.290.4847)

LAURA ARRELL (U.S. EQUITIES) 416.777.4920

SEAN BOYLE 416.777.4927

JEFF CARRUTHERS, CFA 416.777.4929

RICHARD

EAKINS

416.777.4926JONATHAN GREER 416.777.4930

AMAN JAIN 416.777.4949

DAVE MACLENNAN 416.777.4934

ROBERT MILLS, CFA 416.777.4945

DOUG OWEN 416.777.4925

NICOLE SVEC-GRIFFIS, CFA (U.S. EQUITIES) 416.777.4942

NEIL WEBER 416.777.4931

CARMELA AVELLA (ASSISTANT) 416.777.4915

ORNELLA BURNS (ASSISTANT) 416.777.4928

VANCOUVER (1.800.667.2899)

SCOT ATKINSON, CFA 604.659.8225

DOUG BELL 604.659.8220

TERRI MCEWAN (ASSISTANT) 604.659.8228

MONTREAL (514.350.4450 | 1.866.350.4455)

JOHN HART 514.350.4462

DAVID MAISLIN, CFA 514.350.4460

ELLIOTT SOIFER, CFA 514.350.4472TANYA HATCHER (ASSISTANT) 514.350.4458

LONDON

JON DE VOS 0.207.426.5632

LAKSHMI THURAI 0.207.426.5626

ADAM WOOD 0.207.426.5612

INSTITUTIONAL EQUITY TRADING CO-HEAD OF TRADING

BOB MCDONALD, CFA 604.659.8222

ANDREW FOOTE, CFA 416.777.4924

TORONTO (CANADA 1.888.601.6105 | USA 1.800.290.4847)

PAM BANKS 416.777.4923

ANTHONY COX 416.777.4922

ROSS DAVIDSON 416.777.4981

OLIVER HERBST 416.777.4947

ANDY HERRMANN 416.777.4937

ERIC MUNRO, CFA 416.777.4983JAMES SHIELDS 416.777.4941

BOB STANDING 416.777.4921

PETER MASON (ASSISTANT) 416.777.7195

VANCOUVER (1.800.667.2899)

NAV CHEEMA 604.659.8224

FRASER JEFFERSON 604.659.8218

DEREK ORAM 604 659 8223

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[Canada Research] Cardium Junior Oil Amp Gas Producers

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