Resource Play Watch_Viking_CIBCER_Oct 30 2012

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Institutional Equity Research

Industry Update

October 30, 2012 Oil & Gas - Intermediate & Junior Producers

CIBC Resource Play Watch: Special Report Viking At The Gates - A Review Of The Greater Dodsland Viking Oil Play

All figures in Canadian dollars, unless otherwise stated. 12-119275 2012

CIBC World Markets does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision.

See "Important Disclosures" section at the end of this report for important required disclosures, including potential conflicts of interest. See "Price Target Calculation" and "Key Risks to Price Target" sections at the end of this report, or at the end of each section hereof, where applicable.

Sector Weighting: Market Weight

Arthur Grayfer, CFA 1 (403) 216-3409 [email protected] Jeremy Kaliel 1 (403) 260-8657 [email protected]

Andrew Potter, CFA 1 (403) 221-5700 [email protected]

Shahzaib Merwat 1 (403) 216-8518 [email protected]

Ali Majid, P.Eng., CFA 1 (403) 216-3021 [email protected]

Nick Lupick 1 (403) 221-5049 [email protected]

Dennis Fong, P.Eng. 1 (403) 216-3404 [email protected] Adam Gill, CFA 1 (403) 216-3405 [email protected]

Ian Macqueen, P.Geol. 1 (403) 260-8675 [email protected]

Serhiy Petrenko 1 (403) 221-5047 [email protected]

Kyle Balaux 1 (403) 216-3401 [email protected]

Jeremy Mosher 1 (403) 260-8668 [email protected]

CIBC Resource Play Watch: Special Report - October 30, 2012

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Table Of Contents Introduction ............................................................................................3

Key Takeaways .....................................................................................3 Best Ways To Get Viking Exposure ...........................................................4 Executive Summary...............................................................................5

Greater Dodsland Viking............................................................................8 Viking Sub-areas .............................................................................9

Geological Overview............................................................................. 11 Reservoir Characteristics ...................................................................... 13 Application Of Technology..................................................................... 14

Average Measured Depth By Vintage ................................................ 16 Fracture Stimulation Density............................................................ 17

Active Operators And Areas ..................................................................... 18 Viking Productivity.................................................................................. 23

Distribution Of Peak Productivity ...................................................... 23 Development Of Up To 16 Wells Per Section....................................... 25 Distribution Of Productivity By Operator And Area............................... 27 Peak Sub-area Productivity By Vintage.............................................. 30 Peak Operator Productivity By Vintage .............................................. 31 Top 25 Southwest Saskatchewan Viking Wells.................................... 32 Type Well Expectations ................................................................... 33 Sub-area Productivity Relative To Type Curve Expectations.................. 35 GORs By Sub-area ......................................................................... 38

Viking Economic Evaluation................................................................... 39 Crown Vs. Freehold Land................................................................. 40 Where The Viking Fits..................................................................... 41 Per Section Rather Than Per Well Economics...................................... 42

Repeatability And Scalability ................................................................. 43 Supports Growth And A Dividend Model............................................. 43 Growth Scenario ............................................................................ 43 Free Cash Flow Scenario ................................................................. 47

Waterflood Feasibility........................................................................... 51 Waterflood The Key To Unlocking The Full Potential? ........................ 53 The Lower Viking Sequence Amenable To Flooding? ............................ 60

Facilities And Infrastructure .................................................................. 62 Land Sales ......................................................................................... 63 Company Summaries ........................................................................... 65 Appendix............................................................................................ 76

Sub-area Productivity ..................................................................... 76 Comparables ...................................................................................... 89


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Introduction The Viking play in southwest Saskatchewan has seen significant investment since the application of horizontal multi-stage technology over the last five years. Since late 2007, industry has spent over $1.5 billion in the broader Dodsland area, resulting in the drilling of over 1,300 horizontal Viking wells and 435 licenses to drill more. Clearly, the oil & gas industry is interested in the opportunity, but the Viking has never really captured investor interest due to the low productivity of its wells.

We contend that the large Original Oil In Place (OOIP), low recovery to date, low geological and capital risk, meaningful per section NPVs and a trend of improving productivity will continue to draw industry attention to the play and potentially result in a wave of consolidation. Its for these reasons that the play (and E&Ps in the play) need to be on investors radar screens.

In this report, we have segregated the Dodsland Viking into 12 sub-areas with the intent of digging into which areas offer better prospectivity and which producers have the best lands. Beyond that, we have discussed why the Viking should be examined on a larger scale for economic comparison, and why the opportunity offers more than many investors give the play credit for.

Key Takeaways 1. Ideal Play For Juniors And Intermediates. The lower geological risk,

strong netbacks (light oil) and lower total well costs ($0.85 million to $1.2 million) make the greater Dodsland Viking play very well suited to junior and intermediate producers.

2. Robust Economics. We estimate an average Dodsland Viking well requires ~ $60/Bbl for a pre-tax cost of capital return and a top-tier well requires ~$40/Bbl. At $80/Bbl, development of a section of Crown Viking land offers pre-tax NPVs of ~$10 million and IRRs of ~34%.

3. Capable Of Driving Strong Growth. Notwithstanding the lower well productivity, the higher well density supports strong production growth from a small area. At a density of 16 wells per section over a township (36 sections) of Viking land, an E&P can achieve a peak production rate of almost 7,000 Bbls/d after eight years living within cash flow.

4. Play Can Support A Dividend Model. The play can generate meaningful free cash flow, which could support strong growth and/or a dividend model. Our analysis shows that at $80/Bbl, development of a township of Crown Viking land can generate annual free cash flow in excess of ~$50 million for six years after reaching a peak production rate of ~5,000 Bbls/d.

5. Waterflood Upside Could Be Massive. The southwest Saskatchewan Viking has already shown to be amenable to waterflooding and if secondary recovery from the tighter Viking interval works (as preliminary results from tight oil waterfloods in the Bakken indicate it can), the upside is massive. We estimate the potential upside to be up in excess of 600 hundred million incremental recoverable barrels.

6. Expect Continued Consolidation. We have seen junior-on-junior consolidation in the Dodsland Viking (and expect that to continue given the lower well costs and strong economics), but have yet to see a larger player step in and consolidate the play. We do envision this happening; however, it may be dependent upon waterflood success in the lower Viking.

Industry has drilled over 1,300 horizontal Viking wells in the last five years.


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Best Ways To Get Viking Exposure Overall Top Viking Pick For investors interested in pure-play exposure to this play, our top pick is Raging River (RRX-SO). The company derives almost all of its production from the greater Dodsland Saskatchewan Viking and has shown strong year-over-year improvement in productivity. Raging River has focused its activities on highly prospective areas such as Dodsland South, Lucky Hills-Whiteside and Plato. The company controls 133 sections of Viking Rights in the greater Dodsland area and has ~100 locations booked. In our NAV analysis, we estimate the risked unbooked inventory in the greater Dodsland area to be ~408 wells, which translates into ~$190 million or $1.55/share in Risked NAV. On an unrisked basis, we estimate the unbooked inventory to be 840 wells, which is $376 million or $3.07/share in Unrisked NAV.

Picks For Highest Viking Exposure Raging River (mentioned above) and Novus (NVS-SP) stand out as our best ways to gain pure-play southwest Saskatchewan Viking Exposure. For Novus, ~85% of current production is from the Viking in Saskatchewan and ~98% of 2012 capital spending has been focused on the companys Saskatchewan Viking lands. Novus is focused primarily on the Viking in the Flaxcombe sub-area, where the companys wells have shown strong productivity. The company controls 124 sections of Viking Rights in the greater Dodsland area and has ~280 locations booked. In our NAV analysis, we estimate the risked unbooked inventory for the companys Dodsland inventory to be ~411 wells, which translate to ~$120 million or $0.62/share in Risked value. On an unrisked basis, we estimate the unbooked inventory to be 970 wells, which is $266 million or $1.38/share in Unrisked NAV.

High-yield Viking Pick With a current cash yield of ~8%, Penn West (PWT-SO) represents a good way for investors to get exposure to the play via a higher yielding entity. We note we believe the healthy economics at stable long-term decline rates characteristic of Viking wells make the Viking, in our opinion, an ideal asset for mid-sized dividend paying E&Ps. The Viking represents one of the four principle tight oil plays in Penn Wests inventory. In west central Saskatchewan, Penn West controls about 230 sections of Viking Rights in the greater Dodsland area, which could potentially support an inventory of ~3,700 unrisked locations at 16 wells per section spacing. In Alberta, Penn West controls another over 800 net sections of less proven Viking acreage. Penn West is by far the most active operator in the play, having drilled over 200 wells to date. In our NAV analysis, we estimate Penn Wests total risked unbooked Viking inventory to be ~1,500 wells, which is ~$991 million or $2.09/share in our Risked NAV.

Additional Ideas For Viking Exposure Whitecap (WCP-SO), an oil-weighted producer that derives ~13% of its production from the Dodsland Viking, has demonstrated very strong productivity at Lucky Hills-Whiteside. Given the strong cost improvements experienced by the company in the play and the strong productivity from the area, we would not be surprised to see Whitecap look to expand its footprint in the Viking. Whitecap controls 114 sections of Viking Rights in the greater Dodsland area and has ~46 locations booked. In our NAV analysis, we estimate the risked unbooked inventory of the companys Dodsland opportunity to be ~247 wells, which is ~$92 million or $0.72/share in Risked NAV. On an unrisked basis, we estimate the unbooked inventory to be 436 wells, which is $156 million or $1.23/share in Unrisked NAV.

In our coverage universe, Raging River and Novus offer pure-play Dodsland Viking exposure.

Penn West is our top Viking yield pick

Whitecap and Long Run control meaningful land positions and/or have shown strong results to date.


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Long Run (LRE-TSX) controls 183 net sections of Viking rights in the greater Dodsland area. This supports a potential inventory of ~2,900 unrisked locations at 16 wells per section spacing. Currently we estimate that these assets are producing over 2,000 Boe/d (~90% light oil); the area averaged 1,644 Boe/d in Q3/12 which included a number of late quarter tie-ins (9 of 15 wells brought on in the back half of the quarter). There are also a number of low decline legacy vertical wells which contributed about 18% of the Q3 average volumes. We do believe it likely that Long Run will sell these assets in the near-term; we estimate the market value to be at least $130 million (~$80,000/Boe/d based on the Q3 average) and could potentially go for over $155 million ($94,000+/Boe/d). We do note that there have been productivity challenges in the Plato area, but results in the area have been improving.

Executive Summary The southwest Saskatchewan Dodsland Viking oil play offers large OOIP, both over a large geographical area and on a per section basis. The greater Dodsland Viking oil play spans over 20 townships and extends over 116 miles from northwest to southeast and offers large OOIP, both in areal extent and on a per section basis. Including tighter horizons and halo areas in the play, we estimate there could be over six billion barrels of OOIP from the Viking, with estimated recovery to date at ~4%. On a per section basis, we estimate the OOIP to be 6 MMBbls to 11 MMBbls.

The Dodsland Viking oil play offers lower risk than other tight oil plays due to historical delineation and lower capital costs. The play has been actively developed since the mid-1950s (the target was a conventional upper Viking sequence), allowing for delineation of the play and de-risking of most of the sub-areas. The historical drilling in the play also went a long way in de-risking the areal extent of the lower, tighter sequence of the Viking formation. Although the sub-areas in the Viking do differ from each other geologically in terms of reservoir characteristics, the Viking formation within one sub-area remains relatively homogeneous, making drilling predictable and repeatable.

As the play is also fairly shallow and industry has moved to shorter lateral lengths (~600 meter lateral length), total well costs across the southwest Saskatchewan Viking range from $0.85 million to $1.2 million, depending on the operator. This is meaningfully cheaper than other tight oil plays in the Western Canadian Sedimentary Basin (WCSB). (The lower-risk profile and capital costs for the play are the primary reasons why there are so many small entrants in the play.)

The play has exhibited positive trends in productivity. We have seen per-well productivity improve to levels experienced in 2008, but with dramatically lower costs. Historically, the average or P50 well had a 30-day peak rate of ~36 Bbls/d. In 2012, the average or P50 well had a 30-day peak rate of 42 Bbls/d.

Despite the lower per well productivity, the higher well density supports strong production growth from a small area. Industry has been developing the play at a density of eight wells per section, but in many areas has increased the density of the projects up to 16 wells per section with encouraging results. The increased density projects have average productivity that closely resembles productivity from eight wells per section developments.

We estimate there are over six billion barrels of OOIP from the greater Dodsland Viking, with OOIP per section at 6 MMBbls to 11 MMBbls.

The lower geological risk and lower costs make the play very well suited for junior producers.

Productivity in 2012 has shown strong improvement over the prior years


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This higher well density can support very meaningful growth from a small area within the play. Assuming a density of 16 wells per section over a township (36 sections) of Viking land, an E&P can achieve a peak production rate of almost 7,000 Bbls/d after eight years (this scenario assumes spending within cash flow; the timing for peak productivity would be greatly accelerated with external financing). In addition, the peak decline rate achieved in the aforementioned growth scenario is ~33%, lower than many other tight oil plays in the WCSB.

The Dodsland Viking oil play offers meaningful per section NPVs. Given the low per well productivity, but higher well density characteristics of the play (~16 wells per section), it is more appropriate to examine the NPV of the play from a per section basis, as opposed to a per well basis. At $80/Bbl, development of a section of Crown Viking land offers pre-tax NPVs of ~$10 million and IRRs of ~34%. We estimate an average Dodsland Viking well requires ~$60/Bbl for a pre-tax cost of capital return and a top-tier well requires ~$40/Bbl.

The play can generate meaningful free cash flow and support the transition to a dividend model. Our analysis shows that at $80/Bbl, development of a township of Crown Viking land can generate annual free cash flow in excess of ~$50 million for six years after reaching a peak production rate of ~5,000 Bbls/d. This peak rate can be sustained with ~70 wells per year.

The waterflood potential in the Viking could be massive. The southwest Saskatchewan Viking has already shown to be amenable to waterflooding (multiple historical waterfloods in the upper Viking sequence in various sub-areas) and if secondary recovery from the tighter Viking intervals works (as preliminary results from another tight oil waterflood in the Bakken indicate it can), the upside is massive. At this point, the potential incremental recovery from a Viking waterflood project is anyones guess, but historical waterfloods indicate recovery can be in excess of 20%, which implies up to 600 million incremental recoverable barrels. We caveat as some areas will be better than others, and recovery wont be that high everywhere, but even half of the incremental potential is still enormous. In addition, if the waterflood is successful, it would mitigate production declines and make the play even more supportive of a dividend paying model. We also believe that waterflood upside in the tighter Viking interval could spark a wave of consolidation in the play. Raging River is currently piloting a horizontal waterflood, with preliminary results expected in early 2013. The current flood entails five vertical injectors and six horizontal producers.

A township of land can support growth to ~7,000 Bbls/d.

At $80/Bbl, development of a section of Crown Viking land offers pre-tax NPVs of ~$10 million and IRRs of ~34%.

The play can generate meaningful free cash flow, which can support a dividend model.

The upside potential from waterflooding the lower Viking sequence is massive, potentially in excess of 600 million barrels.

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Exhibit 1. Company Land Positions In Greater Dodsland

Source: geoSCOUT, Sherwin Geoedges, Canadian Discovery Digest, The Edge, Geological Atlas of Western Canada, Core Laboratories, company reports, CIBC World Markets Inc.


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Greater Dodsland Viking The greater Dodsland Viking oil play is located southwest of Saskatoon near the Saskatchewan/Alberta border (Township 24 Range 12W3 Township 34 Range 27W3). The play spans over 116 miles from northwest to southeast and offers large OOIP, both in areal extent and per section. Drilling in the play began in the 1950s, which has allowed for a broad delineation of the play and de-risking of most of the sub-areas.

One of the key highlights is that the Viking offers large OOIP and low recovery to date. According to government data, the Dodsland Viking play has two billion barrels of OOIP. However, we estimate there could be in excess of four billion barrels of incremental OOIP from tighter horizons and halo areas in the play. Based on our estimate of OOIP for the opportunity, we calculate recovery to be ~4%. As primary recovery is expected to be 8% to 10% (incremental recovery of between 200 million to 400 million barrels) and secondary recovery could be in excess of 20% (incremental recovery in excess of 600 million barrels), there is substantial resource yet to be captured by industry.

Exhibit 2 compares the OOIP from various resource plays in Western Canada and recovery to date. The Viking offers such large upside potential (enormous if secondary recovery schemes work) that we believe activity levels will be strong for years to come and consolidation will be a theme that will emerge over the next few years, first among smaller players and then possibly among larger industry participants.

The Dodsland Viking play offers large OOIP and low recovery to date.


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Exhibit 2. Resource Play Oil In Place Comparison (% Recovery)

5%7%

1%

4%

28%

16%

2% 2%

0.0

2.0

4.0

6.0

8.0

10.0

12.0

Cardium TightCarbonates

GreaterDodsland

Viking

Bakken LowerShaunavon

Pekisko Amaranth Montney Oil

Oil

in P

lace

(Bill

ion

Bbl

)

Remaining Oil in Place (Billion Bbl)Recovered Oil (Billion Bbl)

Source: Company reports and CIBC World Markets Inc.

Viking Sub-areas We have divided the greater Dodsland play into 12 sub-areas in order to determine which areas offer superior economics and which producers have exposure to the best acreage. Based on our analysis, it is clear that not all sub-areas are created equally. We also note that various operators are exploring the boundaries of the play beyond the sub-areas we have evaluated (Raging River at Beadle for instance, south of the Dodsland pool). However, the purpose of this review is to examine areas that have meaningful productive history from horizontal wells, with the goal of determining which sub-areas are better than others and which operators are showing the strongest results. Exhibit 3 shows the various sub-areas of the play.

We have divided the greater Dodsland play into 12 sub-areas for our comparison.

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Exhibit 3. Greater Dodsland Viking Sub-areas

Source: geoSCOUT, company reports and CIBC World Markets Inc.


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Geological Overview The Viking formation occupies the stratigraphy between two shales in the Lower Colorado sub-group, the lower being called the Joli Fou Formation. In the southwest Saskatchewan area, the Viking is ~690m 40m from surface. Within the trend, there are up-dip portions of the reservoir that are more gas-prone and down-dip portions that are oil-prone.

The formation is roughly divisible into two and sometimes three facies or parasequences. The upper Viking sand is generally characterized by alternating beds of shale, siltstone and (marine-influenced) sandstone. The lower sand has been noted to have a heterogeneous unsorted mixture of sandstone, shale and siltstone with some laminations. In some areas, the lower sand has been known to contain higher concentrations of shale. The Viking formation has been seen as a contiguous sand in the Dodsland proper area and several other areas in southwest Saskatchewan; however, a shale break exists between the upper and lower sands within Flaxcombe, Lucky Hills and Plato. The inter-bedded silt and shale influence the overall potential of the formation by creating tighter pore spaces and compartmentalizing parts of the reservoir.

Drilling in the play began in the 1950s targeting the upper sequence, which has allowed for a broad delineation of the play and has de-risked most of the sub-areas. In many cases, the amount of drilling in the play also de-risked the lower sequence of the Viking formation. Although the sub-areas do differ from each other geologically in terms of reservoir characteristics, the Viking formation within one sub-area remains relatively homogeneous, making drilling more predictable and repeatable.

Exhibit 4 shows Viking logs across the play in southwest Saskatchewan, with the intention of showcasing a representation of the broader play. The takeaways are that the Viking sand is present across the broader area, that there is more than one sequence, and that not all areas are created equal in terms of gross and/or net pay.

Exhibit 4. Geological Cross-section


The Dodsland Viking play is relatively shallow at 650 to 730 meters.

The upper sequence is a conventional reservoir. The lower sequence is compartmentalized or tighter.

PLATO FLAXCOMBE DODSLAND DODSLAND EASTLUCKY HILLS

67

5 7

00

72

5

Kv ik_base

Kvik_ss

77

5 8

00

TD 810.0m

Kv ik_base

Kvik_ss

67

5 7

00

Kv ik_base

Kvik_ss

67

5 7

00

Kv ik_base

Kvik_ss

70

0 7

25

Kv ik_base

Kvik_ss

WILD STREAM ET AL PLATO N 3-32-26-19

734.9 Raging River Expl+683.4

Mid_Viking_SS_bb OIL

101/03-32-026-19W3/00 (2273)A

NOVUS ET AL WHITESIDE 6-25-29-26

810.0 Novus Enrg Inc+751.3

Mid_Viking_SS_bb

2009/05/17

OIL

101/06-25-029-26W3/00 (2273)

CPI WHITESIDE B11-23-30-24

890.2 Whitecap Rsrcs Inc+701.4

Dtorquay

2005/07/20

OIL

121/11-23-030-24W3/00 (4414)

DANKIN DODSLAND 14-18-30-20

714.1 Raging River Expl+689.5

Kspinnyhl OIL

131/14-18-030-20W3/00 (2273)

CPEC DODSLAND 6-5-31-18

736.1 Crescent Point Enrg Corp+705.0

Mid_Viking_SS_bb OIL

101/06-05-031-18W3/00 (2273)

A'

1:24

0


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Although the Viking contains significant amounts of siltstone and shale, the bulk of porosity estimations range from 18% to 28% and gross thickness for the total package ranges from five to 12 meters. The upper zone is two to three meters thick and has been classified as a tighter but conventional reservoir. Estimations of total OOIP in this sequence are ~two billion barrels. The second sequence, consisting of siltier-sandstone, ranges in thickness from three to nine meters and has been described as being somewhat compartmentalized. Despite the compartmentalization, the second sequence has similar porosities as the upper zone and can add an incremental ~four billion barrels of OOIP to previous estimates. This characterizes the formation as having top-tier OOIP when compared to other plays across the WCSB. The following exhibit exemplifies the two Viking sequences.

Exhibit 5. View Of Compartmentalized Sands

2-3 m

3-9 m

Source: WestFire Energy disclosure and CIBC World Markets Inc.

The upper sequence is two to three meters in thickness and the lower sequence is three to nine meters for gross thickness of five to 12 meters.


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Reservoir Characteristics The following table shows our interpretation of the reservoir characteristics for each Viking sub-area. Our analysis indicates the estimated OOIP per section ranges from ~6 MMBbls to 11 MMBbls, with Avon Hills and Plato at the upper-end of the range and Kerrobert, Plenty and Prairiedale at the other end of the range.

The oil has been found to range from 32 to 38 API and is sweet. Initial water saturation in the formation was found to range between 35% and 45%. With respect to drive mechanisms, much of the Viking within the Greater Dodsland area has been found to be relatively oil-prone with little associated gas (this is the norm, but there are exceptions such Lucky Hills-Whiteside). This can be seen in the relatively normally pressured formations (average pressure gradient is ~0.4 psi/ft). The underlying Joli Fou shale shows little or no water-drive support nor does there appear to be an edge water-drive present.

Avon Hills and Plato stand out as having the highest OOIP/section, whereas Forgan, Prairiedale, Kindersley and Dodsland North stand out as having the highest initial pressures.

Exhibit 6. Dodsland Viking Reservoir Parameters

Avon HillsDodsland

NorthDodsland

SouthDodsland

East Flaxcombe Forgan Kerrobert KindersleyLucky Hills-Whiteside Plato Plenty Prairiedale

Gross Pay (meters) 10.0 11.9 9.4 7.7 11.8 9.0 5.3 14.2 10.9 11.0 5.6 12.0Net Pay (meters) 5.0 4.0 4.5 4.5 4.0 4.0 3.0 4.0 5.0 6.0 2.5 3.0Net/Gross Ratio 0.5 0.3 0.5 0.6 0.3 0.4 0.6 0.3 0.5 0.5 0.4 0.3Average Porosity (%) 24% 23% 22% 21% 23% 25% 23% 22% 21% 20% 24% 25%Water Saturation (%) 40% 45% 45% 40% 40% 40% 40% 45% 40% 40% 35% 40%Avg Depth to Top of Viking A Sand (meters) 691 675 684 689 708 692 687 702 686 703 677 696Avg Depth to Top of Viking B Sand (meters) 701 687 693 696 720 701 693 716 697 714 683 708Initial Pressure (psi) 806 935 891 827 891 939 680 928 860 847 828 985Formation Volume Factor (Bbl/Bbl) 1.110 1.110 1.050 1.050 1.091 1.111 1.103 1.111 1.105 1.089 1.111 1.111Est OOIP/section - net basis (MMBbl) 10.6 7.5 8.4 8.8 8.2 8.9 6.1 7.1 9.3 11.2 5.7 6.6Oil Gravity (API) 36 37 37 37 30 37 37 32 34 33 34 31 Source: Company reports, geoSCOUT, Canadian Discovery Digest and CIBC World Markets Inc.

Our volumetric analysis indicates the estimated OOIP per section ranges from ~6 MMBbls to 11 MMBbls of 32 to 38 API sweet oil.


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Application Of Technology The Viking play has been developed vertically since the mid-1950s, with the peak in the 1980s. Since then, the play has been in decline until the implementation of horizontal drilling and multi-stage fracture stimulation late in 2007. As shown in the following exhibit, the application of the innovative new technology has caused a resurgence of activity and growth in the play. Over 1,300 horizontal wells have been drilled in the play, of which 1,137 are on production, with another 435 horizontal wells licensed to be drilled at the time of this report.

Exhibit 7. Historical Viking Oil Production In SW Saskatchewan

0

5,000

10,000

15,000

20,000

25,000

30,000

Jan-

54

Jan-

56

Jan-

58

Jan-

60

Jan-

62

Jan-

64

Jan-

66

Jan-

68

Jan-

70

Jan-

72

Jan-

74

Jan-

76

Jan-

78

Jan-

80

Jan-

82

Jan-

84

Jan-

86

Jan-

88

Jan-

90

Jan-

92

Jan-

94

Jan-

96

Jan-

98

Jan-

00

Jan-

02

Jan-

04

Jan-

06

Jan-

08

Jan-

10

Jan-

12

Bbl

/d

0

1,000

2,000

3,000

4,000

5,000

6,000

Num

ber o

f wel

ls

Horizontal Oil Production (Bbl/d)Vertical Oil Production (Bbl/d)Number of Horizontal WellsNumber of Vertical Wells


As mentioned in the geological summary of this report, the bulk of vertical drilling has targeted the upper Viking sand. The advent of horizontal drilling and multi-stage fracturing technology has opened up the lower, tighter and more compartmentalized silty-sandstone sequence. Vertical drilling had achieved limited success in producing and recovering the compartmentalized oil from the lower zone. The second sequence has a similar porosity to the upper Viking sand, but is several meters thicker. This increases the oil in place from two billion barrels to over six billion barrels for the entire Dodsland play.

Over 1,300 horizontal wells have been drilled in the play in the last five years.


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The use of horizontal drilling in the Viking has shown cost improvement over the last few years. In 2008, the average horizontal section was 1,100 meters to 1,200 meters, with total well costs of $1.5 million to $2 million+. From 2009 to 2012, the wells were drilled with an average ~800 meter horizontal section (including a ~185 meter kick-off). The progression from longer to shorter laterals has occurred for two reasons. The shorter horizontal wells had better operational efficiencies than the longer wells, and to capitalize on the Saskatchewan royalty holiday.

There has also been a progression of improving costs in both drilling (shorter laterals are only a part of the cost improvement) and completion techniques, bringing costs down to under $1 million today. The major savings and improvements can be broken down into four main categories.

1. Monobore drilling traditional horizontal drilling utilizes progressively smaller diameter holes and setting multiple layers of casing inside a wellbore during drilling operations, creating inefficiencies. Monobore drilling simplifies the design by drilling a single uniform diameter hole through to the formation before cementing in the production casing.

2. Improved geosteering technology ensuring that the wellbore stays within the 3-9 meter window of the Viking formation contributes to an improvement in well performance.

3. Improved fracturing techniques the ability to increase the number of stages and increase control of the placement of sand within the formation is critical to post-completion well performance and cost control. For instance, when Reece Energy began drilling horizontal wells into the play in 2007, the company fracd the horizontal wells with 12 to 15 stages over a ~1,200 meter lateral. Today, companies are fracing the wells with over 15 stages in half the lateral length. To achieve this frac density four years ago would have been leading-edge and costly.

4. Pad well planning

Lower lease construction costs;

Lower drilling rig re-location costs between drills;

Economies of scale for purchase and transportation of completions fluids and sand;

Lower completion rig re-location costs; and

Shared wellsite storage facilities, instrumentation, and transportation of oil.

There has been significant cost improvement in the play over the last five years.


16

Average Measured Depth By Vintage The following table shows the average well lengths for the Viking in 2008, 2009, 2010, 2011 and 2012. Two items are evident from the table.

1. Industry has moved away from ~1,200 meter long lateral lengths to 600 meter lateral lengths (~800 meter lengths including the build section of the well) as the play evolved. This was to capture the benefit of the non-deep horizontal royalty incentive in Saskatchewan, as well as mitigation of operational risk with the shorter lateral length.

2. There has been a trend of improving well productivity with the shorter lateral lengths over time. The average peak 30-day IP rate in 2009 was 39 Bbls/d; in 2012, it has been 43 Bbls/d (the median well in 2012 had an average peak rate of ~42 Bbls/d). The horizontal length of wells has remained relatively flat from 2009 onwards. Costs to drill, complete and tie-in wells have trended downward over the same period. Estimated costs per well of $1.4 million at the beginning of 2009 have fallen to $0.85-$1.2 million in 2012 for similar length horizontal wells. Improvements in drilling and completion techniques as well as the switch to pad drilling have been the primary contributors to cost savings.

Exhibit 8. Average Viking Well Total Measured Depth

54.0

38.9 39.2

42.6 43.2

1,000

1,100

1,200

1,300

1,400

1,500

1,600

1,700

1,800

1,900

2,000

2,100

2,200

2,300

2008 (40)wells

2009 (28)wells

2010 (291)wells

2011 (494)wells

2012 (284)wells

Ave

rage

Tot

al M

easu

red

Dep

th o

f Vik

ing

Wel

l (m

)

0

10

20

30

40

50

60

Ave

rage

Pea

k R

ate

(Bbl

/d)

Average Length (m)Average Peak 30 Day Rate (Bbl/d)

Total well costs $1.5-$2.0 million



Costs have come down as productivity in the shorter lateral wells has gone up.


17

Fracture Stimulation Density With the shorter laterals in 2009, operators also decreased the frac density to ~nine fracs per well from ~12 with the longer laterals in 2008. This increased to ~11 for 2010 and 2011 (although productivity improved) and has risen back to almost ~12 in 2012, resulting in the best average peak productivity per shorter lateral well. We note that many operators are implementing up to 15 fracs per shorter lateral well, which is one of the reasons why productivity has continued to improve. Keep in mind that costs over the last four years have continued to decrease.

Exhibit 9. Average Frac Density By Vintage

38.9 39.2

42.6 43.2

54.0

0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

2008 (40)wells

2009 (28)wells

2010 (291)wells

2011 (494)wells

2012 (284)wells

Ave

rage

Num

ber o

f Fra

ctur

e-St

imul

atio

ns

0

10

20

30

40

50

60

Ave

rage

Pea

k R

ate

(Bbl

/d)

Average Number of Fracture-StimulationsAverage Peak 30 Day Rate (Bbl/d)




Frac densities are near what they were in 2008, but with half the lateral length.


18

Active Operators And Areas The following map shows the industry players targeting the Dodsland Viking play in Saskatchewan.

Exhibit 10. Company Land Positions In Greater Dodsland

Source: geoSCOUT, Sherwin Geoedges, Canadian Discovery Digest, The Edge, Geological Atlas of Western Canada, Core Laboratories, company reports, CIBC World Markets Inc.


19

Being a first mover into the area, Penn West is one of the larger land holders within southwest Saskatchewan Viking with over 230 net sections. The bulk of its land is concentrated in the prospective Avon Hills, Dodsland South & North, Flaxcombe, and Lucky-Hills Whiteside areas (the Kerrobert property is to be sold to Beaumont, a private co). Other operators with meaningful land positions are Teine (although a meaningful portion of the acreage is gas prone north of the main Dodsland pool), Devon (DVN-NYSE) and Long Run.

Exhibit 11. Southwest Viking Land Positions By Producers

297

230220

197

150 150133

124114 113

8573 70

60 56 5033 27 21 13

0

50

100

150

200

250

300

350

Teine Penn West Devon Long Run Husky ISH EnergyRaging River Novus Whit ecapResources

Crescent Point CNRL Beaumont Enerplus Imperial RangeResources

ConocoPhillipsManulif e Renegade Bayt ex ARC

Net

Sec

tions



20

The following table showcases horizontal wells drilled by producers and well locations. We surmise that as a result of recent changes in gas conservation regulations, companies may have licensed many wells to benefit from a grandfathering clause. We note that licenses expire after one year and Saskatchewans regulator has capped the number of drilling deferrals for the year.

Exhibit 12. Horizontal Wells Drilled And Licensed By Producer

0

50

100

150

200

250

Pennwest Teine Novus Renegade Whitecap WestfireRaging RiverCrescentPoint

NALResource

Management

ISH Energy Harvest Flagstone Polar Star 3 MV Husky Cirdan HomeQuarter

Invicta Devon AllstarEnergy

Enerplus Baytex Cenovus Spur ARC

LicensesHZ Wells



21

Exhibit 13 summarizes the top operators and the top focus areas in the Viking since industry began drilling horizontal wells into the play in late 2007. Penn West leads the pack with ~17% of drilling in the play over the last five years, followed by Novus, Teine and Renegade (RPL-V). Exhibit 14 summarizes the top operators and the top focus areas in the Viking since industry began drilling horizontal wells into the play. Areas that have seen the most activity have been Avon Hills, Dodsland South, Flaxcombe and Lucky Hills-Whiteside.

Exhibit 13. Top Operators By Vintage (number of wells)

Operator

Penn West Petrl Ltd 25 63% 9 32% 59 20% 72 15% 21 8% 184 17%Novus Enrg Inc 3 8% 1 4% 35 12% 53 11% 29 10% 121 11%Teine Enrg Ltd 1 3% 0 0% 32 11% 46 9% 40 14% 119 10%Renegade Petrls Ltd 0 0% 0 0% 25 9% 47 10% 31 11% 103 9%Whitecap Rsrcs Inc 0 0% 0 0% 12 4% 38 8% 19 7% 69 6%Crescent Point Enrg Corp 4 10% 3 11% 20 7% 27 5% 0 0% 54 5%NAL Rsrcs Lmtd 1 3% 0 0% 18 6% 32 6% 1 0% 52 5%Long Run Expl 3 8% 5 18% 7 2% 6 1% 30 11% 51 4%Raging River Expl Inc 0 0% 1 4% 19 7% 17 3% 13 5% 50 4%Harvest Oprtns Corp 0 0% 0 0% 9 3% 23 5% 13 5% 45 4%ISH Enrg Ltd 0 0% 0 0% 0 0% 19 4% 24 8% 43 4%Polar Star Cdn O&G Inc 0 0% 1 4% 8 3% 16 3% 6 2% 31 3%Husky Oil Oprtns Ltd 0 0% 0 0% 7 2% 12 2% 9 3% 28 2%Flagstone Enrg Inc 0 0% 4 14% 9 3% 11 2% 1 0% 25 2%Invicta Enrg Corp 0 0% 0 0% 3 1% 9 2% 12 4% 24 2%Home Quarter Rsrcs Ltd 0 0% 0 0% 3 1% 13 3% 8 3% 24 2%Allstar Enrg Lmtd 0 0% 0 0% 5 2% 10 2% 5 2% 20 2%3MV Energy 0 0% 4 14% 9 3% 6 1% 0 0% 19 2%Devon Enrg Corp 0 0% 0 0% 2 1% 15 3% 0 0% 17 1%Cirdan Rsrcs Inc 0 0% 0 0% 1 0% 5 1% 7 2% 13 1%Enerplus Corp 0 0% 0 0% 5 2% 7 1% 0 0% 12 1%Baytex Enrg Ltd 3 8% 0 0% 3 1% 3 1% 0 0% 9 1%Spur Rsrcs Ltd 0 0% 0 0% 1 0% 0 0% 2 1% 3 0%Cenovus Energy 0 0% 0 0% 0 0% 1 0% 1 0% 2 0%Average 40 100% 28 100% 291 100% 494 100% 284 100% 1120 100%

2012 Total2008 2009 2010 2011


Penn West has been the most active operator in the play, followed by Novus and Teine.

CIB

C R

eso

urce

Pla

y W

atch

: Sp

ecia

l Rep

ort - O

ctob

er 3

0, 2

01

2

22

Exhibit 14. Top Operators By Area (number of wells) Operator

Penn West Petrl Ltd 146 64% 29 32% 2 2% 0 0% 0 0% 2 4% 0 0% 0 0% 3 6% 0 0% 2 7% 0 0% 184 17%Novus Enrg Inc 9 4% 3 3% 24 19% 1 1% 3 3% 1 2% 66 60% 3 4% 5 10% 0 0% 5 17% 2 4% 122 11%Teine Enrg Ltd 41 18% 1 1% 28 22% 10 6% 0 0% 12 21% 0 0% 0 0% 4 8% 0 0% 0 0% 10 22% 106 10%Renegade Petrls Ltd 5 2% 10 11% 29 23% 35 21% 0 0% 3 5% 12 11% 0 0% 9 18% 0 0% 0 0% 0 0% 103 9%Whitecap Rsrcs Inc 0 0% 0 0% 0 0% 64 39% 2 2% 0 0% 0 0% 0 0% 0 0% 3 9% 0 0% 0 0% 69 6%Crescent Point Enrg Corp 0 0% 0 0% 2 2% 0 0% 19 21% 32 57% 0 0% 1 1% 0 0% 0 0% 0 0% 0 0% 54 5%NAL Rsrcs Lmtd 0 0% 9 10% 6 5% 0 0% 0 0% 4 7% 0 0% 0 0% 0 0% 0 0% 0 0% 33 72% 52 5%Long Run Expl 0 0% 0 0% 0 0% 2 1% 43 47% 0 0% 0 0% 1 1% 3 6% 0 0% 0 0% 1 2% 50 5%Raging River Expl Inc 0 0% 2 2% 37 29% 1 1% 9 10% 0 0% 0 0% 0 0% 0 0% 1 3% 0 0% 0 0% 50 5%Harvest Oprtns Corp 1 0% 22 24% 0 0% 0 0% 0 0% 0 0% 22 20% 0 0% 0 0% 0 0% 0 0% 0 0% 45 4%ISH Enrg Ltd 5 2% 0 0% 0 0% 5 3% 0 0% 0 0% 0 0% 0 0% 0 0% 13 39% 20 69% 0 0% 43 4%Polar Star Cdn O&G Inc 14 6% 0 0% 0 0% 14 8% 0 0% 0 0% 0 0% 0 0% 1 2% 0 0% 0 0% 0 0% 29 3%Husky Oil Oprtns Ltd 0 0% 0 0% 0 0% 0 0% 2 2% 2 4% 0 0% 24 35% 0 0% 0 0% 0 0% 0 0% 28 3%Flagstone Enrg Inc 0 0% 0 0% 0 0% 0 0% 2 2% 0 0% 0 0% 23 33% 0 0% 0 0% 0 0% 0 0% 25 2%Invicta Enrg Corp 0 0% 0 0% 0 0% 24 15% 0 0% 0 0% 0 0% 0 0% 0 0% 0 0% 0 0% 0 0% 24 2%Home Quarter Rsrcs Ltd 0 0% 0 0% 0 0% 2 1% 4 4% 0 0% 9 8% 8 12% 0 0% 0 0% 0 0% 0 0% 23 2%Allstar Enrg Lmtd 0 0% 0 0% 0 0% 4 2% 0 0% 0 0% 0 0% 0 0% 0 0% 15 45% 0 0% 0 0% 19 2%3 Martini Ventures Inc 4 2% 8 9% 0 0% 0 0% 0 0% 0 0% 0 0% 0 0% 5 10% 1 3% 0 0% 0 0% 18 2%Devon Nec Corp 0 0% 0 0% 0 0% 0 0% 8 9% 0 0% 0 0% 9 13% 0 0% 0 0% 0 0% 0 0% 17 2%Cirdan Rsrcs Inc 0 0% 0 0% 0 0% 0 0% 0 0% 0 0% 0 0% 0 0% 13 26% 0 0% 0 0% 0 0% 13 1%Enerplus Corp 4 2% 7 8% 0 0% 0 0% 0 0% 0 0% 0 0% 0 0% 0 0% 0 0% 0 0% 0 0% 11 1%Baytex Enrg Ltd 0 0% 0 0% 0 0% 1 1% 0 0% 0 0% 0 0% 0 0% 7 14% 0 0% 1 3% 0 0% 9 1%Spur Rsrcs Ltd 0 0% 0 0% 0 0% 2 1% 0 0% 0 0% 1 1% 0 0% 0 0% 0 0% 0 0% 0 0% 3 0%ARC Rsrcs Ltd 0 0% 0 0% 0 0% 0 0% 0 0% 0 0% 0 0% 0 0% 0 0% 0 0% 1 3% 0 0% 1 0%Average 229 100% 91 100% 128 100% 165 100% 92 100% 56 100% 110 100% 69 100% 50 100% 33 100% 29 100% 46 100% 1098 100%Total 21% 8% 12% 15% 8% 5% 10% 6% 5% 3% 3% 4%

Avon Hills Dodsland North Dodsland South Lucky Hills-Whiteside

Plato Dodsland East Flaxcombe Forgan TotalKerrobert Kindersley Prairiedale Plenty

Note: We have only included company-operated wells within the sub-areas. Source: geoSCOUT, company reports and CIBC World Markets Inc.


23

Viking Productivity Distribution Of Peak Productivity The following table shows the distribution of peak 30-day rates (calendar-day basis) for all oil wells in the play with over three months of production history. As we see below, the P50 30-day peak rate is 36 Bbls/d, with the P90 being 10 Bbls/d and the P10 being 78 Bbls/d. In 2012, the P90 peak rate has decreased to 7 Bbls/d, the P50 peak rate has increased to 42 Bbls/d and the P10 peak rate has increased to 86 Bbls/d.

Exhibit 15. Peak 30-day Productivity Distribution

2008 to 2012

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

0 20 40 60 80 100 120 140 160 180 200

Peak 30 Day Rate (Bbl/d)

Cum

ulat

ive

Dis

trib

utio

n

P90 = 10 Bbl/d

P50 = 36 Bbl/d

P10 = 78 Bbl/d

The median well has historically had a peak 30-day rate of 36 Bbls/d. In 2012, that increased to 42 Bbls/d.


24

2012

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

0 20 40 60 80 100 120 140 160 180 200


Cum

ulat

ive

Dis

trib

utio

n

P90 = 7 Bbl/d

P50 = 42 Bbl/d

P10 = 86 Bbl/d



25

Development Of Up To 16 Wells Per Section In the following exhibit, we have highlighted the multiple areas where industry participants have employed the concept of more than eight wells per section (or two wells per quarter section), up to a density of 16 wells per section. The various projects that are piloting up to 16 wells per section (over 292 horizontal wells from nine different producers over a 25 township area) are across Dodsland, not just in an isolated area. The conclusion is that preliminary productivity from the higher density wells is slightly better than (and at least in line with) developments at eight wells or less per section.

Exhibit 16. Locations Of 16 Wells Per Section Downspacing Projects


As the following table shows, the increased density projects have demonstrated productivity that is in line after a higher IP rate than the average well productivity from the broader play.

Productivity from the higher density wells has shown to be slightly better than (and at least in line with) developments at eight wells or less per section.


26

Exhibit 17. Downspaced Well Productivity Comparison

Prd-Day Greater Dodsland Viking Well Downspacing Analysis

1

10

100

0 5,000 10,000 15,000 20,000 25,000Cumulative Production (Bbl)

Prod

uctio

n (Bb

l/d)

Prd-day Horizontal Viking Wells At Over 8 Wells/Section (292 wells)

All Horizontal Viking Wells (805 wells)

Cal-Day Greater Dodsland Viking Well Downspacing Analysis

0

10

20

30

40

50

60

1 7 13 19 25 31Months On-stream

Prod

uctio

n (B

bl/d

)

Cal-day Horizontal Viking Wells At Over 8 Wells/Section (292 wells)

All Horizontal Viking Wells (805 wells)



27

Distribution Of Productivity By Operator And Area For companies under coverage that had a statistically significant sample set of results, we have plotted the peak 30-day productivity distribution for all wells drilled (by the operators) in prior years that had more three months of production history and all wells in 2012 (no minimum productivity time required).

We have not included all operators in the Viking as the distribution chart would become convoluted, but have included a bar chart in Exhibit 21 on page 31 that shows the average peak 30-day rate by vintage for most operators in the play.

Following the peak 30-day productivity distributions, we have shown the six month cumulative production distribution by sub-area. It is noteworthy to point out that the operators with the best peak productivity coincide with the best areas. Penn West has shown the strongest results and operates in Avon Hills and Dodsland South. Whitecap stands out as having some of the better results in the top performing wells, which is not surprising as it operates in Lucky Hills- Whiteside. Raging River has strong P50 productivity in 2012, as it operates in Dodsland South, Lucky Hills-Whiteside and Plato.


28

Exhibit 18. Peak 30-day Productivity Distribution By Producer

Cumulative Distribution of Peak 30-day Rate Productivity

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

0 25 50 75 100 125 150

Peak 30-day Rate (Bbl/d)

Cum

ulat

ive

Dis

trib

utio

n

Crescent Point Enrg Corp Novus Enrg Inc Penn West Petrl LtdRaging River Expl Inc Long Run Expl Whitecap Rsrcs IncEnerplus Corp Baytex Enrg Ltd Husky Oil Oprtns Ltd

P50

Penn West stands out as having the best distribution of well results.

Whitecap (and Enerplus with a small sample set) stand out as having the highest productivity on the distribution of its better wells.

Cumulative Distribution of Peak 30-day Rate Productivity (2012 Wells)

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

0 25 50 75 100 125 150


Cum

ulat

ive

Dis

trib

utio

n

Novus Enrg Inc Penn West Petrl Ltd Raging River Expl IncLong Run Expl Whitecap Rsrcs Inc Husky Oil Oprtns Ltd

P50

Raging River has shown a strong improvement in productivity over previous years.

Note: CPG does not have any operated wells in 2012. Source: geoSCOUT, company reports and CIBC World Markets Inc.


29

Exhibit 19. Cumulative Distribution Of Six Month Production By Sub-area

Cumulative Distribution of Six Month Production Horizontal Viking Production by Sub-Area

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

- 5,000 10,000 15,000 20,000 25,000

6 Month Cumulative Production (Bbl)

Cum

ulat

ive

Dis

trib

utio

n

Avon Hills Dodsland North Dodsland South Lucky Hills-WhitesidePlato Dodsland East Flaxcombe ForganKerrobert Kindersley Prairiedale Plenty

P50

Avon Hills and Dodsland South show the best P50 productivity both historically and in 2012. Lucky Hills-Whiteside, Flaxcombe and Forgan stand out as having some of the better productivity in the top 50th percentile of the distribution.

Cumulative Distribution of Peak 30-day Rate Horizontal 2012 Viking Production by Sub-Area

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

0 25 50 75 100 125 150

Peak 30-day Rate (Bbl/d)

Cum

ulat

ive

Dis

trib

utio

n

Avon Hills Dodsland North Dodsland South Lucky Hills-WhitesidePlato Dodsland East Flaxcombe ForganKerrobert Kindersley Prairiedale

P50

Plato production has improved dramatically in 2012 when compared to historical productivity.



30

Peak Sub-area Productivity By Vintage The following exhibit shows the average peak rate by sub-area for 2008 to 2012. The sub-areas are ranked by 2012 peak 30-day production rates. This is essentially a summary of the calendar-day productivity for each sub-area by vintage from the appendix. Avon Hills and Dodsland South stand out as having consistently superior results (although Dodsland South did not screen as having any wells on-stream in 2009). Dodsland North shows well in 2012 as does Dodsland East, however the Dodsland East wells decline very quickly.

Exhibit 20. Average Peak Rates By Sub-area

0

10

20

30

40

50

60

70

80

DodslandNorth

DodslandEast

Avon Hills DodslandSouth

Forgan LuckyHills-

Whiteside

Plato Kerrobert Kindersley Prairiedale Flaxcombe Plenty

Peak

-30

Day

Rat

e (B

bl/d

)

20082009201020112012

Source: geoSCOUT and CIBC World Markets Inc.

Avon Hills and Dodsland South stand out as having consistently superior results.


31

Peak Operator Productivity By Vintage The following exhibit shows the productivity by producer by vintage. We ranked the productivity by 2012 average peak rates. Penn West stands out as having the best well performance; the company has a large land base in the top-performing areas of Avon Hills and Dodsland North. This is followed by Whitecap, Raging River, Husky (HSE-SP) and Novus.

Exhibit 21. Average Peak IP Rate By Operator

0

10

20

30

40

50

60

70

80

Penn

Wes

t

Whi

teca

p

Rag

ing

Riv

er

Hus

ky

Nov

us

Alls

tar E

nerg

y

Long

Run

Ren

egad

e

Tein

e

Cird

an

Invi

cta

ISH

Ene

rgy

Har

vest

Cen

ovus

Arc

Res

ourc

es

Ener

plus

NA

L R

esou

rce

Man

agem

ent

Cre

scen

t Poi

nt

3 M

V

Dev

on

Pola

r Sta

r

Hom

e Q

uart

er

Flag

ston

e

Bay

tex

Spur

Peak

Rat

e (B

bl/d

)

20082009201020112012

Source: Company reports, geoSCOUT and CIBC World Markets Inc.

Penn West stands out as having the best well performance in 2012, followed by Whitecap and Raging River.


32

Top 25 Southwest Saskatchewan Viking Wells The following exhibit shows the top 25 horizontal Viking wells by the 30-day peak rate. The best wells have consistently been at Avon Hills, Forgan and Lucky Hills-Whiteside. The producers seen multiple times in the top 25 peak 30-day rate horizontal Viking wells are Husky, Whitecap, Renegade and Penn West.

Exhibit 22. Top 25 Dodsland Viking Wells

Date On Mnths %Rank Operator Sub-Area UWI (Well Location) Stream On Peak 30-day Current Gas Horizontal Vertical1 Husky Oil Oprtns Ltd Forgan 191/09-23-024-15W3/00 2/17/2010 31 247 69 0% 1,323 6552 Whitecap Rsrcs Inc Lucky Hills-Whiteside 191/16-26-030-24W3/00 11/16/2011 10 240 48 16% 572 7033 Whitecap Rsrcs Inc Lucky Hills-Whiteside 191/10-24-030-24W3/00 2/1/2011 19 183 21 0% 553 7004 Teine Enrg Ltd Dodsland South 191/16-08-030-21W3/00 2/20/2010 31 150 20 0% 544 7005 Flagstone Enrg Inc Forgan 191/13-13-024-15W3/00 10/31/2010 23 148 44 0% 467 6766 Renegade Petrls Ltd Lucky Hills-Whiteside 191/14-25-030-24W3/00 7/7/2011 14 144 44 0% 604 7007 Renegade Petrls Ltd Lucky Hills-Whiteside 191/15-25-030-24W3/00 7/16/2011 14 131 33 0% 546 6758 Penn West Petrl Ltd Dodsland South 191/03-30-030-21W3/00 1/24/2012 8 122 65 10% 1,363 7039 Renegade Petrls Ltd Lucky Hills-Whiteside 192/15-25-030-24W3/00 2/22/2012 7 117 82 0% 648 65810 Husky Oil Oprtns Ltd Forgan 192/10-13-025-15W3/00 1/26/2012 8 117 95 0% 645 73611 Husky Oil Oprtns Ltd Forgan 191/13-14-024-15W3/00 1/20/2011 20 113 57 0% 503 70012 Renegade Petrls Ltd Lucky Hills-Whiteside 191/08-29-030-23W3/00 7/12/2011 14 110 31 0% 1,083 68313 Renegade Petrls Ltd Lucky Hills-Whiteside 192/04-28-030-23W3/00 8/28/2011 13 110 34 0% 612 67014 Penn West Petrl Ltd Avon Hills 191/06-36-030-22W3/00 10/14/2010 23 110 20 9% 1,117 67715 Renegade Petrls Ltd Lucky Hills-Whiteside 191/13-25-030-24W3/00 8/4/2011 13 109 24 0% 548 70016 Penn West Petrl Ltd Dodsland South 192/16-19-030-21W3/00 11/8/2011 10 106 45 12% 544 70017 Penn West Petrl Ltd Dodsland South 191/09-19-030-21W3/00 11/7/2011 10 106 42 10% 554 70218 Penn West Petrl Ltd Avon Hills 191/11-28-030-22W3/00 9/14/2011 12 106 40 14% 701 70019 Whitecap Rsrcs Inc Lucky Hills-Whiteside 191/05-19-030-23W3/00 8/1/2010 25 104 13 6% 567 70020 Penn West Petrl Ltd Avon Hills 191/16-33-030-22W3/00 11/19/2009 34 103 22 5% 605 70521 Penn West Petrl Ltd Avon Hills 191/03-32-030-22W3/00 8/10/2010 25 102 21 8% 602 71522 Penn West Petrl Ltd Avon Hills 192/04-33-030-22W3/00 5/10/2008 52 94 13 4% 1,133 65723 Novus Enrg Inc Flaxcombe 192/16-19-030-25W3/00 7/9/2011 14 93 69 12% 1,154 69524 Penn West Petrl Ltd Avon Hills 191/11-15-030-22W3/00 2/20/2012 7 93 93 10% 537 73625 Husky Oil Oprtns Ltd Forgan 191/06-23-024-15W3/00 10/27/2011 11 90 50 0% 583 651

Prod (Boe/d) Depth (Meters)


The producers seen multiple times in the top 25 peak 30-day rate horizontal Viking wells are Husky, Whitecap, Renegade and Penn West.


33

Type Well Expectations We have provided a table that shows the various type wells used by an industry consultant to determine recoverable reserves. The industry consultant uses nine tiers for an assumed density of eight horizontal wells per section (with shorter lateral lengths of ~600 meters per well) for the various sub-areas in the southwest Saskatchewan Viking. We have provided economics for the various tiers in Exhibit 28 on page 39.

Exhibit 23. Industry Consultants Viking Tiers Eight Wells Per Section

Southwest Saskatchewan Viking Oil

-

10

20

30

40

50

60

70

80

90

1 7 13 19 25 31 37 43 49 55 61 67 73 79 85 91 97 103 109 115 121

Months

Bbl

/d

Tier 9 - 70 MBbl

Tier 8 - 65 MBbl

Tier 7 - 60 MBbl

Tier 6 - 50 MBbl

Tier 5 - 40 MBbl

Tier 4 - 35 MBbl

Tier 3 - 25 MBbl

Tier 2 - 20 MBbl

Tier 1 - 15 MBbl


In addition, the industry consultant uses an additional nine tiers for an assumed density of 16 horizontal wells per section. This second group essentially applies a 25% reduction to the EUR for each tier for the higher density scenario. For example, assuming eight wells per section, a Tier 5 well is expected to recover 40 MBbls, but assuming 16 wells per section, a Tier 5 well is expected to recover 30 MBbls.

An industry consultant categorizes the play into nine tiers. A Tier 5 curve (40 MBbls) is generally recognized as the average well for the play.


34

Exhibit 24. Industry Consultants Viking Tiers Eight Versus Sixteen Wells Per Section

Southwest Saskatchewan Viking Oil

-

5

10

15

20

25

30

35

40

45

1 7 13 19 25 31 37 43 49 55 61 67 73 79 85 91 97 103 109 115 121

Months

Bbl

/d

Tier 5 - 40 MBbl at eightwells per section

Tier 5 - 30 MBbl at sixteenwells per section


One point we want to highlight is that assuming a density of ~16 wells per section at a Tier 5 curve (generally recognized as the average well for the play) implies ~480 MBbls of recoverable oil. Based on our analysis, we estimate the range of OOIP for the greater Dodsland area to be ~6 MMBbls to 11 MMBbls per section. Based on our estimates, a full development scenario or 16 wells per section implies recovery of between 4% and 8%. As industry participants expect recovery to be closer to ~10% on primary, it is possible there is upside to the increased density type wells.


35

Sub-area Productivity Relative To Type Curve Expectations In the following section, we have compared the vintage productivity by sub-area to an industry consultants type curves to determine a sense of the EUR for each sub-area. (For context, Tier 5 is usually assumed as the average curve for the entire play, so areas trending below that are deemed to be poorer than the average for the play.) We caveat that in the final periods of the vintage productivity, the number of wells is low, so the tail-end of productivity can be misleading (productivity at Flaxcombe and Forgan is a great example of this as it increases with the lower well count). However, the earlier periods in the vintage productivity profile provide a better view of what the average profile could look like.

A few trends emerge from our review. Clearly some sub-areas are better than others. There is a marked improvement in productivity in 2012 and it seems to be coming close to productivity experienced in 2008 when industry utilized longer lateral wells. Also, it seems that the productivity typically starts at a higher tier than the tier it tracks after it levels out.

We provide the productivity profiles both on a calendar-day basis (which does not adjust for downtime and interrupted operating conditions) over time, which better represents the cash flow stream expected, and on a producing-day basis relative to cumulative production, which provides a better representation of EUR. We have also included the productivity profiles for each sub-area by vintage in the appendix.

For the comparison of calendar day production over time in Exhibit 25, Avon Hills and Lucky Hills-Whiteside have consistently shown strong results. In 2012, Dodsland North and Plato (as did Dodsland East but production came off sharply) showed marked improvement. Peak rates in 2012 are higher than in previous years in almost every sub-area.

For the comparison of producing day production relative to cumulative production in Exhibit 26, the comments are similar as above. Avon Hills, Lucky Hills-Whiteside, Dodsland South, Flaxcombe and Forgan have historically shown above-average cumulative production relative to producing rate. In 2012, Dodsland North and Plato showed marked improvement and 2012 results are higher than in previous years.

There is a marked improvement in productivity in 2012 and it seems to be coming close to productivity experienced in 2008, when industry utilized longer lateral wells.

A more detailed sub-area analysis is provided in the Appendix.


36

Exhibit 25. Sub-area Productivity Cal-day Production Over Time

Horizontal Viking Normalized Cal-day Production (Bbl/d) - 2008 to 2012

0

10

20

30

40

50

60

70

1 7 13 19 25 31 37 43 49Months On-stream

Prod

uctio

n (B

bl/d

)

Avon Hills (229) Wells Dodsland North (91) Wells Dodsland South (128) WellsLucky Hills-Whiteside (165) Wells Plato (90) Wells Dodsland East (63) WellsFlaxcombe (110) Wells Forgan (69) Wells Kerrobert (59) WellsKindersley (33) Wells Prairiedale (30) Wells Plenty (47) Wells

Horizontal Viking Normalized Cal-day Production (Bbl/d) - 2012

0

10

20

30

40

50

60

70

1 7 13 19 25 31 37 43 49Months On-stream

Prod

uctio

n (B

bl/d

)

Avon Hills (44) Wells Dodsland North (8) Wells Dodsland South (35) WellsLucky Hills-Whiteside (60) Wells Plato (32) Wells Dodsland East (7) WellsFlaxcombe (33) Wells Forgan (15) Wells Kerrobert (16) WellsKindersley (8) Wells Prairiedale (16) Wells Plenty (2) Wells

Avon Hills, Dodsland South and Lucky Hills-Whiteside have consistently shown strong results.

In 2012, Dodsland North and Plato (as did Dodsland East but production came off sharply) showed marked improvement. Peak rates in 2012 are higher than in previous years in almost every sub-area.



37

Exhibit 26. Sub-area Productivity Prd-day Production Relative To Cumulative Production

Horizontal Viking Normalized Prd-day Rate vs. Cumulative Production (Bbl) - 2008 to 2012

1

10

100

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000Cumulative Production (Bbl)

Prod

uctio

n (B

bl/d

)

Avon Hills (229) Wells Dodsland North (91) Wells Dodsland South (128) WellsLucky Hills-Whiteside (165) Wells Plato (90) Wells Dodsland East (63) WellsFlaxcombe (110) Wells Forgan (69) Wells Kerrobert (59) WellsKindersley (33) Wells Prairiedale (30) Wells Plenty (47) WellsTier 4 Tier 5 Tier 6

Horizontal Viking Normalized Prd-day Rate vs. Cumulative Production (Bbl) - 2012

1

10

100

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000Cumulative Production (Bbl)

Prod

uctio

n (B

bl/d

)

Avon Hills (44) Wells Dodsland North (8) Wells Dodsland South (35) WellsLucky Hills-Whiteside (60) Wells Plato (32) Wells Dodsland East (7) WellsFlaxcombe (33) Wells Forgan (15) Wells Kerrobert (16) WellsKindersley (8) Wells Prairiedale (16) Wells Plenty (2) WellsTier 4 Tier 5 Tier 6

Avon Hills, Lucky Hills-Whiteside, Dodsland South, Flaxcombe and Forgan have historically shown above-average cumulative production relative to producing rate.

In 2012, Dodsland North and Plato showed marked improvement and 2012 results are higher than in previous years.



38

GORs By Sub-area The following table shows the gas-oil ratios (GORs) by sub-area. Lucky-Hills Whiteside has the highest GOR, which is likely the drive mechanism for the higher productivity.

Exhibit 27. GORs By Sub-area

1.65 Mcf/Bbl

1.23 Mcf/Bbl

0.98 Mcf/Bbl

0.83 Mcf/Bbl

0.28 Mcf/Bbl0.18 Mcf/Bbl

1.74 Mcf/Bbl

0.09 Mcf/Bbl

0.65 Mcf/Bbl

0.36 Mcf/Bbl

1.34 Mcf/Bbl

1.74 Mcf/Bbl

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

1.60

1.80

2.00

LuckyHills-

W hiteside

Kindersley Flaxcombe DodslandEast

DodslandNorth

Avon Hills Prairiedale Kerrobert Plato DodslandSouth

Plenty Forgan

GO

R (M

cf/B

bl)



39

Viking Economic Evaluation The following charts showcase the economic analysis for the Viking. In each scenario, we have used the industry consultants nine tiers for productivity referenced earlier. In addition, we have assumed ~1,000 Scf/Bbl in each scenario at a flat price of $3.25/Mcf. Each economic scenario assumes an all-in well cost of $0.9 million, and a mid-cycle gross-up that attributes 10% of incremental capital or ~$0.09 million for infrastructure.

On a pre-tax basis, the Tier 5 scenario (which is quite commonly assumed to be the average well in the Dodsland Viking) requires ~$60/Bbl for a cost of capital return. At $60/Bbl, the Tier 5 well takes approximately five years to payout. At $80/Bbl, the well pays out (mid-cycle basis) in just under three years and has an IRR of 34%.

As noted by the sub-area vintage productivity in the Appendix, average results in 2012 from Avon Hills, Dodsland North, Dodsland South, Forgan, Lucky Hills-Whiteside, and Plato are tracking above the Tier 6 curve honorable mention to Flaxcombe, where results are tracking between Tier 5 and Tier 6.

Exhibit 28. Viking Economics

IRR at Various Oil Prices

-100%

-50%

0%

50%

100%

150%

200%

250%

$60 $70 $80 $90 $100 $110Ed Light (C$/Bbl)

IRR

(%)

Tier 1 - 15 MBbl Tier 2 - 20 MBbl Tier 3 - 25 MBblTier 4 - 35 MBbl Tier 5 - 40 MBbl Tier 6 - 50 MBblTier 7 - 60 MBbl Tier 8 - 65 MBbl Tier 9 - 70 MBbl

B-Tax NPV at Various Oil Prices

($1,000)

($500)

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

$60 $70 $80 $90 $100 $110Ed Light (C$/Bbl)

B-T

ax N

PV (0

00$)


Payout at Various Oil Prices

0

50

100

150

200

250

300

$60 $70 $80 $90 $100 $110Ed Light (C$/Bbl)

Payo

ut (M

onth

s)


Cost Of Capital Breakeven (C$/Bbl)

$0

$20

$40

$60

$80

$100

$120

$140

$160

Tier 9 - 70MBbl

Tier 8 - 65MBbl

Tier 7 - 60MBbl

Tier 6 - 50MBbl

Tier 5 - 40MBbl

Tier 4 - 35MBbl

Tier 3 - 25MBbl

Tier 2 - 20MBbl

Tier 1 - 15MBbl

Tier

Ed L

ight

(C$/

Bbl

)

Tier


We estimate an average Dodsland Viking well requires ~$60/Bbl for a cost of capital return and a top-tier well requires ~$40/Bbl.


40

Crown Vs. Freehold Land For Crown land, the Saskatchewan government offers a royalty incentive program that significantly improves the economics of the Viking opportunity. For non-deep horizontal wells, the category the Viking falls under, all new horizontal oil wells are subject to a maximum royalty of 2.5% until a fixed oil volume of 6,000 m3 or ~37,750 Bbls is produced. This is essentially the entire effective life of a Tier 5 or average horizontal Viking oil well in Saskatchewan. The following table compares the economics for the same horizontal Viking well on Crown and Freehold lands (we have assumed a 17.5% royalty rate for the Freehold lands) at $90/Bbl. Once again, in addition to the industry consultants nine tiers, we have assumed ~1,000 Scf/Bbl in each scenario at a flat price of $3.25/Mcf. Clearly Crown lands offer superior economics with all other things being considered equal.

Exhibit 29. Freehold Vs. Crown Economics

Depth (meters)All-in Cost ($ million)IP30 (Boe/d)Associated gas (Mcf/Bbl)First Year DeclineEUR (MBoe)

Freehold (17.5%) Crown



NPVs (9% B-tax) ($663) ($525) $516 $889 $1,935 $2,575NPVs (9% A-tax) ($663) ($525) $339 $626 $1,434 $1,928IRR (B-Tax) (%) na -12% 30% 45% 107% 150%IRR (A-Tax) (%) na -12% 24% 37% 94% 137%P/I Ratio (B-Tax) -0.74x -0.58x 0.57x 0.99x 2.15x 2.86xP/I Ratio (A-Tax) -0.74x -0.58x 0.38x 0.70x 1.59x 2.14xPayout (Months) 421 421 36 26 10 8

$1.0

1 MMcf/Bbl61%

46.7 MBoe

1 MMcf/Bbl63%

81.7 MBoe

1 MMcf/Bbl51%

17.5 MBoe

Tier 5 Curve1,400$1.0

Tier 1 Curve1,400$1.0

9.4 Boe/d 41.0 Boe/d 80.9 Boe/d

Tier 9 Curve1,400

Note: Assumes $90/Bbl and $3.25/Mcf. Source: Company reports and CIBC World Markets Inc.

Freehold lands typically have a royalty rate of ~17.5% over the life of the well compared to Crown lands at ~2.5% for the first 37,750 Bbls.


41

Where The Viking Fits A colleague recently put out a research note that ranked most of the oil resource opportunities in Western Canada. We have added the nine Viking tiers into the P/I analysis to determine where the opportunities shake out. At $90/Bbl, wells ranked under or at Tier 5 have a below-average P/I ratio relative to the group. However, the higher tiers score very well. A key highlight for us is that we have seen a trend of improving productivity over the last few years. To date in 2012, ~50% of the Dodsland Viking wells have been above Tier 5.

Exhibit 30. Pre-tax P/I Economic Comparison

-0.75x

-0.50x-0.25x0.00x0.25x

0.50x0.75x1.00x

1.25x1.50x

1.75x2.00x

2.25x2.50x

2.75x3.00x

Vikin

g-Do

dslan

d Tier

1Vi

king-

Dods

land T

ier 2

Pekis

ko-C

entra

l Albe

rtaVi

king-

Centr

al Al

berta

Card

ium-S

trach

anCa

rdium

-Wap

itiCa

rdium

-Pine

Cre

ek/C

arro

t Cre

ekBe

aver

hill L

ake-S

wan

Hills

Vikin

g-Do

dslan

d Ti

er 3

Slav

e Po

int-R

ed E

arth

Beav

erhil

l Lak

e-De

er M

t./Et

hel

Beav

erhil

l Lak

e-Sw

an H

ills S

outh

Beav

erhill

Lake

-Swa

n Hills

Nor

thSh

auna

von-N

orth

Doig-

Kaku

tCa

rdium

-Wille

sden

Gree

nM

ontne

y-Was

kahig

anPe

kisko

-Haro

Beav

erhil

l Lak

e-Ju

dy C

reek

Pekis

ko-Ju

dy C

reek

Mon

tney

-Ante

Cre

ekSl

ave

Point

-Otte

r/Evi

Long

Cardi

um-L

oche

ndVik

ing-D

odsla

nd T

ier 4

Card

ium-B

uck L

ake/W

ilson

Cre

ekCa

rdium

-Gar

ringt

onSl

ave P

oint-O

tter/E

vi Sh

ort

Viking

-Dod

sland

Tier

5Ca

rdium

-Wes

t Pem

bina

Slav

e Po

int-S

awn

Lake

Beav

erhil

l Lak

e-Vir

ginia

Hills

Doig-

Valha

llaSla

ve P

oint-G

ift/Ni

pisi

Bakk

en-V

iewfie

ld Pe

riphe

ral

Shau

navo

n-Cen

tral

Mon

tney-V

alhall

a/Ryc

roft

Blues

ky H

eavy

-Wes

t Sea

lCa

rdium

-Pem

bina

Core

Shau

navo

n-Sou

thCa

rdium

-Eas

t Pem

bina

Viking

-Dod

sland

Tier

6Ba

kken

-Bird

tail/M

anso

nAm

aran

th-W

aska

daBa

kken

-Tay

lorto

nBlu

esky

Hea

vy-2

Late

rals

Bakk

en-F

rys/S

inclai

rAm

aran

th-Ea

st W

aska

daM

ontn

ey-N

orthe

rnPe

kisko

-Prin

cess

Bakk

en-V

iewfie

ld Co

reVi

king-

Dods

land T

ier 7

Bakk

en-F

lat L

ake

Vikin

g-Re

dwat

erAm

aran

th-Pi

erso

nVi

king-D

odsla

nd T

ier 8

Blue

sky H

eavy

-Eas

t Sea

lVi

king-

Dods

land

Tier 9

Blues

ky H

eavy

-Moo

ney

Mon

tney

-Kay

bob

Pre-

Tax P

rofit

to In

vest

ment

Rat

io

> than 3.0x


At $90/Bbl, wells ranked under or at Tier 5 have a below-average P/I ratio relative to the group. However, the higher tiers score very well.


42

Per Section Rather Than Per Well Economics We believe that it is important to take the discussion on economics one step further. Given the lower relative well productivity and higher potential well density, we believe that it is more relevant to examine the EUR and NPV per section of an opportunity in the Viking than simply on a single-well basis.

Using the third-party evaluators type wells for the Viking (30 MBbls at a density of 16 wells per section), we examine the development of a section of land. We have assumed that all 16 Viking wells are drilled in the first quarter of the year. The following table shows the development parameters for the Viking.

Exhibit 31. Per Section Development

VikingWell Density/Section 16EUR/Well (MBbl) 30EUR/Section (MBbl) 480Associated Gas (Scf/Bbl) 1,000Total Well Cost ($million) $0.9Mid-cycle gross up ($million) $0.1Total Well Cost/Section ($million) $15.8Opex + Transportation ($Bbl) $13.37Price Realization To Edm Light (C$/Bbl) ($2.50)Ed Light (C$/Bbl) $60.00IRR (%) 13%Pre-Tax NPV (9%, $million) $1.7Ed Light (C$/Bbl) $70.00IRR (%) 24%Pre-Tax NPV (9%, $million) $5.8Ed Light (C$/Bbl) $80.00IRR (%) 34%Pre-Tax NPV (9%, $million) $10.1Ed Light (C$/Bbl) $90.00IRR (%) 45%Pre-Tax NPV (9%, $million) $14.3Ed Light (C$/Bbl) $100.00IRR (%) 56%Pre-Tax NPV (9%, $million) $18.5


Given the lower productivity, but higher density development scenarios, we believe it is more appropriate to examine economics on a per section basis, rather than per well.


43

Repeatability And Scalability Supports Growth And A Dividend Model As mentioned earlier, we believe that since the Viking has lower productivity, the financial community has dismissed the play to some degree as not being as desirable as other opportunities. We do not agree with this perception. We believe that the Viking economics should be examined on a per section or township basis to determine the value of the opportunity as the lower productivity is offset by the potential for higher well density.

We have provided two scenarios to support our view. In each scenario, we have assumed the development of one township of Crown Viking land (36 sections or ~23,000 acres). We have assumed a density of 16 wells per section (576 wells on a township) and assumed a Tier 5 curve for both scenarios. A Tier 5 curve assumes 30 MBbls recoverable at a density to 16 wells per section.

The point of the analysis is to show that a relatively small parcel of prospective Viking land can offer robust economic value and support meaningful growth or a dividend model.

Growth Scenario Scenario One is a growth scenario. We assume that an operator spends ~$11 million to acquire a township of land and finances the first year drilling program (~50 wells or ~$48 million) with external capital. Beyond the first year, the remainder of the drilling program is funded through cash flow. Our base-case scenario assumes $80/Bbl Ed Light pricing to determine the pace of development beyond the first year. We have assumed an all-in well cost of ~$900,000 and have assumed the project volumes do not go to a centralized processing facility controlled by the operator (which would improve the economics) and are trucked to third-party processing.

To provide a more conservative scenario, we have only examined oil production and have excluded any associated gas production (including the associated gas, the incremental IRRs range from 1% to 5% for the various scenarios). The following table shows the growth development scenario for one township of Viking land. The takeaways are as follows;

1. Development of the project can be internally financed after the first year when the project is jump started.

2. The pace of development (assuming $80/Bbl) exhausts the inventory in eight years.

3. A township of land can support growth to a peak rate of almost 7,000 Bbls/d after eight years.

4. At the peak production rates in our growth scenario, the decline rate for the field is ~33%.

5. The project needs ~$60/Bbl oil to generate a ~15% return.

6. At ~$80/Bbl oil, the project generates a pre-tax NPV (9%) of $214 million.

A relatively small parcel of prospective Viking land can offer robust economic value and support meaningful growth or a dividend model.

A township of Viking lands can support production growth to 7,000 Bbls/d.


44

Exhibit 32. Viking Growth Scenario

Annual Average Production And Free Cash Flow

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

6,500

Year

1

Year

2

Year

3

Year

4

Year

5

Year

6

Year

7

Year

8

Year

9

Year

10

Year

11

Year

12

Year

13

Year

14

Year

15

Year

16

Year

17

Year

18

Year

19

Year

20

Year

21

Year

22

Year

23

Year

24

Year

25

Bbl

/d

Annual Free Cash Flow

($40)

($20)

$0

$20

$40

$60

$80

$100

$120

Year

1

Year

2

Year

3

Year

4

Year

5

Year

6

Year

7

Year

8

Year

9

Year

10

Year

11

Year

12

Year

13

Year

14

Year

15

Year

16

Year

17

Year

18

Year

19

Year

20

Year

21

Year

22

Year

23

Year

24

Year

25

$ M

illio

n


45

Wells Drilled (Hz)Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total

Year 1 5 5 5 0 0 5 5 5 5 5 5 5 50Year 2 3 3 3 0 0 3 3 3 3 3 3 3 30Year 3 4 4 4 0 0 4 4 4 4 4 4 4 40Year 4 5 5 5 0 0 5 5 5 5 5 5 5 50Year 5 7 7 7 0 0 7 7 7 7 7 7 7 70Year 6 9 9 9 0 0 9 9 9 9 9 9 9 90Year 7 12 12 12 0 0 12 12 12 12 12 12 12 120Year 8 13 13 13 0 0 13 13 13 12 12 12 12 126Year 9 0 0 0 0 0 0 0 0 0 0 0 0 0Year 10 0 0 0 0 0 0 0 0 0 0 0 0 0Year 11 0 0 0 0 0 0 0 0 0 0 0 0 0Year 12 0 0 0 0 0 0 0 0 0 0 0 0 0Year 13 0 0 0 0 0 0 0 0 0 0 0 0 0Year 14 0 0 0 0 0 0 0 0 0 0 0 0 0Year 15 0 0 0 0 0 0 0 0 0 0 0 0 0Year 16 0 0 0 0 0 0 0 0 0 0 0 0 0Year 17 0 0 0 0 0 0 0 0 0 0 0 0 0Year 18 0 0 0 0 0 0 0 0 0 0 0 0 0Year 19 0 0 0 0 0 0 0 0 0 0 0 0 0Year 20 0 0 0 0 0 0 0 0 0 0 0 0 0Year 21 0 0 0 0 0 0 0 0 0 0 0 0 0Year 22 0 0 0 0 0 0 0 0 0 0 0 0 0Year 23 0 0 0 0 0 0 0 0 0 0 0 0 0Year 24 0 0 0 0 0 0 0 0 0 0 0 0 0Year 25 0 0 0 0 0 0 0 0 0 0 0 0 0Year 26 0 0 0 0 0 0 0 0 0 0 0 0 0Total Wells Drilled 576

Production (Bbl/d) (Average)Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Production

Year 1 0 205 379 531 463 413 580 724 851 967 1,074 1,173 613Year 2 1,266 1,273 1,287 1,307 1,207 1,126 1,183 1,231 1,275 1,315 1,353 1,389 1,268Year 3 1,423 1,496 1,562 1,623 1,515 1,428 1,519 1,595 1,663 1,724 1,780 1,832 1,597Year 4 1,881 1,968 2,047 2,120 1,982 1,872 1,984 2,078 2,161 2,236 2,305 2,369 2,084Year 5 2,429 2,568 2,622 2,743 2,567 2,425 2,593 2,735 2,860 2,973 3,076 3,171 2,730Year 6 3,261 3,428 3,578 3,716 3,475 3,282 3,489 3,664 3,818 3,957 4,085 4,204 3,663Year 7 4,315 4,544 4,749 4,936 4,618 4,362 4,641 4,875 5,082 5,269 5,440 5,599 4,869Year 8 5,749 5,931 6,101 6,259 5,877 5,566 5,838 6,065 6,264 6,403 6,533 6,655 6,103Year 9 6,772 6,392 6,081 5,817 5,586 5,381 5,196 5,029 4,876 4,735 4,603 4,480 5,412Year 10 4,364 4,254 4,147 4,045 3,947 3,852 3,762 3,674 3,590 3,509 3,430 3,354 3,827Year 11 3,281 3,210 3,141 3,075 3,010 2,948 2,888 2,830 2,774 2,719 2,666 2,615 2,930Year 12 2,565 2,516 2,469 2,423 2,379 2,335 2,293 2,253 2,213 2,174 2,137 2,100 2,321Year 13 2,064 2,030 1,996 1,963 1,931 1,899 1,869 1,839 1,810 1,782 1,754 1,727 1,889Year 14 1,700 1,675 1,649 1,625 1,600 1,577 1,554 1,531 1,510 1,488 1,467 1,446 1,569Year 15 1,426 1,407 1,387 1,368 1,350 1,331 1,314 1,296 1,279 1,263 1,246 1,230 1,325Year 16 1,214 1,199 1,184 1,169 1,154 1,140 1,126 1,111 1,092 1,074 1,058 1,045 1,131Year 17 1,031 1,014 997 981 964 948 932 917 903 890 878 868 944Yea

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