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Institutional Equity Research

Industry Update

August 15, 2012 Oil & Gas - Large Cap

Too Much Of A Good Thing... A Deep Dive Into The North American Energy Renaissance

All figures in Canadian dollars, unless otherwise stated. 12-117784 © 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

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

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

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

Nick Lupick1 (403) 221-5049 [email protected]

Jeremy Kaliel 1 (403) 260-8657 [email protected]

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

Too Much Of A Good Thing... - August 15, 2012

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Table Of Contents Executive Summary..................................................................................3 The Future Of North American Energy….Too Much Of A Good Thing Is Bad...... 12

Bottoms Up…Introducing The New CIBC Bottoms-Up Shale Model ............ 12 The U.S. Energy Renaissance................................................................... 14

Background & Recent Trends................................................................. 14 Astonishing Shale Growth… ................................................................ 14 Non-resource Play Production In Steep Decline ..................................... 18 Resource Play Trends ........................................................................ 20

Key U.S. Growth Plays ......................................................................... 23 The Eagle Soars….. ........................................................................... 25 Hayneville A Has Been? ..................................................................... 31 Marcellus – The Beast In The East: Activity Moderating Somewhat But Still Going Hard ...................................................................................... 36 Bakken Booming… ............................................................................ 41 Other Plays...................................................................................... 45 Lots Of Activity On Emerging Resource Plays ........................................ 47

Allocating Capital – Comparative Economics ............................................ 50 Where To From Here – U.S. Resource Play Growth Forecasts ..................... 52

Scenario 1 – Growth & Current Rig Counts ........................................... 53 Impact Of Emerging Plays, Long-term Fleet Expansion & Efficiency Gains.. 55 Scenario 3 – Introducing Volatility & Pricing Impact With Monte Carlo Simulation ....................................................................................... 58

Key Takeaways ................................................................................... 62 GOM – Shelf Declines But Deep Production Should Rebound In 2014-16 Time Frame................................................................................................ 65 Canadian Resource Play Growth............................................................. 67

Resource Play Development – Canadian Style ....................................... 67 Canadian Tight Oil Through Inflection Point .......................................... 68 Canadian Natural Gas A Different Picture.............................................. 70 Canada Vs. The U.S. ......................................................................... 72 Allocating Capital – Where Does The Canadian Resource Play Dollar Go?... 75 New Plays Could Lead To Eagle Ford-esque NGL Boom ........................... 76 Six Key Plays In Canada To Watch ...................................................... 76

Where To From Here – Canadian Resource Play Growth ............................ 83 Key Takeaways For Canadian Resource Plays........................................ 83

Oil Sands – Vast Resource But Can It Compete?....................................... 86 Growth Plans Vs. Pipeline Constraints .................................................. 86 Labor Pains...................................................................................... 88 Prices/Costs & Pipelines Will Rationalize Development…It Is Only A Matter Of How Far .......................................................................................... 89 Oil Sands – Higher Cost Projects The First To Fall In A Competitive North American Market .............................................................................. 91 Oil Sands Are Down But Not Out – Technology Optionality Is Still Large.... 92 Conclusions/Takeaways On Oil Sands Growth ....................................... 92

Impact Of North American Tight Oil Renaissance On Global Supply Demand Balances ............................................................................................ 94

High North American Growth Likely To Loosen Medium-term Oil Balances . 94 Impact Of Crude Renaissance On North American Regional Pricing.............. 97

Crude Glut Means Canada + PADD 2 Crudes Will See Excess Volatility & Periodic Discounting Through 2014...................................................... 98 Discounting Of North American Crudes Likely To Remain Long Term – But Discounting Shifts To LLS Vs. Brent ................................................... 100 Canada Will Need Big Pipe Build To Escape Long-term Discounting......... 105 Oil Supply/Demand Balances Key Takeaways...................................... 114

North American Natural Gas Supply/Demand Balances............................ 116 Demand Drivers ............................................................................. 116 Supply/Demand Balances – Tighter Markets Ahead.............................. 122 Takeaways From Natural Gas Supply Demand Balances........................ 125

Investment Conclusions...................................................................... 126


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Executive Summary In an effort to better forecast North American natural gas, natural gas liquids (NGL) and oil supply, we are introducing the CIBC Bottoms-Up North American Resource Play Model. Our analysis, as the name implies, is a bottoms-up approach looking at each of the major U.S. and Canadian resource plays (resource plays includes shales/tight resource plays and oil sands). We believe this is one of the most detailed reports of this kind, analyzing trends from 57,000 wells across 28 different North American resource plays. This model is a powerful tool for forecasting North American oil and natural gas deliverability.

U.S. Resource Plays – Key Takeaways U.S. Onshore Oil Production Can Grow 500,000-700,000 Bbls/d Per Year Through 2016: We have conducted a number of scenarios ranging from status quo drilling (current rig counts held flat) to a very detailed Monte Carlo simulation. While the results vary considerably by scenario, the general takeaway is that U.S. onshore oil growth is capable of big growth for a long period of time. Our lowest growth scenario (current rig counts with a 20% reduction in IPs) would yield oil resource play growth of 460,000 Bbls/d per year, which, after deducting declines on non-resource play production, would yield onshore U.S. growth of 350,000 Bbls/d per year through 2016. Our highest growth scenario, which incorporates moderate rig fleet expansion and cycle time improvements, would yield resource play growth of 830,000 Bbls/d per year through 2016. After deducting non-resource play declines, this would leave onshore production growth in the 700,000 Bbls/d per year range through 2016. Our base case view is U.S. resource play production growing in the 650,000 Bbls/d per year range yielding annual onshore oil growth of approximately 530,000 Bbls/d per year through 2016. We note that these outcomes reflect liquids only from the well head; we expect NGL production from gas plants to also grow ~200,000 Bbls/d per year through 2016.

Gas Is Not Sustainable At Current Rig Counts: Our current rig count scenario clearly depicts how unsustainable the current gas rig count is. At current rig counts, we see production from gas resource plays growing only 1.7 Bcf/d per year through 2016, a stark contrast to the 4-6 Bcf/d per year growth seen from 2009-2012. Layering in anticipated declines of ~0.8 Bcf/d per year from non-resource play production along with anticipated extraction losses for increasing NGL output, leaves U.S. dry gas production flat with current levels. To believe this outcome is sustainable assumes no growth in demand – which we do not believe is realistic.

At What Price Do Rigs Move Back To Dry Gas?: On average, we expect natural gas demand growth to average 0.5-1.5 Bcf/d per year through 2016 and 1.5-2.5 Bcf/d per year post 2016 as we incorporate LNG exports. For supply to meet projected demand growth through 2016, we need to see gas prices signals strong enough to attract another ~100 rigs back towards dry natural gas drilling or see another ~150 rigs allocated towards liquids-rich drilling. For either of these scenarios to unfold, substantially higher natural gas prices are required to pull rigs away from tight oil drilling. This conclusion arises from two considerations; 1) most dry natural gas plays do not compete with the big tight oil plays (with oil in a US$85/Bbl range) until gas is in the ~US$5/Mcf range; and 2) most gas-weighted producers need prices in the US$4-US$5/Mcf range to have sufficient cash flow to drill sufficient gas wells.

We believe this is one of the most detailed reports of this kind, analyzing trends from 57,000 wells across 28 different North American resource plays.


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Industry Can’t Support Gas AND Oil Boom At Same Time: What has become abundantly clear through this report is that the U.S. industry has been running at very close to full utilization over the past 12 months. Within the full utilization, there has been a clear shift from gas to oil. However, what this also implies is that there is no way the industry can either fund or logistically support a boom in natural gas AND oil drilling – when services are running at near full utilization, rigs will be allocated on the basis of returns and strategic value (primarily land retention).

Liquids Lands…25,000-40,000 Wells Needed To Hold New Oil Lands Leaves Little Flexibility To Move Rigs: Using an assumption of 1.0-1.5 wells to hold a section of land, implies the need to drill over 26,000-39,000 wells on new liquids plays to meet land commitments (generally within a three- to five-year time frame) – an aggressive requirement. Overall, we believe the U.S. is in the early innings of a new land retention driven boom, this time focused on new liquids plays. What this means for gas prices is that, even if gas prices rise, producers are more likely to use the incremental cash flows to accelerate drilling on liquids plays (to meet commitments) rather than accelerate on dry gas plays where they already hold the majority of their lands.

US E&Ps Addicted To Spending; More JVs Necessary To Meet Obligations: The Top 40 U.S. E&Ps that we track have outspent cash flow by $55 billion since the start of 2008. The gap has been funded by equity, debt and JVs. Since the start of 2008, we have seen $32 billion of JV announcements ($14 billion of upfront carry delivered). With current consensus capex for the U.S. Top 40 exceeding cash flow estimates by $26 billion (for 2012 and 2013), it is clear we will need to see substantial JV announcements to keep the party going. Recent JV announcements indicate the market is still open to such transactions but this could be at risk if macro conditions deteriorate.

Warning To Regulators – Changes In Frac Legislation Would Send U.S. Energy Renaissance Back To The Dark Ages: The biggest risk (albeit still quite remote) that we see to the development of unconventional resources is harsh changes to fraccing rules. We calculate declines on U.S. resource plays to be running in the 36% range, implying ~10 Bcfe/d of production additions per year just to offset declines. With high drilling activity, there will no problem keeping ahead of this curve, however, if there were any major changes to fraccing legislation (which would drop activity levels meaningfully), the U.S. energy renaissance would quickly return to the dark ages.

Canadian Resource Plays – Key Takeaways Canadian Tight Oil Through Inflection Point & Capable Of Growing ~100,000 Bbls/d Per Year: Based on our bottoms-up analysis of all major Canadian tight oil plays, we expect Canadian conventional oil production to grow by an average of ~10% per year from 2011 to 2016 (~100,000 Bbls/d per year, compared to CAPP’s estimate of about 40,000 Bbls/d per year) and 8% per year from 2016 to 2020. In this scenario, total Canadian conventional oil production would be 1,650,000 Bbls/d by 2020.

Natural Gas Growth Largely Driven By LNG: We expect Canadian drilling activity to continue to focus heavily on liquids-rich and tight oil, at the expense of natural gas. The one big exception will be for companies drilling gas to supply planned LNG facilities. Overall on the natural gas side, we see Canadian gas production growing ~2% per year from 2011 to 2016 (~300 MMcf/d per year) and 4% per year from 2016 to 2020 and natural gas would be 19 Bcf/d by 2020.


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Key Canadian liquids plays we believe will drive growth include the Cardium, Tight Carbonates, and the Duvernay, while key Canadian natural gas plays to drive growth include the Montney, Deep Basin, and the Horn River. Canadian resource play economics are competitive with U.S. plays, as is the depth of Canadian development opportunities. Canadian dry gas plays are pretty far down the value chain…but LNG will still yield meaningful development.

We expect that labor and services capacity in Canada will continue to be periodic bottlenecks, with the most notable required infrastructure builds including LNG export capacity on the West Coast as well as the Northern Gateway oil pipeline. We believe differences in land tenure are one of the reasons why development has been slower in Canada compared to the U.S. At least on the oil side of the equation, much of the rights to prospective tight oil acreage was already “held by production” when horizontal multi-stage fraccing rejuvenated the sector (i.e., operators producing from either the same zone or deeper zones were already holding the rights of emerging resource plays). With rights held by production in many cases (and in other cases held on five-year tenure with the government) operators in Canada have been able to afford a more measured pace of development compared to the U.S.

As has already begun, we expect foreign capital will continue to flow into Canada to help fill the funding deficit faced in the development of and attractive set of resource play opportunities. This is a necessary factor for accelerated development in Canada, as for many Canadian operators capital is less accessible than it is for their American peers.

Oil Sands – Key Takeaways Overall, the oil sands has almost unlimited resource potential but the real question once again boils down to how much can (or should) get built in an environment that has substantial competition, particularly for labor and pipeline access.

A Wide Range Of Growth Outcomes: The sum of company forecasts implies oil sands growth of 380,000 Bbls/d per year through 2020 whereas on the other end of the spectrum is CAPP with forecasts of 180,000 Bbls/d per year growth through 2020. We believe that company forecasts are wildly optimistic as, in such a scenario, even if every pipeline currently being planned was built (Keystone XL, Alberta Clipper expansion, TMX Expansion, Gateway and TransCanada’s gas pipeline conversion), there would still not be enough capacity to meet company targets! On the other hand, we believe CAPP’s forecasts are conservative. Our base case view is for ~270,000 Bbls/d per year of oil sands growth through 2020, but note that this is entirely dependant on pipelines being built.

Company Growth Plans Will Need To Be Rationalized: No company voluntarily gives up the quest for growth. This leaves the onus on market forces to rationalize that growth. The main market drivers will either be hyper inflation, regulatory delays and/or lower pricing either due to lower global benchmark pricing or localized discounting due to insufficient pipeline capacity. The most likely outcome is some combination of all these factors but our biggest concern at the moment is pipeline access.

Pipelines Will Likely Be The Biggest Factor To Dictate The Pace Of Oil Sands Growth. We continue to believe Keystone XL (the full line) will get built but one can’t deny there is still a level of risk to that. The Enbridge (ENB-SO) Alberta Clipper expansion and Line 9 reversals are also clear go-aheads in our view. Access to the West Coast, either through the proposed TMX expansion or Northern Gateway, is looking riskier by the day as provincial governments squabble over revenue sharing and broad based political support in B.C. appears


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very low. If neither of these lines go ahead, oil sands growth targets for 2020 (company forecasts) would have to be rationalized approximately 1.7 MMBbls/d from current levels.

Lower Cost SAGD Projects Competitive With Tight Oil: Oil sands resource quality is by no means homogenous. We calculate supply costs for higher-quality (lower-cost) SAGD projects to be in the $50-$60/Bbl range and very competitive with many North American tight oil opportunities. The only disadvantage is the bigger upfront investment (a typical SAGD project is a $1 billion decision vs. being able to manage capital well by well), which means operators need to be that much more confident in the macro environment. We continue to believe that we will see aggressive development of low-cost SAGD resources.

Higher Cost SAGD & Mining Projects Likely First To Be Rationalized: In a market that is oversaturated with oil, there will no doubt be rationalization and the first projects to get squeezed will be those with higher supply costs and a riskier capital profile. Mining projects and lower-quality SAGD projects have supply costs in the $70-$90/Bbl range vs. most tight oil plays in the $50-$70/Bbl range, leaving these project types as the first to be rationalized in a competitive market.

Technology Impact Could Still Make Oil Sands More Competitive: There is unprecedented R&D going on in the oil sands, aimed at improving the economics and environmental footprint. Technologies range from evolutionary to revolutionary and any success could have a meaningful impact on supply costs – similar to how frac technology changed the game for tight oil. Oil sands continue to offer a significant “free option” on technology.

Oil Sands Transaction Parameters Will Reflect Riskier Outlook: Back in the 2005-2008 time frame, typical deals for long-dated oil sands resource were about US$1/Bbl. Despite higher oil prices, transaction parameters have actually been declining as risks (inflation/pipe) weigh on the outlook for resource and there is more competition for oil capital (tight oil vs. oil sands). Overall, we believe there is still room for oil sands M&A but likely continuing the recent trend of sub US$1/Bbl parameters.

Oil Supply/Demand Balances – Key Takeaways We See North American Oil Growth In the 800,000-900,000 Bbls/d Per Year Range Through 2016: Overall we see approximately 530,000 Bbls/d per year growth coming from U.S. onshore (resource play driven), ~45,000 Bbls/d per year from the U.S. GOM, ~100,000 Bbls/d per year from Canadian conventional (tight oil driven) and oil sands growth of ~230,000 Bbls/d per year. Any way you cut it, that is a lot of oil.

North Am Growth Takes Some Pressure Off Global Balances: Consensus forecasts are for North Am oil growth of ~340,000 Bbls/d per year through 2015 vs. our forecasts of closer to 800,000-900,000 Bbls/d per year. Incorporating our estimates into consensus supply demand balances would imply a relatively flat “call on OPEC” through 2015 (typically corresponds to flat prices). Additionally, spare capacity would grow meaningfully, which could take some of the risk premium out of oil prices.

Oil Renaissance Will Continue To Have Big Impact On Regional Price Discounts: The biggest impact of the North American oil renaissance is the impact on regional price discounts and flows. We are already seeing this in PADD 2 and Canada where crudes have been extra volatile and often selling at large discounts vs. benchmarks. This trend will continue long term but the pinch-points will change over time.


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Canada & PADD 2 Discounts To Remain Through 2014: We continue to believe Canadian and PADD 2 crudes will remain very susceptible to discounting through the 2014/15 time frame (when both the full Keystone XL and Flanagan/Seaway is built). PADD 2, and pipe within PADD 2, are at capacity meaning any pipeline curtailment or refinery outage will lead to meaningful discounts. Once the aforementioned pipes are built, we should see Canadian crudes settle into a transportation discount vs. WTI and Louisiana Light Sweet (LLS).

PADD 2 Problems Will Soon Turn To PADD 3 Problems: PADD 3 is already nearly awash in light sweet crude (Eagle Ford, etc.). When Seaway and the south portion of Keystone XL come on-stream, PADD 2 will be sending over 1 MMBbls/d of crude into this market (a good portion of that being light) – fully saturating the market. As it is prohibited by law to export crude oil from the U.S., this means that PADD 3 will become a trapped market for light oil and will soon lead to discounting of LLS to Brent.

We Estimate WTI-Brent In US$10/Bbl Range Long Term: We recently changed our oil price forecasts to reflect a US$10/Bbl discount of WTI vs. Brent from 2014 onward, which consists of a US$5/Bbl discount for LLS-Brent plus ~US$5/Bbl transport differential back to Cushing.

Downstream Remains Key: Our view that WTI-Brent differentials will remain long term in the $10/Bbl range also implies that inland North American refiners, and even Gulf Coast refiners, will see sustainably high crack spreads. We believe most investors are still treating current crack spreads (in the $30/Bbl range) as supernormal and will revert back to the $10/Bbl range in 2014+. If we are correct in our view on differentials, investors will gradually begin to place greater value on downstream assets to recognize the higher sustainable cash flows and strategic value of these assets.

No Crude Is Untouched By This Theme: Generally speaking, there will be strong desire for Canadian heavy crudes by PADD 3 refiners, but this by no means is meant to imply that WCS has a “reserved” spot in the PADD 3 refinery system. Complex heavy refiners can (and will) take light oil over heavy for the right price – leading to competition for this coveted refinery space. Directionally we believe WCS pricing is less impacted by this theme, but still impacted nonetheless as it is weighed down to a certain degree by pricing on the light complex.

Canadian Crudes Should Be Transportation Discounts - But Only If Pipe Is Built: If adequate pipeline capacity is built, Canadian crudes should trade at transportation costs vs. U.S. equivalent crudes (SCO vs. WTI and WCS vs. Maya with slight quality adjustment). If pipeline capacity is not built, then Canadian prices will move to discounts large enough to eliminate much of the anticipated demand growth – a disastrous scenario for Canadian producers.

What’s The TAN Man? How Western Canada Select (WCS) or Access Western Blend (AWB)/Christina Lake Blend (CLB) gets priced vs. Maya is still a bit of a question mark. WCS and AWB are very similar in terms of API and sulphur content but have much higher TAN, particularly AWB. Globally, higher TAN can have a big impact on pricing, which may mean WCS and AWB get slightly bigger discounts than many investors presume. Our modeling suggests the quality differentials vs. Maya could be in the $4.75/Bbl range for WCS and up to $8/Bbl for AWB/CLB.

Canadian Pipeline Pinch-point Closer Than Many Think: Pipeline capacity out of Western Canada is the biggest risk to Western Canadian producers in the medium and long term. We believe pipeline capacity could effectively be full in the 2014 time frame, highlighting that there is no room for error/politicking in bringing on new pipeline capacity.


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Time To Smoke The Peace Pipe: There are currently ~2.9 MMBbls/d of long-haul pipeline proposals on the table (out of Western Canada). That sounds like a lot until one considers that two of the largest (the proposed 525,000 Bbls/d Gateway and 450,000 Bbls/d TMX expansion through B.C.) face ever-increasing political risk and we assign no better than 50/50 odds that these pipes are built before the end of the decade. The proposed TransCanada Mainline conversion (estimated ~600,000 Bbls/d) is compelling but very early stage and could also provoke some political backlash in Quebec. We also note that the 2.9 MMBbls/d proposed capacity gets used up quickly given our view of 100,000 Bbls/d per year growth in Canadian conventional oil and 230,000 Bbls/d per year growth in oil sands (or ~300,000 Bbls/d when blended). Overall, Canada needs pipe and lots of it to avoid the opportunity cost of stranding over a million barrels a day of potential crude oil growth.

Rail Offers Good Insurance Policy: Railing oil today from Canada or PADD 2 offers a meaningful improvement in netbacks due to the premium of LLS to WTI. If our view of differentials is correct (i.e., that WTI-LLS closes to transportation differentials) but that LLS discounts vs. Brent, the economic advantage to railing will dissipate by the 2014 time frame – if pipelines are built. Given the big risk on pipeline builds, we expect producers to maintain rail optionality even if the economic uplift is mitigated. If PADD 3 pricing significantly discounts vs. Brent (i.e., over $5/Bbl), we could see railed volumes focus more towards PADD 1 from the current focus of PADD 3.

Natural Gas Supply/Demand Balances – Key Takeaways LNG Becoming A Reality – We believe LNG is well on its way to reality. There are well over 20 Bcf/d of export projects on the table. Our risked view is that approximately 8 Bcf/d is built by 2020, with approximately 3 Bcf/d of capacity in Western Canada and the remainder in the U.S. (centered in the GOM).

Demand Should Grow By 1 Bcf/d Per Year Through 2016 And 1.5 Bcf/d Per Year From 2016-2020: We expect U.S. natural gas demand to grow on average approximately 1 Bcf/d per year through 2016 driven primarily by higher demand for power consumption due to coal retirements. We expect demand to pick up in the latter half of the decade as LNG exports are added into the mix.

Surplus WC Gas Flat In Best Case And Meaningful Declines In Worst Case: We expect Canadian supply to be down modestly in 2012 and 2013, and settling into a modest growth profile thereafter, with most of the growth wedge allocated to planned LNG facilities. Demand for gas in Western Canada will increase ~ 0.2-0.4 Bcf/d per year through 2016 and 0.2-0.6 Bcf/d per year through 2020 due primarily to higher demand for natural gas out of oil sands projects. We expect LNG exports out of Western Canada to be up to 3.0 Bcf/d by 2020 (2-3 facilities). Overall, gas available for movement to Eastern Canada or the U.S. will likely remain flat in the growth scenario ranging down 6 Bcf/d by 2020 in a low price scenario (limited gas drilling).

Shale Growth Decelerating: We expect shale gas growth to decelerate massively from the high growth rates seen in 2008-2010. At current rig counts, shales would only grow ~1.7 Bcf/d per year through 2016 vs. the ~4 Bcf/d per year growth seen previously. Adding in extraction losses and declines in non-shale production would see U.S. dry gas production grow by only 0.5 Bcf/d per year through 2016. We also note that our modeling suggests that overall dry gas production is flat to modestly down in 2013/14 before beginning to ramp up again post 2014.


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2013-14 Nat Gas Balances Look Quite Tight: We expect Western Canadian gas exports to decline ~0.5 Bcf/d in 2013 and ~0.3 Bcf/d in 2014. Meanwhile, U.S. dry gas production should be relatively flat in 2013/14 (the first time in many years). This lower supply outlook points to a much tighter gas market in 2013/14. However, the one cautionary point is that if prices rise much above $4/Mcf in 2013, we may give back a meaningful portion of the ~4.5 Bcf/d Y/Y demand increase for natural gas for coal substitution. The other wild card is whether or not a rally back to the $4/Mcf range attracts a big increase in dry gas drilling. We believe producers will be relatively slow to return to natural gas drilling due to a combination of land retention drilling commitments on new liquids plays and skepticism over sustainability of any price increase.

Gas Prices Unsustainably Low: The clear takeaway from our modeling (both the linear models and the simulation models) indicates that the current natural gas rig count and prices are unsustainably low. However, finding equilibrium remains a real balancing act. Based on our Monte Carlo simulation, at gas prices below $4/Mcf vs. oil in the $85-$95/Bbl range, we see insufficient gas growth to meet base case demand growth. On the other hand, above $6/Mcf triggers too much growth (unless oil prices are substantially higher as well). Overall, prices in the $4-$4.50/Mcf range seem sustainable in the pre-LNG era (i.e., up to 2015) with prices in the $5/Mcf in the LNG era.

Investment Conclusions Global Investors Likely To Remain Luke Warm On Canada Due To Pricing/Infrastructure Risk: Global investors have generally been moving away from Canadian oil & gas exposure for many reasons. Generally speaking this decision is driven by a combination of macro fears (Greece, Spain, China slowing) along with fears regarding short-term differential risk for Canadian oil producers. With the dismal stock performance YTD in the Canadian large caps, one could argue that much of our macro thesis is already discounted in stock prices – which is generally true. However, the general negative backdrop with increasingly limited growth visibility and rising pipeline/differential risk means that global investors are unlikely to flock back to Canadian oil and gas exposure anytime soon – unless we see the recent flurry of M&A turn into a full blown wave (possible).

Some Big Players May Adjust Strategies: If our macro view pans out, it will (or should) impact investment decisions by producers. The most likely adjustment will be to those planning mega projects such as upgraders or mining oil sands projects. We expect operators to move more cautiously on these projects, with a high chance of outright cancellation. On the one hand, lower growth is a negative. However, we believe investors have compressed valuations on many of these stocks due to concerns regarding low return investment. On balance, we actually believe investors would react favorably to large-cap producers moving to lower growth, but higher returning and higher free cash flow yielding strategies. For example, we can make a case that Suncor (SU-SO) would be worth 40%-50% more if it moved to a slower and more SAGD-oriented strategy and paid out excess free cash.

Negative Backdrop For Long-dated Oil Sands: Much of our macro thesis is very bearish for the value of long-dated bitumen assets. As we highlighted, producer growth forecasts are wildly optimistic and we believe there will be big competition for pipe access and resources to build projects – which leaves the longer-dated more fringe resources at a distinct disadvantage. Additionally, investors will likely remain much more cautious on providing the necessary capital for those growth ambitions, meaning that early-stage oil sands companies will face far more execution risk than better financed players. Value can still be obtained/recognized for long-dated resource, but this depends more on M&A or JV activity.


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Downstream Value Becomes Very Apparent: Our macro view clearly favors companies with downstream assets. In Canada, there are no pure refiners so this by default means that integrated energy companies [Suncor, Cenovus (CVE-SO), Husky (HSE-SP) and Imperial Oil (IMO-SU)] are best positioned. The rationale is that in-land refineries capture much of the value of lower upstream pricing. We have seen the integrateds outperform PADD 2 exposed names YTD indicating that some of this theme is already reflected in share prices. However, we believe investor expectations are still generally that current downstream cash flows are “supernormal” and will revert to low levels again in 2014+. We believe that downstream cash flows will remain robust over the long term – and that is not reflected in share prices. We highlight Suncor and Cenovus as two of the best positioned integrateds.

Good Opportunity Still In Quality Gas Producers: For the first time in many years, the outlook for natural gas prices looks quite attractive. With tightening storage balances in 2013/14 and a rig count that will likely be slow to return to gas drilling, gas prices should move into the US$4/Mcf range in 2013. We note that some gas players like Encana (ECA-SP) are already reflecting ~US$4.50/Mcf natural gas so much of the upside is already built in. However, we still see good upside in some of the smaller-/mid-cap gas names.

Among the dividend-paying corps, our top two ways to play natural gas include Trilogy (TET-SO) and Peyto (PEY-SO) – with Trilogy as the more defensive gas play (due to its 45% liquids weighting) and Peyto as a higher torque gas pick (88% weighted to gas).

In the junior/intermediate space, Celtic (CLT-SO) and Painted Pony (PPY-SO) are our top gas-weighted names. Both companies offer investor meaningful torque to gas prices as they control substantial resource potential from large contiguous land positions. We also highlight NuVista (NVA-SO) as another gas-weighted pick for its undervalued asset base with 500 drilling locations identified in the Wapiti Montney liquids-rich gas play that is a strong M&A candidate. In addition, we believe the company’s shares are trading inexpensively relative to its natural gas peers as measured by Core NAV (P+P reserves value).

Light Oil Players Will See Lower-than-expected Pricing But Low-cost Players Will Still Make Very Strong Returns: Our thesis of lower light oil pricing will take some of the shine off domestic light oil producers. However, we note that producers with low costs and high-quality resources will continue to prosper (although consensus numbers may be overstated if our macro view holds). Light oil companies with high cost structures and high capital obligations such as Canadian Oil Sands (COS-SU) (opex in US$40/Bbl range with sustaining capex in the ~US$30/Bbl range through 2014) will see many challenges in this environment.


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Top Picks Large Caps: Among the large caps, we continue to focus on Brent-focused producers and integrateds as our top picks. In order of preference, we highlight Suncor (inexpensive with high-quality downstream), Cenovus (highest quality oil sands and well positioned with downstream) and Talisman (TLM-SO) (turnaround story, gas assets will get re-rated if prices recover and enough Brent-priced growth projects in Colombia and Asia that will interest investors).

Small- To Mid-cap Oil Sands: From a macro perspective, it is more challenging to get excited about the small- to mid-cap oil sands producers, however, we continue to highlight MEG Energy (MEG-SO) (innovative and one of lowest cost resources bases) and Athabasca Oil (ATH-SO). We remain positive on ATH primarily because we see it reducing oil sands exposure and believe the light oil assets will drive remaining value in short term.

Dividend-paying Corps: Our top picks in this space include our highest netback domestic light oil producers such as PetroBakken (PBN-SO) (whose margins are better protected in a downside scenario in which crude oil sees pressure). We would also highlight Trilogy as a top pick owing to its strong growth profile and its ability to fund its development (and pay its dividend) within cash flow.

Small And Mid Caps: Our top pick is Angle Energy (NGL-SO) as it offers exposure to a high netback Cardium oil play at Harmattan, which has become the largest focus area for the company. We highlight that the corporate liquids have increased from 39% at the end of 2010 to 46% projected for Q4/12. We also expect large year-end reserve growth associated with the active drilling program in Harmattan and area.

International Producers: Our two top picks in the international producer space are Coastal Energy (CEN-SO) and Gran Tierra Energy (GTE-SO). Both companies produce over 90% high netback oil that track to Brent pricing. CEN has a strong balance sheet, good free cash flow generation from its producing properties and significant upside potential with booked P3, 2C and prospective resources. GTE trades at a 20% discount to its 2P NAV but has a surplus of cash on its balance sheet, is expected to generate free cash flow in 2013 and has an active H2/12 planned with potential for significant catalysts.


12

The Future Of North American Energy….Too Much Of A Good Thing Is Bad

Bottoms Up…Introducing The New CIBC Bottoms-Up Shale Model In an effort to better forecast North American natural gas, natural gas liquids (NGL) and oil supply, we are introducing the CIBC Bottoms-Up North American Resource Play Model. Our analysis, as the name implies, is a bottoms-up approach looking at each of the major U.S. and Canadian resource plays (resource plays includes shales/tight resource plays and oil sands).

As the North American shale picture can change rapidly, due to changes in technology and gas-liquids pricing relationships, we intend to update this analysis at least semi-annually to keep a solid pulse on rapidly changing North American oil and natural gas fundamentals.

A Quick Word On Methodology & Data Quality While some competitors provide play-by-play forecasts for resource plays, our approach is differentiated by the level of detail – rather than simply basing our forecasts on anticipated type curve results, our models have been back calibrated through Q1/08 (the start of the shale boom) and carried forward, ensuring we have accurate type curve trends, drilling times, etc. rather than just using unrisked company forecasts. Our model assimilates data from over 57,000 wells on 28 different North American resource plays.

There are many ways to portray type curves. Our approach is centered around taking actual reported calendar day production rates for the ENTIRE play rather than relying on company disclosures from a few select companies. As we compare our results to company disclosures, there are sometimes quite meaningful differences – which we chalk up to several factors:

Instantaneous IPs Vs. 30-day IPs: Many companies are guilty of disclosing instantaneous IPs (24-hour test rates for instance). These are sometimes meaningful, but more often than not quite distorted numbers. Our IPs are based on 30-day calendar averages. The one shortfall of our approach is that if a well is brought on later in a month, the first recorded month of production is low on a calendar day average and the peak month ends up being month 2. This is only meaningful in terms of optics; it does not impact EUR or our longer-term forecasted performance.

Producing Day Vs. Calendar Day: We calculate type curves based on actual calendar day rates (total monthly production divided by calendar days in the month) vs. producing days (only recording production for days the well is on stream). Producing day rates can be meaningful in terms of showing what a well is capable of unconstrained – but it is not how a producer reports volumes or achieves cash flow. Depending on the play, the difference between producing day and calendar day rates can be meaningful.

Our model assimilates data from over 57,000 wells on 28 different North American resource plays.


13

Play Averages Vs. Select Producer Averages: In most U.S. plays, there are a large number of companies participating. Our data reflects the average of all wells drilled, not just a few select producers. In the appendices to this report, we break out factors such as IP by operator and by county so investors can see the variations. In most cases, the top operators (by size) typically do have meaningfully higher IP rates than the play average.

Data Quality Varies: With any primary analysis such as this, you are at the mercy of data quality – and data quality varies considerably by province or state. Overall, Canadian data quality is very high and very timely. Of the bigger plays in the U.S., we find data from North Dakota, Texas, Louisiana to be very high quality (covering Bakken, Eagle Ford, Haynesville, Permian plays, etc.). On the weaker end of the spectrum lies Oklahoma (Anadarko plays, parts of the Mississippi lime).

On the scale of inexcusably bad lies Pennsylvania, where data is released only once every six months for the Marcellus and even then only for a cumulative basis (i.e., no monthly production). Given the importance of the Marcellus, we were forced to take a different tact and rely on overall Marcellus gas production from Bentek, and back into type curves base on rates and wells completed.


14

The U.S. Energy Renaissance

Background & Recent Trends

Astonishing Shale Growth… The North American shale revolution is well documented, but one last review won’t hurt! Exhibit 1 depicts the almost unbelievable growth in gas and oil resource play development over the past three years. 2008 was clearly the dawn of the unconventional age, with key resource plays producing approximately 6.3 Bcfe/d, consisting of 5.5 Bcf/d of marketable gas production and 135,000 Bbls/d of oil production (note: this analysis includes only horizontal production from Anadarko and Permian). Importantly, the only one big play in 2008 was the Barnett shale. By year-end 2011, production from these plays had grown to an astonishing 35 Bcfe/d, consisting of ~28 Bcf/d of marketable gas and 1.2 MMBbls/d of oil production spread across over nine different resource plays. Importantly, there are still new resource opportunities popping up so these incredible growth rates are by no means over.

Exhibits 1-3 provide an overview of the key growth drivers behind gas production and oil production as well as on an MMcfe/d basis. As is quite obvious, the early part of the resource play boom was absolutely dominated by natural gas-weighted development, but weakening prices for natural gas meant a move towards oil and liquids-rich resource plays over the past few years.

Exhibit 1. Key Resource Play Growth Q1/08-Q1/12 (MMcfe/d)

-

10,000

20,000

30,000

40,000

50,000

60,000

Q1/08 Q2/08 Q3/08 Q4/08 Q1/09 Q2/09 Q3/09 Q4/09 Q1/10 Q2/10 Q3/10 Q4/10 Q1/11 Q2/11 Q3/11 Q4/11 Q1/12

Anadarko BasinPermianMississippi LimeUS BakkenEmerging PlaysWoodfordBarnettFayettevilleHaynesvilleMarcellus PAEagleford

Source: HPDI and CIBC World Markets Inc.

Production from the main US resource plays increased from 6.3 Bcfe/d in 2008 to 35 Bcfe/d by year-end 2011 – astonishing growth.


15

Exhibit 2. Key Resource Play Growth – Marketable Gas Production (MMcf/d)

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000


Anadarko BasinPermianMississippi LimeUS BakkenEmerging PlaysWoodfordBarnettFayettevilleHaynesvilleMarcellus PAEagleford

Exhibit 3. Key Resource Play Growth – Oil Production (Bbls/d)

-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000


Anadarko Basin

PermianMississippi Lime

US Bakken

Emerging Plays

Woodford

Barnett

Fayetteville

Haynesville

Marcellus PAEagleford

Source for Exhibits 2 and 3: HPDI and CIBC World Markets Inc.

As depicted above, the shale gas game changes quickly. In Q1/11, the Haynesville dethroned the Barnett as the largest producing shale in North America – astonishing given the Haynesville was really only commercialized in 2008. However, Haynesville growth is stalling out as of late as the industry shifts rigs from this prolific but very dry (i.e., low liquids content) plays to higher returning liquids plays such as the Eagle Ford.

The charts in Exhibits 4 and 5 depict Y/Y growth trends out of the key U.S. shales. As depicted, the Haynesville has been THE dominant growth driver in U.S. shales but the pace of growth is decelerating rapidly with newer plays such at the Eagle Ford, which by no coincidence enjoys a very high liquids content, picking up the slack. The Marcellus has been a consistent growth driver for a sustained period of time. On the oil side, growth has been more diverse, actually lead by the Permian basin, where production was up 737,000 Bbls/d from Q1/08-Q1/12, followed by the Bakken with production up 509,000 Bbls/d from Q1/08 to Q1/12) and the Eagle Ford where oil and condensate production

Gas growth from 2008-2011 was led by the Haynesville & Marcellus. However, Haynesville growth is now giving way to the Eagle Ford as the other main gas driver.

Oil growth has come from a renewed focus on the Permian basin as well as major growth from the Eagle Ford and Bakken.


16

increased 422,000 Bbls/d from Q1/08 to Q1/12 (note that other NGLs are accounted for in extraction losses from marketable gas production). We note, however, that Eagle Ford activity started later than the Bakken, and therefore has accounted for a bigger proportion of the more recent growth.

Exhibit 4. Y/Y Changes In Marketable Gas Production By Play

(2,500)

(1,250)

-

1,250

2,500

3,750

5,000

6,250

7,500

8,750

10,000

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

Q4/10

Q1/11

Q2/11

Q3/11

Q4/11

Q1/12

Mm

cf/d

Eagleford Marcellus PA Haynesville Fayetteville

Barnett Woodford Emerging Liquids Plays US Bakken

Mississippi Lime Permian Anadarko Basin Total Production

Exhibit 5. Y/Y Changes In Oil Production By Play

(100,000)

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

1,000,000

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

Q4/10

Q1/11

Q2/11

Q3/11

Q4/11

Q1/12

Bbl

s/d

Eagleford Marcellus PA Haynesville Fayetteville

Barnett Woodford US Bakken Emerging Liquids Plays

Mississippi Lime Permian Anadarko Basin

Source for Exhibits 4 and 5: HPDI and CIBC World Markets Inc.

NGL Growth…Another Example Of Too Much Of A Good Thing Any discussion of North American resource play production cannot avoid reference to the production of NGLs. For investors wanting a general background on NGLs and how they fit into the North American energy mix, please refer to Appendix page 132. Generally speaking, NGL production growth is closely tied to natural gas production growth. When liquids prices are higher than natural gas prices on a btu basis (less processing costs), producers will move to extract as much of the liquids as possible from the gas stream and sell them as separate products. In the event that liquids prices are less than gas (not seen for many years now), producers can leave certain amounts of liquids in the stream and sell the product as higher heat content gas.


17

With the initial stage of the resource play revolution focusing on dry gas plays such as the Haynesville, the natural gas market was quickly overwhelmed and natural gas prices plummeted. The focus over the past two years has gradually moved to liquids-rich gas plays as well as tight oil plays. The big focus on liquids-rich plays, particularly the Eagle Ford in Texas, has led to a boom in U.S. NGL production. As depicted in the following chart, U.S. gas plant production of NGLs (note: some gas liquids such as condensate are typically stripped out at the wellhead and are typically reported as part of the oil production stream above while other NGLs are extracted at natural gas plants) increased 120,000 Bbls/d (7%) in 2009, 164,000 Bbls/d (9%) in 2010 and 110,000 Bbls/d (5%) in 2011 – substantial growth. There has been no meaningful shift in the composition of NGLs, with typical gas plant output being ~14% pentanes plus, 41% ethane, 29% propane and 17% butane and isobutene. From a regional perspective, NGL growth has been largest out of PADD 3 driven by the explosion of the Eagle Ford (high liquids content), which has accounted for ~42% of growth from Q1/08-Q1/12. The balance of growth is roughly evenly split from PADD 2 and PADD 3 production.

Exhibit 6. U.S. NGL Production By Product

U.S. NGL Production By Type U.S. NGL Production By Area

-

250

500

750

1,000

1,250

1,500

1,750

2,000

2,250

2,500

2,750

3,000

Q1/08

Q2/08

Q3/08

Q4/08

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

Q4/10

Q1/11

Q2/11

Q3/11

Q4/11

Q1/12

('000

Bbl

/d)

Pentanes Plus Detail On LPG

Ethane-Ethylene Propane and Propylene

Normal Butane-Butylene Isobutane-Isobutylene

0

250

500

750

1,000

1,250

1,500

1,750

2,000

2,250

2,500

2,750

3,000

Q1/08

Q2/08

Q3/08

Q4/08

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

Q4/10

Q1/11

Q2/11

Q3/11

Q4/11

Q1/12

Q2/12

('00

0 B

bls

/d)

PADD 1 PADD 2PADD 3 PADD 4PADD 5

Source: EIA and CIBC World Markets Inc.

Once again, the market is showing efficiency as the big boom in drilling liquids rich gas plays are starting to put very material pressure on NGL processing margins. Despite the recent weakness in NGL prices, we are not yet seeing any slowdown in activity on liquids-rich plays just yet. We expect the U.S. NGL basket to remain weak (i.e., in the 45% range vs. WTI) for the foreseeable future.

The specific issues vary by component of the NGL basket but the one commonality is clearly that the rapid growth has overwhelmed local demand and infrastructure. With the exception of ethane, the rest of the NGL basket is increasingly reliant on being exported into the global market as supply growth far eclipses domestic demand growth.

Margins for ethane are at rejection levels (where ethane remains in the gas stream) reflecting the lack ethane demand. There is a large backlog of fractionation plants to be built and also for steam crackers (which are the main demand driver to turn ethane into ethylene for chemical uses) but these will only come on-stream progressively. Propane demand remains highly weather dependent and therefore is suffering from the same overhang of a warm winter that is depressing natural gas prices. We expect propane prices to increase seasonally but remain generally weaker than historical ranges given the limited domestic structural growth and continued supply pressures.

The big boom in drilling liquids rich gas plays are starting to put very material pressure on NGL processing margins.


18

For a more detailed discussion on NGLs, please refer to Appendix page 132.

Exhibit 7. NGL Prices – U.S. And Canada

($2.00)$0.00$2.00$4.00$6.00$8.00

$10.00$12.00$14.00$16.00$18.00$20.00$22.00$24.00

Jan-1

1

Feb-11

Mar-11

Apr-11

May-11

Jun-1

1Ju

l-11

Aug-11

Sep-11

Oct-11

Nov-11

Dec-11

Jan-1

2

Feb-12

Mar-12

Apr-12

May-12

Jun-1

2Ju

l-12

Aug-12

US$

/Mcf

Ethane at Mt. Belvieu Propane at Mt. BelvieuButane at Mt. Belvieu Isobutane at Mt. BelvieuNatural Gasoline at Mt. Belvieu US Basket Price

($2.00)$0.00$2.00$4.00$6.00$8.00

$10.00$12.00$14.00$16.00$18.00$20.00$22.00$24.00

Jan-1

1

Feb-11

Mar-11

Apr-11

May-11

Jun-1

1Ju

l-11

Aug-11

Sep-11

Oct-11

Nov-11

Dec-11

Jan-1

2

Feb-12

Mar-12

Apr-12

May-12

Jun-1

2Ju

l-12

Aug-12

C$/

Mcf

Mixed Butane EdmontonMixed Propane EdmontonCondensate

Source: Bloomberg and CIBC World Markets Inc.

One interesting point on NGLs is that although prices are linked between Canada and the U.S., they can still vary by significant margins. As depicted in the chart above, Canadian NGL margins have generally remained stronger than U.S. margins as Canada has several unique uses for NGLs. The primary difference is the demand within Alberta for condensate to dilute bitumen to pipeline specifications and for butane use as a recovery solvent in the oil sands. The big drivers for these NGLs mean that Alberta still imports large amounts of condensate from the U.S., which typically means that Alberta condensate is priced at a transportation premium to U.S. hubs (and the transportation premiums are large right now). Given the robust growth in outlook for oil sands, we see no change to the trend of increasing condensate and butane demand. In fact, with more producers experimenting with solvent assisted SAGD (SAP or SAGD+ and various other acronyms) butane demand could accelerate well beyond its historical growth. Overall, Canadian NGL pricing has come under pressure but is likely to remain elevated vs. U.S. margins.

Non-resource Play Production In Steep Decline The North American E&P industry has clearly proved its ability to quickly reallocate capital to the highest return and highest growth opportunities. Unsurprisingly, as the industry shifted its emphasis from conventional drilling to gas resource plays and more recently liquids-rich and oil resource plays, conventional (or non-resource play production) for both natural gas and oil has declined consistently, but not nearly enough to offset the tremendous strides being made elsewhere.

After years of declining production, overall U.S. marketable gas production grew 1.3 Bcf/d in 2009, 1.8 Bcf/d in 2010 and 3.3 Bcf/d in 2011. As discussed previously, the large increases were driven by resource play production that grew 2.7 Bcf/d in 2009, 3.9 Bcf/d in 2010 and an astonishing 6.4 Bcf/d in 2011. What these numbers imply is that not all of the shale growth has been incremental. Clearly the aggressive spending on shales has cannibalized spending on other conventional opportunities, mitigating somewhat the overall rate of U.S. supply growth somewhat (albeit U.S. gas production growth has been impressive). The following chart depicts the trends in U.S. resource play vs. non-resource play production. As depicted, non-shale volumes declined 1.1 Bcf/d in 2009 (3%), 1.8 Bcf/d in 2010 (5%) and approximately 1.6 Bcf/d (4.5% in) in 2011. With virtually no rigs currently targeting conventional natural gas targets, there is little doubt this trend will continue or even accelerate.

Canadian NGL margins, primarily for Butane and Condensate, have generally remained stronger than U.S. margins as Canada has several unique uses for NGLs.

Non-shale gas volumes declined 1.1 Bcf/d in 2009 (3%), 1.8 Bcf/d in 2010 (5%) and approximately 1.6 Bcf/d (4.5% in) in 2011. With virtually no rigs drilling conventional gas this trend will continue (or accelerate).


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Exhibit 8. U.S. Natural Gas Shale Vs. Non-Shale (MMcf/d)

-

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

Q1/08

Q2/08

Q3/08

Q4/08

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

Q4/10

Q1/11

Q2/11

Q3/11

Q4/11

Q1/12

Mm

cf/d

Non Resource Play Gas Production Resource Play Gas Production


The oil side of the equation looks very similar to natural gas, albeit with a slightly later starting point. Overall U.S. oil production increased 290,000 Bbls/d in 2009, 292,000 Bbls/d in 200 and a whopping 535,000 Bbls/d in 2011. The recent ramp-up towards 500,000 Bbls/d+ growth is very likely to continue given the continued high growth in oil-weighted rig counts (discussed in more detail in later sections). As highlighted previously, the key driver behind these large oil growth numbers is the boom in resource play production. Resource play production increased 216,000 Bbls/d (25%) in 2009, 354,000 Bbls/d (32%) in 2010 and 610,000 Bbls/d (42%) in 2011, while non-resource play production in the U.S. has been declining approximately 6%/year (~150,000 Bbls/d per year) since 2008.

Exhibit 9. U.S. Oil Resource Play Vs. Non-resource Play Production (Bbls/d)

-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

4,500,000

5,000,000

Q1/08

Q2/08

Q3/08

Q4/08

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

Q4/10

Q1/11

Q2/11

Q3/11

Q4/11

Q1/12

Bbl/d

Non Resource Play Oil Production Resource Play Oil Production


Non-resource play oil production in the U.S. has been declining approximately 6%/year (~150,000 Bbls/d per year) since 2008.


20

Resource Play Trends IPs Stabilizing After Step Change Improvements In 2008-2010 The early days of the resource boom seemed to be marked by continuous step changes in IP rates as producers experimented with longer and longer reach wells with ever increasing frac segments. Based on the IP trends in the plays we have been observing recently we have seen stabilizing trends in IP rates, indicating that much of the easy gains are behind us, or that incremental gains are being disguised by more marginal reservoir. In either case, going forward we do not expect to see dramatic industry wide IP rate improvements the way we saw in the first three years of the resource boom.

Exhibit 10. Weighted Average IP (U.S. Plays)

0.0

0.5

1.0

1.5

2.0

2.5

3.0

Q1/08

Q2/08

Q3/08

Q4/08

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10Q4/10

Q1/11Q2/11

Q3/11Q4/11

Q1/12

Mm

cfe/

dGasLiquids


The other key takeaway from Exhibit 10 is the big increase in liquids yield as a proportion of the weighted average industry IP rate. With the big uplift in pricing available in liquids, it is no surprise that industry moved aggressively to harness this value – so much so that liquids prices have recently come under significant pressure. However, even with the weakness in NGL pricing, the uplift is still meaningful enough for producers to continue to focus on liquids-rich plays.

Cycle Times – Still Lots Of Room To Improve Cycle times are the number of days between when a well is spud and when it is placed on-stream (or the time to drill, complete and tie-in a well). We have based our analysis on drilling and licensing records. The data is not available for every well (in a consistent manner) but for all plays we were able to gather a sample of over 1,000 wells with seemingly accurate data.

Many companies talk about new records being set for time to drill a well or time to complete a well, but the reality is that the data seems to indicate on average that industry cycle times are still quite high. Our approach to quantifying this is to look at each play and take the calculated days between reported spud date and on-stream date. The following charts depict the cycle times for the Eagle Ford, Haynesville, Bakken and Marcellus. As depicted, the Haynesville in recent months has actually seen quite a meaningful declining trend in cycle times, which seems to mirror the maturity of this play (i.e., with rig counts dropping over the past year, the completion/infrastructure backlog is subsiding – making it easier/quicker to tie-in wells). Additionally, the improvement is also likely due to operators having more flexibility to move to more efficient pad drilling now that land retention drilling is largely complete.


21

Exhibit 11. Resource Play Cycle Times

Eagle Ford Cycle Times (Days) Bakken Cycle Times (Days)

0

20

40

60

80

100

120

140

160

180

200

0

20

40

60

80

100

120

140

160

180

200

Haynesville Cycle Times (Days) Marcellus Cycle Times (Days)

0

20

40

60

80

100

120

140

160

180

200

0

20

40

60

80

100

120

140

160

180

200


Cycle times in the Haynesville (in recent months) and Eagle Ford are starting to show improvement but still have considerable room to improve on average. Bakken and Marcellus cycle times are actually getting longer, likely reflecting the intense (and climbing) activity levels. Based on depth and average completion designs, we believe in an unconstrained market, cycle times for these plays should be able to get down to ~40 days on average – an important point to consider as we forecast production growth from these plays.

Excess Capacity Still Exists There is no doubt that substantial productive capacity exists in many emerging resource plays. In some plays, like the Haynesville and Barnett, where activity has slowed meaningfully, the inventory of drilled but non-completed wells has decreased as completion/tie-ins have finally caught up with drilling activity. However, in hot plays like the Bakken, Eagle Ford and Marcellus, this is clearly not the case – the only question is how much excess capacity exists? Unfortunately, it is almost impossible to quantify the backlog of drilled but non-completed wells. There is plenty of speculation that there are over 1,000 wells in the Marcellus yet to come on, ~800 in the U.S. Bakken and nearly 1,500 in the Eagle Ford. However, as we dig into the methodology behind those estimates, it is apparent that they are based on very high level statistics. Directionally they are likely correct but one should not rely too heavily on these estimates.


22

One interesting way to gauge the magnitude of excess capacity is to look at the differences in producing day production for the main plays vs. recorded actual calendar day averages. The difference is not necessarily all production that could be sustained if bottlenecks didn’t exist, but it does provide an indication of how much production is being held back by infrastructure bottlenecks, etc.

The following chart looks at the producing day vs. calendar day production data for the Eagle Ford and Bakken. As depicted, we have seen a steady increase in producing day production in both plays vs. calendar day, implying that infrastructure bottlenecks are weighing on production up to 100,000 Boe/d or approximately 8% on just these two plays alone.

Exhibit 12. Producing Day Vs. Calendar Day For Bakken & Eagle Ford – Indicates ~100,000 Boe/d Held Back

500,000

600,000

700,000

800,000

900,000

1,000,000

1,100,000

1,200,000

1,300,000

1,400,000

Jan-1

1

Feb-11

Mar-11

Apr-11

May-11

Jun-1

1Ju

l-11

Aug-11

Sep-11

Oct-11

Nov-11

Dec-11

Jan-1

2

Feb-12

Mar-12

Boe/

d

Producing DayCalendar Day


Declines On Resource Play Production Running 36% – A Big Curve To Keep In Front Of With the big push into high decline horizontal wells, the overall U.S. decline rate remains at very high levels. We calculate actual aggregate declines from the main U.S. shales plays at 34% in 2011 (measured from Q4/10 to Q4/11) and we forecast declines in the 36% range for 2012 (measured from Q4/11 to Q4/12). This implies the need for a large 10 Bcfe/d of production additions just to offset declines from resource plays – a large undertaking.

Although U.S. declines are steep, the industry has shown that if it sustains high levels of drilling activity that it can still not only offset declines but also grow production in a meaningful way. Given our outlook for reasonably robust commodity prices, we see no imminent risks of drilling not offsetting declines. However, this does highlight the intense volatility that U.S. resource play production does have vs. changes in commodity prices or changes to regulations. The biggest risk to the production outlook in our view is any legislation that bans or imposes undue restriction on fraccing, which is the heart of the U.S. production renaissance. With a decline rate in the 36% range, the shale production profile would quickly turn from a picturesque renaissance to the dark ages.

We forecast resource play decline rates at ~36% for 2012, implying the need for ~10 Bcfe/d of production additions just to offset declines – a large undertaking.

With such a big decline rate, any harsh changes to fraccing rules would quickly put the US energy renaissance back to the dark ages.


23

Play IPs Are Variable – But Some More Than Others Through our studies, we have pulled data on over 57,000 wells across 28 plays and have assembled type curves based on each play. The notion of “type curve” is misleading to some investors as it carries the connotation that resource play well performance is quite homogenous. The reality is type curves are highly variable across plays and are meant to represent the statistical average of wells, not that every well will perform at the said “type curve” rates. While all resource plays see significant variability in type curve performance, we note that the magnitude of variability is bigger in some plays than others. To quantify this, we have calculated the co-efficient of variation (st-dev of IPs relative to the average IP) across all the different plays. The following chart ranks the plays according to this metric. As depicted, the Fayetteville and Haynesville are generally the most cohesive in terms of type curve performance moving down to the Mississippi Lime and Woodford. The Mississippi Lime’s high variability likely reflects the early stage of the play as opposed to an overall higher level of risk, whereas the Woodford and Marcellus are more mature and do represent genuine variability.

Exhibit 13. Coefficient Of Variation Of U.S. Resource Play IPs

2.70

1.43

1.22 1.15 1.13

0.800.68 0.65

0.54 0.49

0.0

0.3

0.5

0.8

1.0

1.3

1.5

1.8

2.0

2.3

2.5

2.8

3.0

ML

Woodford

Marcell

us

Permian

Hz

Aandark

o Hz

Eagle Ford

Barnett

Bakken

Haynesv

ille

Fayett

eville


US E&Ps Addicted To Spending… Any discussion of resource play trends would not be complete without highlighting how all of this activity is being funded…and whether or not this is sustainable. U.S. E&Ps are addicted to growth and addicted to spending. To illustrate this point, we highlight the capital spending vs. cash flow profiles of the Top 40 U.S. public E&Ps. As depicted, since the start of 2008 (the start of the unconventional boom), the Top 40 has spent an average of 115% of cash flow – spending in line with cash flow only during the financial crisis. In total, over the past four years, the Top 40 have collectively outspent cash flow by an amazing $55 billion. Part of this massive capex gap was made up of external debt and equity but there is little doubt big JV activity has helped propagate this massive spending level. Based on current consensus expectations for the Top 40, this trend is expected to continue through 2012/13 with consensus expectations of capex outweighing cash flow by $26 billion – clearly implying the need for massive external capital infusions with JVs once again being the primary source.

The Top 40 US E&Ps have collectively outspent cash flow by an amazing $55 billion since early 2008. Consensus forecasts are for capex to exceed cash flow by an additional $26 billion in 2012/13.


24

Exhibit 14. U.S. Top 40 Capex / Cash Flow

$0

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

2008 2009 2010 2011 2012e 2013e

Cap

ex &

Cas

h Fl

ow ($

mm

)

50%

60%

70%

80%

90%

100%

110%

120%

130%

Cap

ex/C

ash

Flow

Cash Flow Capex Capex/Cash Flow

Source: Company reports and CIBC World Markets Inc.

…JVs Have Filled The Void But Will This Continue? We have seen U.S. producers tap all types of externally capital over the past four years to sustain high growth including traditional debt and equity and a relatively new found preference for Joint Venture activity. The following chart depicts recent JV deals in Canada and the U.S. As depicted, we have seen at least $32 billion of JV announcements, importantly with at least $14 billion of this coming in the form of upfront payment or approximately 25% of the current external capital needs.

Exhibit 15. Joint Venture Activity

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

CHK & PXP (O

ct-08

)

CHK & STO (N

ov-08)

CHK & B

P (Feb

-09)

KWK & E (M

ay-09

)

ERF & C

hief (A

ug-09)

PDC & Lim

e Rock

(Nov-0

9)

CHK & TOT (J

an-10

)

ECA & K

oGas (M

ar-10

)

APC & M

itsubish

i (Mar-

10)

ATLS & R

elian

ce (A

pr-10)

PWT & C

hina Inv.

Co. (May

-10)

XCO & B

G Gro

up (June-1

0)

PXD & R

elian

ce (J

uly-10

)

PWT & M

itsubish

i (Aug-10

)

Carrizo

& R

elian

ce (S

ept-1

0)

TLM & STO (O

ct-10

)

TLM & SSL (D

ec-10

)

CHK & C

NOOC (Jan

-11)

TLM & SSL (M

ar-11

)

PRQ & Petr

onas (J

une-11)

ECA & K

oGas (O

ct-11

)

NXY & IN

PEX (Nov-1

1)

CHK & TOT (D

ec-11

)

DVN & Sinopec

(Jan

-12)

ECA & M

itsubish

i (Feb

-12)

Up-Front Drilling Carry


The key question mark in today’s environment is whether or not the large JVs can be counted on for funding? There have been several recent deals [Devon (DVN-NYSE) and Comstock (CRK-NYSE)] still depicting strong desire from external partners to gain North American resource exposure. The risk in our view is that if commodity prices correct once again (it was only a month ago that WTI was in the low US$70s) that external JV partners will become more disciplined – at a time when there are huge demands for capital. Such a scenario could have a large impact on drilling activity, particularly in the 2013 time frame given the big funding void that exists.

JV’s have played a big role in funding E&P growth with at least $32 billion of JV announcements (including $14 billion of up-front payment).

We believe the JV market is getting riskier given the large number of assets on the market and less certain macro environment.


25

Based on our regression of rig activity vs. oil and natural gas prices over the past few years, the current 2013 commodity strip of ~US$90/Bbl and US$3.75/Mcf natural gas would imply a rig count in the 1,700 range, down ~10% from current levels. Rig activity could remain in the current 1,900 range if sufficient external capital is tapped – which is a reasonable assumption today given still robust prices. However, a drop in oil prices down to the US$80/Bbl range with no external capital would argue for a rig count in the 1,500 range.

Key U.S. Growth Plays

The Eagle Soars….. The sudden thirst for liquids (no pun intended) is leading to a profound shift in drilling activity. Nowhere is this more evident than in the dramatic switch in activity from the Haynesville (dry gas) to the Eagle Ford (liquids-rich). While the Haynesville was notable for its incredibly high IP rates, the Eagle Ford’s higher priced crude and NGL weighting has sucked massive resources away from the Haynesville. The Eagle Ford has now become the most active play in the U.S.

Exhibit 16 depicts the rig and well counts for the Haynesville and Eagle Ford. As depicted, the Haynesville rig count has declined from its high of 207 rigs (monthly average) down to 45 rigs now whereas the Eagle Ford has picked up all the slack and is now running 258 rigs, the highest horizontal rig count of any major resource play ever. Additionally, anecdotal evidence suggests that Eagle Ford operators will continue to add rigs into the area, likely making this the biggest rig concentration ever seen in any North American shale play.

Exhibit 16. The Haynesville-Eagle Ford Switch

0

50

100

150

200

250

300

350

400

Q1/08

Q2/08

Q3/08

Q4/08

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

Q4/10

Q1/11

Q2/11

Q3/11

Q4/11

Q1/12

Q2/12

Rig

s

Eagle Ford

Haynesville

Source: Smith Data and CIBC World Markets Inc.

Despite really only ramping up in later 2009, it is remarkable that the Eagle Ford is now producing over 770,000 Boe/d (416,000 Bbls/d of oil and 2.1 Bcf/d of natural gas). The actual liquids weight will be higher than this as well data only includes liquids separated at the well head while other NGLs will be extracted at gas plants. As the rig count continues to grow, the overall growth rate will continue to rise as well, with output in Q1/12 estimate to have been up approximately 500,000 Boe/d vs. Q1/11 and 180,000 Boe/d sequentially.

The Haynesville rig count has declined from its high of 207 rigs down to 45 rigs now whereas the Eagle Ford has picked up all the slack and is now running 258 rigs – the highest rig count of any major resource play.

Despite really only ramping up in later 2009, it is remarkable that the Eagle Ford is now producing over 770,000 Boe/d (416,000 Bbls/d of oil and 2.1 Bcf/d of natural gas).


26

Exhibit 17. Eagle Ford Growth – Q1/08-Q1/12

Vintage Quartlery Production Q/Q Growth

-

600

1,200

1,800

2,400

3,000

3,600

4,200

4,800

5,400

6,000

Q1/08

Q2/08

Q3/08

Q4/08

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

Q4/10

Q1/11

Q2/11

Q3/11

Q4/11

Q1/12

Mm

cfe/

d

0

100

200

300

400

500

600

700

800

900

1,000

Mbo

e/d

0

100

200

300

400

500

600

700

800

900

1,000

1,100

1,200

Q1/08

Q2/08

Q3/08

Q4/08

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

Q4/10

Q1/11

Q2/11

Q3/11

Q4/11

Q1/12

Mm

cfe/

d

0

20

40

60

80

100

120

140

160

180

200

Boe/

d

Gas Q/Q Production

Liquids Q/Q Production


IP Trends & Dispersion The Eagle Ford technically spans 25 counties but the vast majority of production and activity are focused in a few main areas. In Q1/12, the top 5 counties accounted for 75% of total production (top counties being Karnes at 20%, Webb at 18%, Dewitt at 15%, Lasalle at 11% and Gonzales at 10%). Additional background on the Eagle Ford play can be found on page 160 of our Appendix, including detailed information on results by operator and country.

Our survey of approximately 2,700 Eagle Ford wells indicates an average 30-day IP (calendar day) during 2010 and 2011 of approximately 3.1 MMcfe/d with an average 50% liquids yield at the well head. We note that IPs from the top 5 largest operators in the play are in the 4.8 MMcf/d range (800 Boe/d). Overall IP trends have bounced around quarter to quarter (as illustrated in the chart below), characteristic of an early-stage play and likely reflecting some temporary infrastructure bottlenecks. Liquids yields in the play have changed quite considerably, ranging from the 30% range in early 2010 and climbing in recent quarters to approximately 62% - clearly reflecting an industry focus on the higher NGL and crude oil-weighted areas of the play.

Top-quartile IPs average 1,420 Bbls/d while bottom-quartile IPs average 158 Bbls/d. We also see considerable difference in IP rates among the major Eagle Ford producers, with top operators such as GeoSouthern (private) and EOG (EOG-NYSE) achieving average IP rates of 1,000 Boe/d and 820 Boe/d, respectively, down to a low of 474 Boe/d for Chesapeake (CHK-NYSE) (of the top 20 operators by production – there are many IP rates for the remaining 50 companies below Chesapeake’s average). As with any play, IPs vary considerably by location (see Appendix 161 for more details on operator and county information) but on balance, we have seen the highest IPs in Dewitt county (1,041 Boe/d IP with 51% liquids), Gonzales (994 Boe/d with 88% liquids), Live Oak (894 Boe/d with 88% liquids) and Karnes county (878 Boe/d IP with 74% liquids).


27

The following charts depict the average IP rates and dispersion of rates for the entire Eagle Ford play.

Exhibit 18. Eagle Ford IP Trends & IP Distribution

Quarterly IP Peak IP Distribution (2008+)

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

00 03 06 09 12 15 18 21 24 27 30 33 36 39 42

Months on Production

MM

cfe/

d

0

80

160

240

320

400

480

560

640

720

Boe/

d

Q1/08 Q2/08 Q3/08 Q4/08Q1/09 Q2/09 Q3/09 Q4/09Q1/10 Q2/10 Q3/10 Q4/10Q1/11 Q2/11 Q3/11 Q4/11Q1/12

0

100

200

300

400

500

600

700

800

037

074

01,1

101,4

801,8

502,2

202,5

902,9

603,3

303,7

004,0

704,4

404,8

105,1

805,5

505,9

206,2

906,6

60

Peak IP Rate (Boe/d)

Freq

uenc

y


The Eagle Ford is unique vs. many of the other shale plays in that the play has very large and very well defined windows for crude, liquids-rich gas and dry natural gas. The following map depicts the rough contour of each window based on observed liquids yields. While the bulk of activity has clearly been in the liquids window (68% of 2011 wells were drilled in oil window, 14% in liquids-rich or transitional window and 18% into the dry gas window – see Appendix page 160), we are starting to see activity pick up in the liquids-rich part of the play as well.

Exhibit 19. Eagle Ford – Where The Liquids Lie

Major Producers1 Dry Gas2 Wet Gas3 Crude Oil

Barnett

TEXAS

MEXICO

Dimmit

La Salle

Webb

McMullen

Atascosa

Live Oak

Karnes

Wilson

Gonzales

Dewitt

Permian

Source: HPDI, Google Earth and CIBC World Markets Inc.


28

Exhibit 20. Eagle Ford – Drilling By Portion Of The Play (Eagle Ford Reconciliation)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Q1/10 Q2/10 Q3/10 Q4/10 Q1/11 Q2/11 Q3/11 Q4/11

Pct O

f Wel

ls D

rille

d

Oil Window Liquids Window Gas Window


Supply Costs The following charts depict supply costs for the Eagle Ford at today’s costs. As depicted, the average Eagle supply cost of US$60/Bbl with top-quartile wells breaking even at US$50/Bbl and lower-quartile results breaking even at US$70/Bbl. Break-evens vary as to whether or not a well is in the oil or liquids-rich gas windows. Liquids-rich wells hit break-even returns at approximately US$60/Bbl with a US$5/Mcf gas price (assuming NGL prices at 45% of WTI) or ~US$70/Bbl with a US$4.50/Mcf gas price.

Exhibit 21. Eagle Ford Economics (All Wells)

$60$70$80$90$100$110$120 $2.00

$3.00

$4.00

$5.00

$6.00

$7.00

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

IRR - %

US$/Bbl

US$/Mcf

Source: CIBC World Markets Inc.


29

Exhibit 22. Eagle Ford Crude Economics

$60$70$80$90$100$110$120 $2.00

$3.00

$4.00

$5.00

$6.00

$7.00

0%

20%

40%

60%

80%

100%

120%

IRR - %

US$/Bbl

US$/Mcf


Exhibit 23. Eagle Ford Wet Gas Economics (NGLs 45% Of WTI)

$60$70$80$90$100$110$120 $2.00

$3.00

$4.00

$5.00

$6.00

$7.00

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

IRR - %

US$/Bbl

US$/Mcf



30

Growth Projections The following charts depict growth scenarios out of the Eagle Ford. Our base case view is based on current rig counts while low and high scenarios vary rig counts up/down by 20% from current levels (alternatively, the low and high cases can be thought of as a 20% improvement/decrease in rig productivity/drilling efficiency). As depicted, at current rig counts with static efficiencies we could see the Eagle Ford growing to the 2.0 MMBoe/d range (1.2 MMBbls/d of light oil and 4.8 Bcf/d of natural gas) by 2016 and 2.6 MMBoe/d (1.6 MMBbls/d of light oil and 6.1 Bcf/d of natural gas) by 2020. With a 20% improvement in efficiency OR a 20% improvement rig count, we could see the Eagle Ford reach 2.3 MMBoe/d by 2016 and 3.1 MMBoe/d by 2020.

Exhibit 24. Eagle Ford Growth Model

Rigs Running Wells Drilled

0

50

100

150

200

250

300

350

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

Rig

s R

unni

ng

HighBaseLow

0

500

1,000

1,500

2,000

2,500

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

Wel

ls D

rille

d

HighBaseLow

Total Base Production Forecast Actual Production & Forecast Cases

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

Q2/19E

Q1/20E

Q4/20E

Mm

cfe/

d

-

333

667

1,000

1,333

1,667

2,000

2,333

2,667

3,000

3,333

Mbo

e/d

Liquids (Right)

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

Q2/19E

Q1/20E

Q4/20E

Mm

cfe/

d

0

333

667

1,000

1,333

1,667

2,000

2,333

2,667

3,000

3,333

Mbo

e/d

High

Base

Low

Liquids Growth (Bbl/d) Gas Growth (Boe/d)

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

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

HighBaseLow

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

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

HighBaseLow


At current rig counts with static efficiencies we could see the Eagle Ford growing to the 2.0 MMBoe/d range (1.2 MMBbls/d of light oil and 4.8 Bcf/d of natural gas) by 2016 and 2.6 MMBoe/d (1.6 MMBbls/d of light oil and 6.1 Bcf/d of natural gas) by 2020.


31

Hayneville A Has Been? In what seems like eons ago, the Haynesville was the most active resource play in North American. Activity on the play really began in 2008 with the rig count quickly ramping up to 218 rigs, only to decline during the financial crisis down to 127 rigs, and back up to an all-time peak of 217 rigs in Q2/10. After Q2/10, a combination of land retention commitments having been largely met by industry and weak natural gas prices (and more importantly the belief that weak prices may persist) have led to rigs consistently being moved out of this prolific but dry gas play into other more liquids-oriented plays (as discussed previously in the Eagle Ford section).

Production growth in the Haynesville has been astonishing. From a Q1/08 average of only ~130 MMcfe/d, the play averaged ~7,500 MMcfe/d in Q4/11, making up approximately 11% of total U.S. gas supply. Growth from the play was 1.14 Bcfe/d in 2009, and averaging 2.8 Bcf/d in each of 2010 and 2011, staggering growth, particularly given the rig count decline in 2011. We attribute a substantial amount of 2011 growth due to completion of previously drilled but not tied in wells, which we now believe is largely complete.

We estimate that Q1/12 was the first quarter of declines in the Haynesville with our calculations indicating average output of 7.3 Bcfe/d, down approximately 0.3 Bcfe/d (3%) from Q4/11 although we note output is still up 1.2 Bcfe/d (20%) Y/Y. We believe the Haynesville has reached an important inflection point where it will continue to see declines in production (note there will be some noise in the short term due to some production shut-ins followed by reactivations).

Exhibit 25. Haynesville Production Growth – Q1/08-Q1/12


-

800

1,600

2,400

3,200

4,000

4,800

5,600

6,400

7,200

8,000

Q1/08

Q2/08

Q3/08

Q4/08

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

Q4/10

Q1/11

Q2/11

Q3/11

Q4/11

Q1/12

Mm

cfe/

d

0

145

290

435

580

725

870

1,015

1,160

1,305

1,450

1,595

Mbo

e/d

-300

-200

-100

0

100

200

300

400

500

600

700

800

900

1,000

1,100

1,200

Q1/08

Q2/08

Q3/08

Q4/08

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

Q4/10

Q1/11

Q2/11

Q3/11

Q4/11

Q1/12

Mm

cfe/

d

0

20

40

60

80

100

120

140

160

180

200

Boe/

d

Gas Q/Q Production



IP Trends & Dispersion The Haynesville, which presently spans 50 counties across Texas and Louisiana, the top 5 counties account for approximately 77% of production for the play (top counties/parishes being De Soto LA at 44%, Red River LA at 13%, Caddo LA at 9%, Sabine LA at 7% and Nacogdoches (TX) at 5%). Additional background on the Haynesville play can be found on page 168 of our Appendix, including detailed information on results by operator and county.

From a Q1/08 average of only ~130 MMcfe/d, the play averaged ~7,500 MMcfe/d in Q4/11, making up approximately 11% of total U.S. gas supply.

We estimate that Q1/12 was the first quarter of declines in the Haynesville with our calculations indicating average output of 7.3 Bcfe/d, down approximately 0.3 Bcfe/d (3%) from Q4/11


32

The key attraction of the Haynesville is its prolific initial productivity rates from the play. As depicted below, our survey of 2,759 Haynesville wells shows the average IP for a Haynesville well at approximately 8 MMcfe/d and has been relatively consistent in that range since mid-2009. IP rates in 2011 tailed off somewhat to 7.7 MMcfe/d, likely to a slight change in operator practices towards limiting initial rates somewhat to achieve more moderate declines. The high IP rates are partly attributable to the greater depth and pressure of the play, which also leads to another trade-off – higher decline rates. Our observed 12-month decline rate on a typical Haynesville well is approximately 75%, versus most other shales in the ~60% range (calculated from one-month average rate).

As depicted below, IP rates in the Hayneville appear to be reasonably dispersed vs. other plays. Top-quartile IPs average 14.1 MMcfe/d, while bottom-quarter IPs average 3 MMcfe/d. IP rates vary by operator (see Appendix page 169 for more operator-specific information) but of the top 10 producers, which account for 90% of production, we see IP rates range from a low of 6 MMcfe/d for XTO [ExxonMobil (XOM-NYSE)] to a high of 12 MMcfe/d for Encana.

Exhibit 26. Haynesville IP Trends & IP Distribution


0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

00 03 06 09 12 15 18 21 24 27 30 33 36 39 42

Months On Production

MM

cfe/

d

0

0.15

0.3

0.45

0.6

0.75

0.9

1.05

1.2

1.35

1.5

Boe

/d


0

100

200

300

400

500

600

700

800

900

1 929 1,857 2,785 3,713 4,641 5,569 6,497 7,425 8,353


Freq

uenc

y


Supply Costs Exhibit 27 depicts supply costs for the Haynesville at today’s costs. As depicted, the average Haynesville supply cost is ~US$4.00/Mcf with top-quartile wells breaking even at US$3.50/Mcf and lower-quartile results breaking even at US$4.50-US$5.00/Mcf. In the early days, the Haynesville supply costs/break-even costs were considered the lowest in the industry, however, while it is still low for a dry gas play, in the context of all plays (i.e., including tight oil and liquids-rich gas), the supply costs are uncompetitive. In general, we believe natural gas prices would have to get to the US$5.00/Mcf range for the Haynesville to begin pulling rigs back out of the Eagle Ford.

The average Haynesville supply cost is ~US$4.00/Mcf with top-quartile wells breaking even at US$3.50/Mcf and lower-quartile results breaking even at US$4.50-US$5.00/Mcf.


33

Exhibit 27. Haynesville Economics

$60$70$80$90$100$110$120 $2.00

$3.00

$4.00

$5.00

$6.00

$7.00

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

IRR - %

US$/Bbl

US$/Mcf


Growth Projections Exhibit 28 depicts growth scenarios out of the Haynesville shale. Our base case view is based on current rig counts while low and high scenarios vary rig counts up/down by 20% from current levels (alternatively, the low and high cases can be thought of as a 20% improvement/decrease in rig productivity/drilling efficiency). As depicted, at current rig counts with static efficiencies, we expect to see the Haynesville continue to maintain a declining profile until mid-2014. After peaking in Q4/11 at 7.6 Bcfe/d, we expect production to drop to ~6.2 Bcfe/d by late 2012 and 5.7 Bcfe/d by late 2013. Production after this point will gradually moderate as the steep decline phase is largely complete. As declines stabilize, the current rig count could once again start to deliver moderate growth in the 2016-2020 time frame. With a 20% improvement in efficiency OR a 20% improvement rig count, we could see the Haynesville reach 5.6 Bcfe/d by 2016 and 6.2 Bcfe/d by 2020.

The efficiency gain could be particularly important in the Louisiana portion of the Haynesville as current land regulations make it prohibitive to drill across section boundaries (i.e., limited to one-mile horizontals). The Louisiana state government is currently expecting to enact regulations to allow longer reach drilling, which could reduce cycle times meaningfully as producers move to bigger pads with longer reach wells – characteristic of other resource plays.

At current rig counts with static efficiencies, we expect to see the Haynesville declining until mid-2014.


34

Exhibit 28. Haynesville Activity Levels & Growth Projections


0

50

100

150

200

250

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

Rig

s R

unni

ng

HighBaseLow

0

200

400

600

800

1,000

1,200

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

Wel

ls D

rille

d

HighBaseLow


-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

Q2/19E

Q1/20E

Q4/20E

Mm

cfe/

d

0

167

333

500

667

833

1,000

1,167

1,333

Mbo

e/d

Liquids

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

Q2/19E

Q1/20E

Q4/20E

Mm

cfe/

d

0

167

333

500

667

833

1,000

1,167

1,333

Mbo

e/d

Low Base High


-300,000

-200,000

-100,000

0

100,000

200,000

300,000

400,000

500,000

600,000

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

HighBaseLow

-300,000

-200,000

-100,000

0

100,000

200,000

300,000

400,000

500,000

600,000

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

HighBaseLow



35

LNG Could Rekindle Interest In Haynesville What was once hot has become cold as ice but interest level in the Haynesville could be rekindled in the not too distant future. Why? Proximity to LNG facilities. As discussed in our report, LNG: The Race Is On, we believe companies that have committed to the Sabine Pass LNG export terminal, or who are planning to commit volumes to other facilities pending DOE export approval, will want to be naturally hedged. The structure of Gulf Coast LNG is different than many regions in that so far, it is being done on a tolling basis. Under this structure, the terminal operator is essentially a utility that pulls gas off the grid, and under a long-term contract will liquefy the gas for the buyer who then takes delivery and can market it wherever it wants. Even though a buyer is not able to move its own molecule of gas through the facility, we believe many buyers will want to be naturally hedged against a potential rise in U.S. gas prices longer term (recalling that the contracts are 20 years+).

From this perspective, the Haynesville is well positioned as it is a large producing asset that can be sustained for many years without a big increase in drilling, which is an ideal profile for many LNG buyers. Additionally, the Haynesville play is in close proximity to the export facilities, which eliminates basis risk from the producing region to where the gas is purchased from. We believe Asian buyers [Kogas (036460-KS), GAIL (GAIL-BO), etc.] who have committed for capacity from Sabine Pass (or more recently the Freeport project) will be highly motivated to obtain a natural hedge against spot price risk. The most logical place to obtain this hedge is the Haynesville, which could bring new interest to these assets that many regard as having little value in today’s market.

Exhibit 29. Gulf Coast Facilities (Freeport, Sabine, Lake Charles)

FreePort LNG

Sabine Pass LNG

160 Km

Lake Charles LNG(TrunkLine LNG) 71 Km

Tuscaloosa

Haynesville-BossierBarnett

Eagle Ford

Woodford

Woodford-Carny

Fayetteville

Floyd-Neal

Cameron LNG

Source: CIBC World Markets Inc and Google Earth.

We believe parties who have made large LNG commitments from Sabine Pass (and more recently Freeport) will be interested in obtaining a physical hedge against US spot price risk – and Haynesville is well positioned for that Hedge.


36

Marcellus – The Beast In The East: Activity Moderating Somewhat But Still Going Hard The Marcellus is a monster. As with many shale plays, it started to get a lot of attention in early 2008 and activity has boomed since then. Unfortunately, the Marcellus earns the dubious distinction of having THE WORST data quality of any of the major shales, with data released only twice per year (which actually an improvement) and that data does not include month-by-month production as most states/plays report. This means that industry largely has to guess at overall production and well rate trends.

Our approach to gauging Marcellus production has been to back the production out of regional pipeline flows. This approach is reasonable as there are no other major growth drivers in Pennsylvania. As depicted below, based on this approach, we estimate the Marcellus is producing approximately 6.2 Bcfe/d in Q1/12, which would make it the largest shale gas play in the U.S. The Marcellus grew ~1 Bcf/d in 2009/10 and an impressive 2.4 Bcf/d from 2010/11. Even if production held flat (unlikely as still many wells are still to come on-stream) from today’s levels, it would still imply ~2.5 Bcf/d of growth in 2012 from 2011.

Exhibit 30. Marcellus Shale Production & Growth


-

600

1,200

1,800

2,400

3,000

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5,400

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Mm

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d

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-100

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Q1/08

Q2/08

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Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

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Q1/12

Mm

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d

0

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Boe/

d

Gas Q/Q Production



Even the mighty Marcellus is starting to feel the pinch of low natural gas prices, albeit it is faring far better than any other gas play, reflecting its strong economic attributes. As depicted in Exhibit 29, overall rig counts in the Marcellus have finally started to roll over. From a high of approximately 150 rigs running in late 2011, the play is now down to approximately 100 rigs running. As depicted, there is a major difference between rig counts depending on the part of the play. In the dry gas counties (primarily the northern part of the play), rig counts have fallen from a peak of 104 down to 56 while activity levels in the wet gas counties (primarily the SW of the play), rig counts have stayed relatively stagnant at 45-50 rigs running.

We estimate the Marcellus is producing approximately 6.2 Bcfe/d in Q1/12, which would make it the largest shale gas play in the U.S. The Marcellus grew ~1 Bcf/d in 2009/10 and an impressive 2.4 Bcf/d from 2010/11.

Marcellus rig counts have declined ~33%, but even at current levels it would still generate meaningful growth.


37

Exhibit 31. Marcellus Rig Count – Wet Gas Vs. Dry Gas Counties

0

20

40

60

80

100

120

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160

180

Janu

ary-10

Februa

ry-10

March-1

0

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-10

July-

10

Augus

t-10

Septem

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0

Octobe

r-10

Novem

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0

Decem

ber-1

0

Janu

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Februa

ry-11

March-1

1

April-1

1

May-11

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-11

July-

11

Augus

t-11

Septem

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1

Octobe

r-11

Novem

ber-1

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Decem

ber-1

1

Janu

ary-12

Februa

ry-12

March-1

2

April-1

2

May-12

June

-12

Rig

Cou

nt

Dry Gas Rig Count

Marcellus Wet Gas Rig Count

Source: Smith Data and CIBC World Markets Inc.

Supply Costs Exhibits 32-33 depict supply costs for the Marcellus shale at today’s costs. We have subdivided the play into a dry gas (northern) type curve as well as a wet gas curve. As depicted, the average Marcellus dry gas supply cost is US$3.00/Mcf. Due to the large liquids subsidies, the average wet gas supply cost is in the US$2.00/Mcf range assuming NGLs at 45% of WTI. While the wet gas break-evens are very low, we note that the wet gas window is a relatively small portion of the entire Marcellus play (approximately 3 counties from the entire play) and should not be construed as a proxy for the entire play.

The average Marcellus dry gas supply cost is US$3.00/Mcf. Due to the large liquids subsidies, the average wet gas supply cost is in the US$2.00/Mcf range assuming NGLs at 45% of WTI.


38

Exhibit 32. Marcellus Dry Gas Economics

$60$70$80$90$100$110$120 $2.00

$3.00

$4.00

$5.00

$6.00

$7.00

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

IRR - %

US$/Bbl

US$/Mcf


Exhibit 33. Marcellus Wet Gas Economics (NGLs 45% Of WTI)

$60$70$80$90$100$110$120 $2.00

$3.00

$4.00

$5.00

$6.00

$7.00

0%

20%

40%

60%

80%

100%

120%

140%

IRR - %

US$/Bbl

US$/Mcf



39

Growth Projections The charts in Exhibit 34 depict growth scenarios out of the Marcellus shale. Our base case view is based on current rig counts while low and high scenarios vary rig counts up/down by 20% from current levels (alternatively, the low and high cases can be thought of as a 20% improvement/decrease in rig productivity/drilling efficiency). As depicted, at current rig counts with static efficiencies, we expect to see a significant deceleration in Marcellus growth. The play averaged approximately 6.2 Bcfe/d in Q1/12 and we expect that to grow to 7.5 Bcf/d by Q1/13. While this is still quite a meaningful growth rate, it is down significantly from the 3 Bcf/d the play grew from Q1/11 to Q1/12.

There is no doubt the Beast From The East will continue to deliver big volume growth. Based on current rig counts (which are off ~30% from highs), volumes can reach ~10 Bcf/d by 2016 and over 12 Bcf/d by 2020. If we layer in some combination of 20% productivity assumptions, rig counts or cycle times, our growth projects would jump to ~12 Bcf/d by 2016 and over 14 Bcf/d by 2020.

At current rig counts with static efficiencies, we expect to see a significant deceleration in Marcellus growth. The play averaged approximately 6.2 Bcfe/d in Q1/12 and we expect that to grow to 7.5 Bcf/d by Q1/13.

Marcellus production could reach 10-12 Bcf/d by 2016 and 12-14 Bcf/d by 2020.


40

Exhibit 34. Marcellus Growth & Activity Outlook


0

50

100

150

200

250

300

350

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

Rig

s R

unni

ng

HighBaseLow

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1,000

1,500

2,000

2,500

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

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HighBaseLow


-

1,250

2,500

3,750

5,000

6,250

7,500

8,750

10,000

11,250

12,500

13,750

15,000

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

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Q2/19E

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Q4/20E

Mm

cfe/

d

-

208

417

625

833

1,042

1,250

1,458

1,667

1,875

2,083

2,292

2,500

Mbo

e/d

Liquids (Right)

-

1,250

2,500

3,750

5,000

6,250

7,500

8,750

10,000

11,250

12,500

13,750

15,000

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

Q2/19E

Q1/20E

Q4/20E

Mm

cfe/

d

0

208

417

625

833

1,042

1,250

1,458

1,667

1,875

2,083

2,292

2,500

Mbo

e/d

Low Base High


0

100,000

200,000

300,000

400,000

500,000

600,000

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

HighBaseLow

0

100,000

200,000

300,000

400,000

500,000

600,000

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

HighBaseLow



41

Bakken Booming… The Bakken (we include Three Forks in all of our Bakken analysis) has been an amazing growth story thus far, increasing from only ~90,000 Boe/d in 2008 to approximately 590,000 Boe/d in Q1/12 (510,000 Bbls/d of oil and 500 MMcf/d of natural gas). Equally impressive is that the growth momentum is not yet waning, with the rig count on the play recently reaching 230 horizontal rigs, a big uptick from the already high 180 rigs running through 2011 and 124 in 2010. Additional background on the Bakken play can be found on page 152 of our Appendix, including detailed information on results by operator and county.

Exhibit 35. Bakken Production Growth – Q1/08-Q1/12


-

600

1,200

1,800

2,400

3,000

3,600

4,200

4,800

5,400

6,000

Q1/08

Q2/08

Q3/08

Q4/08

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

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Q2/11

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Q1/12

Mm

cfe/

d

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1,000

Mbo

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Q1/08

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Q4/09

Q1/10

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Mm

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d

0

20

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Boe/

d

Gas Q/Q Production



IP Trends & Dispersion Although the Bakken play spans large areas of North Dakota and Montana, the bulk of activity has been focused in four counties of North Dakota (Dunn, McKenzie, Mountrail and Williams), which collectively account for 85% of Bakken production. Bakken IP trends bounce around modestly quarter to quarter but on balance have been quite stable for the past two years.

Our survey of 3,400 Bakken wells drilled since early 2008 indicates an average IP of 423 Boe/d (30-day calendar day average) with an 86% light oil weighting. Top-quartile IPs average 925 Bbls/d, while bottom-quartile IPs average 160 Bbls/d. We also see considerable difference in IP rates among the major Bakken producers, with top operators such as Brigham Exploration [Statoil (STO-NYSE)] and Williams Partners (WPZ-NYSE) achieving average IPs of over 600 Bbls/d vs. XTO (Exxon) at approximately 300 Bbls/d. As with any play, IPs vary considerably by location (see Appendix page 153 for more details on operator and county information) but on balance we have seen the highest IPs in Mountrail county with rates of 571 Boe/d, followed not far behind by average rates in Mackenzie county of 483 Boe/d.

The following charts depict IP trends and the dispersion of results.

Our survey of 3,400 Bakken wells drilled since early 2008 indicates an average IP of 423 Boe/d (30-day calendar day average) with an 86% light oil weighting.


42

Exhibit 36. Bakken IP Trends & IP Distribution


0.0

0.5

1.0

1.5

2.0

2.5

3.0

00 03 06 09 12 15 18 21 24 27 30 33 36 39 42


MM

cfe/

d

0

83

167

250

333

417

500

Boe/

d


0

50

100

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250

300

350

400

0 250 500 750 1000 1250 1500 1750 2000 2250 2500


Freq

uenc

y


Supply Costs The data table in Exhibit 37 depicts supply costs for the Bakken at today’s costs. As depicted, the average Bakken supply cost of ~US$65-US$70/Bbl with top-quartile wells breaking even at US$55-US$60/Bbl and lower-quartile results breaking even at US$70/Bbl+. We note that our analysis assumes Bakken Light pricing of approximately 5% discount to WTI over the long term, reflecting the more challenged market access vs. PADD 3 and many other light oil plays. This more conservative (arguably more realistic) view of pricing makes our estimated break-evens for the U.S. Bakken higher than is often suggested.

Exhibit 37. Bakken Economics

$60$70$80$90$100$110$120 $2.00

$3.00

$4.00

$5.00

$6.00

$7.00

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

IRR - %

US$/Bbl

US$/Mcf



43

Growth Projections The charts in Exhibit 38 depict growth scenarios out of the Bakken. Our base case view is based on current rig counts while low and high scenarios vary rig counts up/down by 20% from current levels (alternatively, the low and high cases can be thought of as a 20% improvement/decrease in rig productivity/drilling efficiency). As depicted, at current rig counts with static efficiencies, we could see the Bakken growing to the 1.2 MMBoe/d range (1.1 MMBbls/d of light oil and 1.1 MMcf/d of natural gas) by 2016 and 1.6 MMBoe/d (1.4 MMBbls/d of light oil and 1.4 MMcf/d of natural gas) by 2020. With a 20% improvement in efficiency OR a 20% improvement rig count, we could see the Bakken reach 1.5 MMBoe/d by 2016 and 1.9 Boe/d by 2020.

We believe there is little risk as to whether or not the Bakken has the resource to support over 1 MMBbls/d of production. The bigger question is relative economics. The Bakken is one of the most active U.S. plays but discounted pricing and higher transport costs weigh on economics vs. many competing light oil plays, particularly those in PADD 3. As more new plays mature in PADD 3, we would not be surprised to see more rigs reallocated from the Bakken southward. From a macro perspective, this would reduce the aforementioned production targets for the Bakken but on an aggregate basis would not likely have any major impact as we would see higher-than-forecast production from these other liquids plays.

At current rig counts with static efficiencies, we could see the Bakken growing to the 1.2 MMBoe/d range (1.1 MMBbls/d of light oil and 1.1 MMcf/d of natural gas) by 2016 and 1.6 MMBoe/d (1.4 MMBbls/d of light oil and 1.4 MMcf/d of natural gas) by 2020

Price discounting in PADD 2 is weighing on Bakken economics, which could see activity moderate from current levels….but there are many other plays eager to pick up these rigs.


44

Exhibit 38. Bakken Activity Levels & Growth Projections


0

50

100

150

200

250

300

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

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s R

unni

ng

HighBaseLow

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1,500

2,000

2,500

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

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HighBaseLow


-

2,000

4,000

6,000

8,000

10,000

12,000

Q1/08

Q4/08

Q3/09

Q2/10

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Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

Q2/19E

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Q4/20E

Mm

cfe/

d

-

333

667

1,000

1,333

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2,000

Mbo

e/d

Liquids (Right)

-

2,000

4,000

6,000

8,000

10,000

12,000

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

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Q4/17E

Q3/18E

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Base

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

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100,000

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250,000

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

HighBaseLow



45

Other Plays Thus far we have focused our attention on the Eagle Ford, Marcellus, Haynesville and Bakken – with the rationale being that these are the fastest growing plays (Eagle Ford, Bakken, Marcellus) or the ones that have the potential to correct the most in the short term (Haynesville). However, the focus on these plays should not be taken to imply that they are the only plays that matter in the U.S. We have also done detailed models on the Permian Basin and Anadarko Basin plays – aggregated within the respective basins but broken out into horizontal and vertical drilling as well as the Woodford/Cana Woodford and Fayetteville. We present a summary of each of these plays (IP rates in aggregate, by county and by operator, total production, etc.) in Appendix pages 148-186.

As depicted in Exhibit 39, beyond the plays discussed above, aggressive development in the Permian Basin from both aggressive horizontal and vertical drilling has also led to very meaningful increase in oil production increase. Production in the Permian has grown by ~210,000 Bbls/d in 2010 and 2011 and seems to be on track to produce 1.5 MMBbls/d in 2012 (up 340,000 Bbls/d from 2011). The Permian is truly a variety of resource plays plus conventional targets with, in many cases, overlapping geologically making it difficult to separate out rig counts by play, etc. However, in many cases, the type curves aren’t wildly different so we have found it accurate enough to simply break out horizontal Permian vs. vertical Permian activity and build type curves around that. For the Anadarko Basin, we have broken out the Woodford and Cana Woodford separately and modeled all other Anadarko horizontal and vertical activity separately.

Exhibit 39 shows the growth outlook by play for each of the other regions. For more details (IP trends, IP distributions, etc.), please refer to Appendix pages 148-186.


46

Exhibit 39. Growth Outlook

Rigs Running – Anadarko (Horizontal) Production Forecasts – Anadarko (Horizontal)

0

20

40

60

80

100

120

140

160

180

200

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

Rig

s R

unni

ng

HighBaseLow

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

Q2/19E

Q1/20E

Q4/20E

Mm

cfe/

d

0

83

167

250

333

417

500

583

667

Mbo

e/d

Low Base High

Rigs Running – Fayetteville Production Forecasts – Fayetteville

0

5

10

15

20

25

30

35

40

45

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

Rig

s R

unni

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Low Base High

-

500

1,000

1,500

2,000

2,500

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3,500

4,000

4,500

Q1/08

Q4/08

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Q2/10

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Q4/11

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Q2/13E

Q1/14E

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583

667

750

Mbo

e/d

Low Base High

Rigs Running – Permian (Horizontal) Production Forecasts – Permian (Horizontal)

0

10

20

30

40

50

60

70

80

90

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

Rig

s R

unni

ng

HighBaseLow

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

Q2/19E

Q1/20E

Q4/20E

Mm

cfe/

d

0

167

333

500

667

833

1,000

1,167

1,333

1,500

1,667

1,833

Mbo

e/d

Low Base High

Rigs Running – Woodford Production Forecasts – Woodford

0

20

40

60

80

100

120

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

Rig

s R

unni

ng

HighBaseLow

-

250

500

750

1,000

1,250

1,500

1,750

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

Q2/19E

Q1/20E

Q4/20E

Mm

cfe/

d

0

42

83

125

167

208

250

292M

boe/

d

Low Base High



47

Lots Of Activity On Emerging Resource Plays U.S. resource play activity has not stood still. Even with gigantic successes like the Marcellus, Haynesville, Eagle Ford and Bakken, the industry continues to look for “the next big thing”. We highlight four early-stage resource plays but acknowledge that there are others and this list will change continuously. Of all the emerging plays, the Mississippi Lime seems to be the most active with industry now running 89 rigs on the play, up from ~30 in the year prior. As the play is quite new, historical data is sparse making it still difficult to gauge an accurate type curve based on official data so in this case we are more at the mercy of company disclosures. Recent results on the play suggest typical IPs of 200-300 Boe/d, primarily oil weighted. The most active operators targeting the Mississippi Lime are Sandridge (SD-NYSE), Chesapeake and Noble (NBL-NYSE).

The Niobrara and Utica are also seeing meaningful activity with the Niobrara currently running approximately 38 rigs, relatively flat with last year (as the Niobrara overlays gas zones the true rig count targeting the Niobrara is harder to define vs. many other plays so last year’s number likely included some gas oriented rigs). Typical 30-day IPs from the Niobrara are approximately 300 Boe/d but, as with most plays, vary widely. Most active operators in the Niobrara are Encana with nine rigs running, Williams six rigs, Anadarko five rigs, and Noble with four rigs.

The Utica is gaining steam very rapidly with 36 rigs now being run in the area vs. ~5 at this time last year. As the Utica is the youngest of emerging resource plays, there is virtually no verifiable public data so we are reliant on company disclosures, which are suggesting IPs in the 500 Boe/d range. The most active operator in the Utica is Chesapeake with 13 rigs running followed by Gulfport Energy (GPOR-NASDAQ) with two rigs.

The Tuscaloosa Marine Shale is another play that is getting attention, however, it is approximately a year behind other emerging plays in terms of activity levels with only ~four rigs running. However, as seen with both the Utica and Mississippi Lime, if results warrant, we could see a very quick ramp-up in activity. Most active operators in the Tuscaloosa are Encana, Devon, Goodrich and Aldridge all with one rig currently running.

In terms of forecasting production from the emerging resource plays, we have modeled the Mississippian separately but, for the time being, have grouped the other emerging plays together reflecting the greater uncertainty around these plays. As better data is available in terms of verifying type curves/economics, we will gradually split these plays into their own categories. The charts in Exhibits 40 and 41 depict growth potential from the Mississippi Lime and other emerging resource plays based on current rig counts with our typical +-20%, which can be interpreted as a +-20% change in drilling efficiencies or IP rates. We have also presented a scenario that follows the ramp up cycle of other plays in which rig counts continue to expand rapidly and drilling efficiencies (cycle times) improve. As depicted, these emerging resource plays will likely be an important growth driver going forward. Our base case modeling includes approximately 300,000 Boe/d of production (70% oil weighted) from these plays by 2016 and approximately 550,000 Boe/d by 2020. With a more aggressive ramp-up and improvements in cycle times, production could be more in the 700,000 Boe/d range by 2016 and ~1.2 MMBoe/d by 2020.

Even with gigantic successes like the Marcellus, Haynesville, Eagle Ford and Bakken, the industry continues to look for “the next big thing”.

Our base case modeling includes approximately 300,000 Boe/d of production (70% oil weighted) from these emerging plays by 2016 and approximately 550,000 Boe/d by 2020. With a more aggressive ramp-up and improvements in cycle times production could be more in the 700,000 Boe/d range by 2016 and ~1.2 MMBoe/d by 2020.


48

Exhibit 40. Emerging Plays – Growth Outlook

Rigs Running – Mississippi Lime Production Forecasts – Mississippi Lime

0

20

40

60

80

100

120

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

Rig

s R

unni

ng

HighBaseLow

-

250

500

750

1,000

1,250

1,500

1,750

2,000

2,250

2,500

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

Q2/19E

Q1/20E

Q4/20E

Mm

cfe/

d

0

42

83

125

167

208

250

292

333

375

417

Mbo

e/d

High

Base

Low

Rigs Running – Other Emerging Plays Production Forecasts – Other Emerging Plays

0

10

20

30

40

50

60

70

80

90

100

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

Rig

s R

unni

ng

HighBaseLow

-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

Q2/19E

Q1/20E

Q4/20E

Mm

cfe/

d

0

33

67

100

133

167

200

233

267

300

Mbo

e/d

High

Base

Low



49

Exhibit 41. Emerging Plays – Growth Outlook – Improved Efficiencies & Continued Activity Expansion

Rigs Running – Mississippi Lime Production Forecasts – Mississippi Lime

0

50

100

150

200

250

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

Rig

s R

unni

ng

HighBaseLow

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

Q2/19E

Q1/20E

Q4/20E

Mm

cfe/

d

0

83

167

250

333

417

500

583

667

750

833

917

1,000

Mbo

e/d

High

Low

Base

Rigs Running – Other Emerging Plays Production Forecasts – Other Emerging Plays

0

50

100

150

200

250

300

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

Rig

s R

unni

ng

High

Base

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

Q2/19E

Q1/20E

Q4/20E

Mm

cfe/

d

0

83

167

250

333

417

500

583

667

750

833

917

1,000

Mbo

e/d

High

Base



50

Allocating Capital – Comparative Economics As we have seen over the past few years, the industry has demonstrated an ability to shift capital quickly in response to price signals. The rapid pace with which capital can be reallocated from play to play in the U.S. makes it very important to understand the relative economics of various plays in order to get an understanding of where producers will favor oil plays vs. liquids-rich gas plays vs. dry gas plays.

The charts in Exhibit 42 are a useful tool in understanding economic sensitivities and where producers will allocate capital for the main U.S. resource plays. Overall, based on today’s type curve performance, we generally see the Eagle Ford as having some of the best returns regardless of gas price assumption. We see an average Eagle Ford well breaking even at approximately US$50-US$60/Bbl, although if we subdivide this between liquids-rich wells and crude oil wells, there is quite a different story with crude oil wells breaking even closer to US$50/Bbl and liquids-rich wells in the US$70/Bbl range with a US$5/Mcf gas price (assuming NGL basked at 45% of WTI). Unsurprisingly, we also see strong returns from the Bakken but not as high as generally viewed as we forecast approximately a 10% variance in oil prices for PADD 2 and Canadian plays vs. plays producing in PADD 3 (our section on Crude oil explains the rationale). On average, we see break-evens for the Bakken at approximately US$60-US$70/Bbl.

On the natural gas side, the best returns of the dry gas plays comes from the Marcellus where we see typical wells breaking even at approximately US$3/Mcf. Noteworthy is the fact that the Marcellus wet gas wells (primarily in the SW part of the play) break even at US$2/Mcf (with oil at US$95/Bbl and NGL basket priced at 45% of WTI). With this backdrop, we fully expect the Marcellus (wet and dry) to remain one of the primary gas growth drivers. In other dry gas plays like the Haynesville we typically see break-even returns more in the US$4/Mcf range.


51

Exhibit 42. Comparative Returns

Comparative Economics @ $2.00/Mcf Comparative Economics @ $3.00/Mcf



$60$7

0$80$9

0$100$1

10$120

Fayetteville

Marcellus

Haynesville

Barnett

Utica

Eagle Ford - Wet Gas

PermianHzDir

MLWoodford

AnadarkoHzDir

Bakken

Marcellus - Wet Gas

Eagle Ford

Eagle Ford - Crude0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

110%

120%

130%

$60$7

0$80$9

0$100$1

10$120

Fayetteville

Haynesville

Marcellus

Barnett

Utica


PermianHzDir

MLWoodford

AnadarkoHzDir

Bakken

Marcellus - Wet Gas

Eagle Ford


10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

110%

120%

130%

$60$7

0$80$9

0$100$1

10$120

Haynesville

Fayetteville

Barnett

Utica

Marcellus

PermianHzDir


MLWoodford

AnadarkoHzDir

Bakken

Eagle Ford

Marcellus - Wet Gas


10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

110%

120%

130%

$60$7

0$80$9

0$100$1

10$120

Haynesville

Utica

Barnett

Fayetteville

PermianHzDir


MLBakken

Woodford

Marcellus

AnadarkoHzDir

Eagle Ford

Marcellus - Wet Gas


10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

110%

120%

130%

$60$7

0$80$9

0$100$1

10$120

Utica

Haynesville

PermianHzDir

Barnett


MLBakken

Fayetteville

Woodford

AnadarkoHzDir

Marcellus

Eagle Ford

Eagle Ford - Crude

Marcellus - Wet Gas0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

110%

120%

130%

$60$7

0$80$9

0$100$1

10$120

Utica

PermianHzDir

Barnett

Bakken

MLHaynesville


Woodford

AnadarkoHzDir

Fayetteville

Marcellus

Eagle Ford

Eagle Ford - Crude

Marcellus - Wet Gas0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

110%

120%

130%



52

Natural gas prices being above break-even levels on dry gas plays alone will not dictate a return to dry gas drilling. Rather, the real relevant factor is whether or not gas plays can generate a high enough rate of return to draw resources away from liquids-rich or tight oil-focused plays. The following chart depicts some of the swing dry gas plays and how they compete for capital vs. the Eagle Ford and Bakken – two of the largest oil/liquids-focused plays. As depicted, gas prices generally need to be in the US$4-US$6/Mcf range for dry gas plays to compete vs. the main liquids plays. We note our return assumptions for the Bakken are generally slightly lower than consensus reflecting our view of discounting for PADD 2 and Northern plays. This analysis reinforces our view that rigs will be slow to return to dry gas plays unless we see a substantial uptick in gas prices. The one exception being the Marcellus where we are approaching a range where it competes with some oil weighted plays like the Bakken (but is still a long ways from Eagle Ford returns).

Exhibit 43. Dry Gas Returns Vs. Main Oil Plays At US$90/Bbl Oil

-50%

-30%

-10%

10%

30%

50%

70%

90%

110%

$2.00 $3.00 $4.00 $5.00 $6.00 $7.00

$/Mcf

IRR

- %

Fayetteville Haynesville Marcellus Woodford Barnett Bakken Eagle Ford


Where To From Here – U.S. Resource Play Growth Forecasts There is no doubt that U.S. resource plays can deliver quite amazing growth. The question is what does that growth profile look like longer term? We have provided a number of different approaches to evaluating the long-term outlook for U.S. resource plays. Our scenario analysis begins with a look at deliverability using status quo assumptions (current rigs running and no changes to IP rates or drilling cycle times). Scenario 2 incorporates changes in the rig fleet and activity levels as well as cycle times. Scenario 3, which is the most complex, introduces variability and dynamic capital allocation using a Monte Carlo simulation. This approach is particularly powerful as it provides some insight into how, and when, producers allocate capital to natural gas plays vs. the current oil focus.

Natural gas prices generally need to be in the US$4-US$6/Mcf range for dry gas plays to compete vs. the main liquids plays.


53

Scenario 1 – Growth & Current Rig Counts Our first approach to forecasting overall industry growth is to assume a continuation of current rig counts and productivity assumptions on each of the individual plays. The following charts provide an overview of recent trends in U.S. rig counts along with the current break-out of rig counts by play.

Exhibit 44. Current U.S. Rig Counts

Rig Count Ramp Up - By Play Rig Count - By Play - Q4/20

0

250

500

750

1,000

1,250

1,500

1,750

2,000

2,250

Q1/08

Q3/08

Q1/09

Q3/09

Q1/10

Q3/10

Q1/11

Q3/11

Q1/12

Q3/12

Q1/13

Q3/13

Q1/14

Q3/14

Q1/15

Q3/15

Q1/16

Q3/16

Q1/17

Q3/17

Q1/18

Q3/18

Q1/19

Q3/19

Q1/20

Q3/20

Eagleford Marcellus PA

Haynesville Fayetteville

Barnett Woodford

Emerging Liquids Plays US Bakken

Mississippi Lime Permian

Anadarko Basin

Eagleford Marcellus PAHaynesville FayettevilleBarnett WoodfordEmerging Liquids Plays US BakkenMississippi Lime PermianAnadarko Basin


As depicted, in this scenario, we see oil production from resource plays growing by 2.9 MMBbls/d from 2011 to 2016 (~600,000 Bbls/d per year) and a further 1.1 MMBbls/d from 2016 to 2020 (~270,000 Bbls/d per year). After netting off anticipated declines in non-resource play production, total U.S. on-shore oil production would be grow to ~6.6 MMBbls/d in 2016 (~485,000 bbl/d per year) and 7.2 MMBbls/d by 2020 (an incremental 152,000 Bbls/d per year from 2016-2020).

Exhibit 45. U.S. Oil Production Growth – Key Resource Plays

Oil Production (Bbls/d) Oil Production - YoY Chng By Play (Bbls/d)

-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

4,500,000

5,000,000

5,500,000

6,000,000

6,500,000

7,000,000

7,500,000

8,000,000

Q1/08

Q3/08

Q1/09

Q3/09

Q1/10

Q3/10

Q1/11

Q3/11

Q1/12

Q3/12

Q1/13

Q3/13

Q1/14

Q3/14

Q1/15

Q3/15

Q1/16

Q3/16

Q1/17

Q3/17

Q1/18

Q3/18

Q1/19

Q3/19

Q1/20

Q3/20



Barnett Woodford



Anadarko Basin Low

High

-100,000

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

1,000,000

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



Barnett Woodford



Anadarko Basin


With current rig counts & efficiencies, total U.S. on-shore oil production would grow to ~6.6 MMBbls/d in 2016 (~485,000 bbl/d per year).


54

Exhibit 46. Oil Scenario Summary

Oil Ramp Up - (Bbl/d) 2011 2016 2020 '11-'16 '16-'20 '11-'20

Low Case 1,937,841 4,255,899 5,049,138 463,612 198,310 345,700Base Case 1,937,841 4,939,280 6,007,644 600,288 267,091 452,200High Case 1,937,841 5,627,452 6,974,215 737,922 336,691 559,597

Non Shale Production Decline 2,239,159 1,658,504 1,200,421 (116,131) (114,521) (115,415)

Total On-Shore USLow Case 4,177,000 5,914,403 6,249,559 347,481 83,789 230,284Base Case 4,177,000 6,597,784 7,208,065 484,157 152,570 336,785High Case 4,177,000 7,285,956 8,174,636 621,791 222,170 444,182

Total Production Per Year Growth


With this scenario’s big allocation of rigs towards liquids plays, there is no surprise that gas production growth decelerates massively from prior year’s. In this scenario, we expect dry gas production to be flat in 2013 as a decline in Haynesville production moderates increases from the Marcellus and gas from liquids-rich plays. As steep initial declines moderate though in the 2014 time frame, production from dry gas plays such as the Haynesville will likely return to moderate growth at current rig counts. At static rig counts, U.S. wet gas production from resource plays would grow 8.4 Bcf/d (1.7 Bcf/d per year) from 2011 to 2016 and 5.5 Bcf/d from 2016 to 2020 (1.4 Bcf/d per year). Production from non-resource plays would likely continue to decline approximately 4.4 Bcf/d (0.9 Bcf/d per year) by 2016 and extraction losses due to NGL would increase approximately 1.4 Bcf/d (0.3 Bcf/d per year) implying total dry gas production growth of 2.6 Bcf/d (0.5 Bcf/d per year) through 2016 and 0.4 Bcf/d per year through 2020.

Exhibit 47. U.S. Gas Production Growth

Natural Gas Production (MMcf/d) Natural Gas Production - YoY Chng By Play (MMcf/d)

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

55,000

60,000

Q1/08

Q3/08

Q1/09

Q3/09

Q1/10

Q3/10

Q1/11

Q3/11

Q1/12

Q3/12

Q1/13

Q3/13

Q1/14

Q3/14

Q1/15

Q3/15

Q1/16

Q3/16

Q1/17

Q3/17

Q1/18

Q3/18

Q1/19

Q3/19

Q1/20

Q3/20

Eagleford Marcellus PA Haynesville

Fayetteville Barnett Woodford

Emerging Liquids Plays US Bakken Mississippi Lime

Permian Anadarko Basin Low

High

-5,000

-3,750

-2,500

-1,250

0

1,250

2,500

3,750

5,000

6,250

7,500

8,750

10,000

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



Barnett Woodford



Anadarko Basin


Exhibit 48. Gas Scenario Summary

Gas Ramp Up - (Mmcf/d) 2011 2016 2020 '11-'16 '16-'20 '11-'20Low Case 31,775 35,113 38,530 667 854 750Base Case 31,775 40,258 45,759 1,696 1,375 1,554High Case 31,775 45,606 53,263 2,766 1,914 2,388

Non Shale Production Decline 34,429 29,802 26,420 (925) (845) (890)

Extraction Losses 3,203 4,466 4,601 253 34 155

Total On-Shore USLow Case 63,002 60,448 60,348 (511) (25) (295)Base Case 63,002 65,593 67,578 518 496 508High Case 63,002 70,941 75,082 1,588 1,035 1,342



At current rig counts and efficiencies, dry gas production would only grow ~2.5 Bcf/d by 2016 or about 0.5 Bcf/d per year – not sufficient to keep pace with demand growth.


55

In the above scenarios, we have included a sensitivity of +-20%, which can be thought of as improvements in initial productivity rates and/or rig efficiency. If we saw some combination of 20% improvements in initial productivity rates or rig efficiency, U.S. tight oil production could grow to 5.6 MMBbls/d by 2016 or 740,000 Bbls/d per year instead of ~5 MMBbls/d or 600,000 Bbls/d as in our base case. On the downside, a decrease in IP rates and productivity (seemingly unlikely) would still see U.S. tight oil production grow to 4.3 MMBbls/d by 2016 or 460,000 Bbls/d per year – still above pre-2011 grow rates.

Scenario 2 – Impact Of Emerging Plays, Long-term Fleet Expansion & Efficiency Gains This scenario expands on the “base case” output from Scenario 1 (which is labeled Scenario A in the following tables) by incorporating different assumptions around rig counts and cycle times. Scenario B begins by taking all the assumptions laid out in Scenario A, but assumes that emerging plays such as the Utica, Niobrara and Tuscaloosa continue to ramp up activity. We assume that these plays collectively ramp up from ~100 rigs today to ~300 rigs by end of 2014. Ramp-up times in new plays have been steadily decreasing as the industry gains experience and confidence in building out new resource plays and implementing the necessary supply chains to support them.

As shown in Exhibit 51, Scenario C builds on B and also assumes gradual decreases in cycle times on the remaining plays, most notably the U.S. Bakken and Eagle Ford where we continue to measure cycle times in the 60- and 80-day range, which could theoretically be reduced by ~33%. Scenario D takes the previous two scenarios and also assumes the rig fleet continues to expand by ~5% per year from 2014 to 2020 – a reasonable assumption given producer production would be growing in excess of 5% per year.

Exhibit 49. Eagle Ford & Bakken Calculated Cycle Times

Eagle Ford Cycle Times (Days) Bakken Cycle Times (Days)

0

20

40

60

80

100

120

140

160

180

200

0

20

40

60

80

100

120

140

160

180

200



56

As depicted, with these scenarios, we see a very wide range of outputs, which reflects the many moving parts in this type of exercise. In Scenario B, we would see oil production from resource plays increase ~670,000 Bbl/d per year from 2011-2016 (vs. ~600,000 Bbls/d per year from 2011 to 2016 under Scenario A). Scenario C, which adds in gradual cycle time improvements would see resource play growth jump to 758,000 Bbl/d per year from 2011-2016 and Scenario D, which incorporates long-term growth in the US rig fleet could deliver oil growth of 832,000 Bbl/d per year through 2016.

From 2016-2020, oil production from resource plays would increase anywhere from 320,000 Bbls/d to 865,000 Bbls/d per year. The main cause for the wide variance in the 2016-2020 forecasts is whether or not one assumes that the U.S. rig fleet continuously expands. If no expansion is assumed, then the current rig fleet is spread over a larger production base and not able to deliver as much growth (although even the lower end numbers are still quite impressive) whereas if the assumption is made that the U.S. rig fleet gradually expands in line with industry production and cash flows (a reasonable assumption), the higher growth rates can be sustained for longer.

Exhibit 50. Oil Resource Play Growth

Oil Production (Bbls/d) Oil Production - YoY Chng By Play (Bbls/d)

-

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

7,000,000

8,000,000

9,000,000

10,000,000

11,000,000

Q1/08

Q3/08

Q1/09

Q3/09

Q1/10

Q3/10

Q1/11

Q3/11

Q1/12

Q3/12E

Q1/13E

Q3/13E

Q1/14E

Q3/14E

Q1/15E

Q3/15E

Q1/16E

Q3/16E

Q1/17E

Q3/17E

Q1/18E

Q3/18E

Q1/19E

Q3/19E

Q1/20E

Q3/20E

Anadarko BasinPermianMississippi LimeUS BakkenEmerging Liquids Rich PlaysWoodfordBarnettFayettevilleHaynesvilleMarcellus PAEaglefordHigh CaseLow Case

-100,000

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

1,000,000

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

Anadarko BasinPermianMississippi LimeUS BakkenEmerging Liquids Rich PlaysWoodfordBarnettFayettevilleHaynesvilleMarcellus PAEagleford


The following table depicts overall onshore U.S. oil production after taking into account continued declines in other U.S. oil production. As depicted, after deducting declines from other production, we could see U.S. onshore production grow at a rate ranging from 557,000 Bbls/d to ~720,000 Bbls/d per year from 2011-2016 (2.8 MMBbls/d growth to 3.6 MMBbls/d growth). Growth in the 2016-2020 time frame slows in Scenario A, B & C as it largely reflects a static rig fleet on a significantly larger production base (lower ability to grow). In these scenarios, onshore growth would still average 85,000-285,000 Bbls/d per year. Scenario D, which assumes the U.S. rig fleet continues to expand at 5%/year beyond 2015, would be able to sustain growth in the 750,000 Bbls/d per year range.

Incorporating rig fleet expansion, improved cycle times etc would see US resource play oil growth in the 670,000-832,000 Bbl/d per year range through 2016 (556,000-717,000 Bbl/d per year after deducting non-resource play declines).


57

Exhibit 51. Oil Growth Scenarios

Total Production (bbl/d) Per Year Growth (bbl/d)Oil Production From Resource Plays (Bbl/d) 2011 2016 2020 '11-'16 '16-'20 '11-'20A) Scenario 1 Base Case Results 1,937,841 4,939,280 6,007,644 600,288 267,091 452,200B) A + Ramp Up In New Plays 1,937,841 5,303,505 6,578,417 673,133 318,728 515,620C) B + Efficiency Gains 1,937,841 5,729,262 7,322,741 758,284 398,370 598,322D) C + Rig Fleet Growth 1,937,841 6,103,513 9,571,809 833,134 867,074 848,219

Non Resource Play Oil Production 2,239,159 1,658,504 1,200,421 (116,131) (114,521) (115,415)

Total On Shore Oil ProductionScenario A (Same as Scenario 1 Base Case in previous example) 4,177,000 6,597,784 7,208,065 484,157 152,570 336,785Scenario B 4,177,000 6,962,009 7,778,838 557,002 204,207 400,204Scenario C 4,177,000 7,387,765 8,523,162 642,153 283,849 482,907Scenario D 4,177,000 7,762,017 10,772,230 717,003 752,553 732,803


As emerging plays have meaningful amounts of associated gas or are liquids-rich in nature, the acceleration in rig count on these plays does impact natural gas growth, albeit not to the same extent as oil. In Scenarios A,B, & C, we see U.S. gas production from resource plays increasing ~1.7-2.5 Bcf/d per year through 2016 with rates slowing to a range of 0.5-1.3 Bcf/d per year from 2016-2020. Scenario D, which assumes expansion of the rig fleet, would see gas production accelerate significantly to 2.3 Bcf/d on average in the 2011-2016 time frame and 4.8 Bcf/d per year from 2016-2020. After layering in declines in non-resource play production and NGL extraction losses, dry gas growth rates drop to only 0.5-1.4 Bcf/d per year from 2011-2016 in Scenarios A-C and 2 Bcf/d per year in Scenario D.

Exhibit 52. Gas Resource Play Growth

Natural Gas Production (MMcf/d) Natural Gas Production - YoY Chng By Play (MMcf/d)

-

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

Q1/08

Q3/08

Q1/09

Q3/09

Q1/10

Q3/10

Q1/11

Q3/11

Q1/12

Q3/12E

Q1/13E

Q3/13E

Q1/14E

Q3/14E

Q1/15E

Q3/15E

Q1/16E

Q3/16E

Q1/17E

Q3/17E

Q1/18E

Q3/18E

Q1/19E

Q3/19E

Q1/20E

Q3/20E

Anadarko BasinPermianMississippi LimeUS BakkenEmerging Liquids Rich PlaysWoodfordBarnettFayettevilleHaynesvilleMarcellus PAEaglefordHigh CaseLow Case

-5,000

-2,500

0

2,500

5,000

7,500

10,000

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

Anadarko BasinPermianMississippi LimeUS BakkenEmerging Liquids Rich PlaysWoodfordBarnettFayettevilleHaynesvilleMarcellus PAEagleford


Dry gas growth rates drop to only 0.5-1.4 Bcf/d per year from 2011-2016 in Scenarios A-C and 2 Bcf/d per year in Scenario D.


58

Exhibit 53. Gas Growth Scenarios

Gas Production From Resource Plays (Mmcf/d) 2011 2016 2020 '11-'16 '16-'20 '11-'20A) Scenario 1 Base Case Results 31,775 40,258 45,759 1,696 1,375 1,554B) A + Ramp Up In New Plays 31,775 42,628 49,440 2,171 1,703 1,963C) B + Efficiency Gains 31,775 44,662 53,201 2,577 2,135 2,381D) C + Rig Fleet Growth 31,775 47,689 70,361 3,183 5,668 4,287

Non Resource Play Gas Production 34,429 29,802 26,420 (925) (845) (890)

Total Wet Gas ProductionScenario A (Same as Scenario 1 Base Case in previous example) 66,204 70,060 72,179 771 530 664Scenario B 66,204 72,430 75,860 1,245 858 1,073Scenario C 66,204 74,464 79,621 1,652 1,289 1,491Scenario D 66,204 77,491 96,781 2,257 4,822 3,397


Total US Dry Gas ProductionScenario A (Same as Scenario 1 Base Case in previous example) 63,002 65,593 67,578 518 496 508Scenario B 63,002 67,964 71,259 992 824 917Scenario C 63,002 69,998 75,019 1,399 1,255 1,335Scenario D 63,002 73,025 92,180 2,005 4,789 3,242


Scenario 3 – Introducing Volatility & Pricing Impact With Monte Carlo Simulation The main shortfall of most industry growth forecasts (and the aforementioned examples) is that it ignores the impact of volatility and unpredictability/uncertainty and ignores the dynamic reallocation of rigs according to price signals (i.e., producers reallocating rigs to gas plays if gas prices rise sufficiently to make economics competitive with liquids-rich or tight oil). As an example, as recently as three years ago, the consensus view was that natural gas prices will be in the US$8/Mcf long term and that the U.S. would be short natural gas. Clearly that proved wrong. At least once a year for the past five years there has been some major political uncertainty leading to spikes in oil prices. None of these types of things can be captured by typical linear type forecasts. Additionally, most forecasts suffer immensely from adaptive expectations (i.e., where forecasters are overly influenced by today’s environment in making long-term projections). To provide a different perspective, we have built a fairly sophisticated simulation tool that introduces a degree of randomness, volatility and then inter-relationship of rig allocation to changes in relative economics.

Methodology & Background The Monte Carlo method is very suitable to this type of exercise and is the core of our simulation model. (The definition of Monte Carlo simulation is: “A problem solving technique used to approximate the probability of certain outcomes by running multiple trial runs, called simulations, using random variables”). We use the Monte Carlo method to generate independent prices for oil and natural gas. The importance of introducing volatility is significant as companies allocate capital according to the environment (with some lag typically). For instance, if prices decline significantly and producers cut capex and rig counts followed by a rebound and rise in prices and capex, production will still not make it back to the same level as would be achieved with a linear projection due to the impact of decline rates.

Our Monte Carlo simulation introduces the impact of price volatility and the dynamic reallocation of capital (gas vs. oil drilling) according to price signals.


59

Once both the oil and natural gas prices are determined for a period, we then apply a historical correlation of oil rigs vs. oil prices and gas rigs vs. gas prices to determine the overall rig count operating in the specific price scenario.

Once the rig count has been determined from the Monte Carlo price simulation, the complexity is how to allocate rigs across different plays? For this we use the economic analysis discussed in the company sections to allocate rigs within certain constraints. For instance, in a scenario where the simulation generates an oil price of US$95/Bbl in a given quarter and a natural gas price of US$2/Mcf, the model would rank the plays according to the IRR generated at that price deck and allocate rigs accordingly. In the scenario of high oil and low gas prices, the model would clearly see a heavy allocation of rigs to oil plays and low allocation to gas plays. If we saw a scenario of US$85/Bbl oil and US$5/Mcf gas, our model would begin to move rigs out of more marginal oil plays into gas plays. To better simulate real world conditions, we assume that no play can handle more than 20% of total U.S. rigs (today that would be approximately 300 rigs – and for context the Eagle Ford and Bakken seem to be peaking in the 275 and 240 range, respectively). We also assume that rigs are not perfectly mobile and only react to price signals if conditions have persisted for more than one quarter.

Key inputs into the Monte Carlo analysis are the long-term direction of oil prices and the volatility around those prices. We have run three different baseline scenarios using flat prices of US$75, US$85 and US$95/Bbl along with gas price of US$3/Mcf, US$4/Mcf and US$5/Mcf. Volatility is also a key variable in the Monte Carlo simulation and for this we have used 35% volatility for natural gas and 28% for crude oil, both based on the implied volatility in the futures curve for both commodities.

Monte Carlo Simulation Results The results of our 500 iteration Monte Carlo simulation are provided below. As depicted, the growth outcomes of oil vs. natural gas depend on the pricing dynamic between both commodities. Under the CIBC price forecast of ~US$85/Bbl WTI average through 2016 and average gas prices of approximately US$4/Mcf, we would expect U.S. oil resource play production to increase approximately 540,000 Bbls/d per year through 2016 and gas production from resource plays to increase approximately 2.7 Bcf/d per year. Under the futures curve, which currently stands at ~US$90/Bbl and US$4/Mcf through 2016, oil resource play growth would average 560,000 Bbls/d per year and wet gas production ~2.7 Bcf/d per year. After deducting non-resource play declines and processing losses on gas, the overall growth rate would be ~424,000 Bbls/d per year growth in oil production and ~1.5 Bcf/d per year for dry gas through 2016.

Exhibit 54. Monte Carlo Simulation Outputs

Oil (Bbls/d)2011-2016 75.00$ 85.00$ 95.00$ 2016-2020 75.00$ 85.00$ 95.00$ 2011-2020 75.00$ 85.00$ 95.00$

3.00$ 483,661 548,899 597,370 3.00$ 301,780 330,804 322,387 3.00$ 352,765 401,908 425,0964.00$ 474,812 540,496 586,963 4.00$ 304,411 335,283 328,741 4.00$ 349,019 399,231 422,1385.00$ 456,466 507,979 521,613 5.00$ 311,870 303,705 338,819 5.00$ 342,142 367,131 390,311

Gas (mmcf/d)2011-2016 75.00$ 85.00$ 95.00$ 2016-2020 75.00$ 85.00$ 95.00$ 2011-2020 75.00$ 85.00$ 95.00$

3.00$ 1,287 1,624 1,780 3.00$ 2,110 2,301 2,225 3.00$ 1,174 1,446 1,4984.00$ 2,392 2,691 2,818 4.00$ 1,935 2,200 2,215 4.00$ 1,710 1,994 2,0715.00$ 3,940 4,181 4,271 5.00$ 2,458 2,481 2,753 5.00$ 2,802 2,946 3,117


At US$85/Bbl WTI average through 2016 and US$4/Mcf, we would expect U.S. oil resource play production to increase approximately 540,000 Bbls/d per year through 2016 and gas production from resource plays to increase approximately 2.7 Bcf/d per year.


60

As with the growth scenarios discussed in the previous sections, the Eagle Ford remains a dominant driver for both oil and natural gas growth and the Marcellus for natural gas. The one interesting observation is that the Bakken figures as a less prominent growth driver in this simulation, which uses economic returns to allocate rig activity. The key reason for this is our assumption that WTI remains ~US$5/Bbl discounted vs. PADD 3 plays with Bakken realizing approximately 95% of WTI reflecting transportation challenges. This lower price assumption has a significant impact on relative economics. From a macro forecasting perspective, the overall impact is relatively negligible as it implies that if activity slows in the Bakken due to weaker relative economics, we will see those rigs absorbed by other emerging resource plays in PADD 3 such as the various Permian and Anadarko plays (i.e., if Bakken oil growth forecasts decline, higher growth in other oil plays offsets leaving overall oil projections unchanged).

Exhibit 55. Growth Drivers By Play Through 2016 In Monte Carlo Simulation #1

Contribution to 2012 - 2016 Average Y/Y Gas Growth By Play (mmcf/d) Contribution to 2012 - 2016 Average Y/Y Oil Growth By Play (Bbls/d)

Note: Note:- Average Y/Y Haynesville production declines (32)mmcf/d during the given time period. - Average Y/Y Haynesville production declines (181)bbls/d during the given time period.- Average Y/Y Woodford production declines (97)mmcf/d during the given time period.- Average Y/Y Permian/Anadarko production declines (159)mmcf/d during the given time period.

Marcellus PA1,202

Mississippi Lime186

Barnett 77

Eagleford534

Fayetteville 9

US Bakken61

Emerging Liquids Plays 47

Eagleford158,745

Mississippi Lime38,917

Permian / Anadarko 167,379

US Bakken63,232

Marcellus PA 323

Woodford 1,768Emerging Liquids Plays

8,070

Barnett 12,136


A key benefit of the Monte Carlo approach is to assess probabilities around a range of outcomes. The following charts depict the distribution of growth forecast outcomes from our 500 iteration Monte Carlo approach (based only on the US$85/Bbl and US$4/Mcf scenario. As depicted, high commodity price volatility and the ability to move rigs between plays as economics warrant leads to a wide degree of forecast variability for both oil and natural gas (wider for natural gas primarily reflecting the higher implied volatility in the commodity.


61

Exhibit 56. Frequency Distribution Of Monte Carlo Simulation

Q1/12 - Q4/16 Q1/12 - Q4/16GAS OIL

0

10

20

30

40

50

60

> 12,2

00

12,20

0 - 11

,400

11,40

0 - 10

,600

10,60

0 - 9,

800

9,800

- 9,00

0

9,000

- 8,20

0

8,200

- 7,40

0

7,400

- 6,60

0

6,600

- 5,80

0

5,800

- 5,00

0

5,000

- 4,20

0

4,200

- 3,40

0

3,400

- 2,60

0

2,600

- 1,80

0

1,800

- 1,00

0

1,000

- 200

200 -

(600

)

(600)

- (1,40

0)

(1,40

0) - (2

,200)

< (3,00

0)

Average Aggregate Change YoY (Mmcf/d)

Freq

uenc

y

0

5

10

15

20

25

30

35

40

45

> 868

,150

868,1

50 - 8

26,30

0

826,3

00 - 7

84,45

0

784,4

50 - 7

42,60

0

742,6

00 - 7

00,75

0

700,7

50 - 6

58,90

0

658,9

00 - 6

17,05

0

617,0

50 - 5

75,20

0

575,2

00 - 5

33,35

0

533,3

50 - 4

91,50

0

491,5

00 - 4

49,65

0

449,6

50 - 4

07,80

0

407,8

00 - 3

65,95

0

365,9

50 - 3

24,10

0

324,1

00 - 2

82,25

0

282,2

50 - 2

40,40

0

240,4

00 - 1

98,55

0

198,5

50 - 1

56,70

0

156,7

00 - 1

14,85

0

< 73,0

00

Average Aggregate Change YoY (Bbls/d)

Freq

uenc

y


Monte Carlo Simulation With Efficiency Gains As we highlighted in the previous section, it still appears that several key U.S. growth plays have plenty of room to improve efficiencies (the time to drill, complete and tie-in a well as calculated from spud date to first production date). The following table highlights the impact on the previous production scenarios but also incorporates approximately 15% improvements in well cycle times across the major resource plays. As we highlighted previously, we believe this is a very achievable target given that we calculate key plays such as the Eagle Ford and Bakken having average cycle times of approximately 60-80 days vs. optimal target ranges in the 40 day range. Overall, adding in 15% efficiency gains adds approximately 94,000 Bbls/d per and 0.6 MMcf/d per year growth to our forecasts. In this scenario, we would see average U.S. oil resource play growth of 644,000 Bbls/d per year from 2011-2016 and natural gas growth of 3.3 Bcf/d from 2011-2016 using CIBC forecast prices and approximately 675,000 Bbls/d per year and 3.4 MMcf/d per year using current strip prices through 2016.

Exhibit 57. Monte Carlo Simulation Outputs With Efficiency Gains

Oil (Bbls/d)2011-2016 75.00$ 85.00$ 95.00$ 2016-2020 75.00$ 85.00$ 95.00$ 2011-2020 75.00$ 85.00$ 95.00$

3.00$ 571,037 644,641 699,181 3.00$ 388,648 424,845 416,317 3.00$ 439,916 496,895 523,4044.00$ 561,462 635,861 688,118 4.00$ 391,399 429,387 423,908 4.00$ 435,819 494,035 520,6325.00$ 541,121 615,053 666,512 5.00$ 399,877 433,269 425,536 5.00$ 428,287 484,201 509,352

Gas (mmcf/d)2011-2016 75.00$ 85.00$ 95.00$ 2016-2020 75.00$ 85.00$ 95.00$ 2011-2020 75.00$ 85.00$ 95.00$

3.00$ 1,815 2,187 2,368 3.00$ 2,645 2,866 2,790 3.00$ 1,705 2,010 2,0764.00$ 2,980 3,314 3,459 4.00$ 2,459 2,770 2,790 4.00$ 2,269 2,593 2,6825.00$ 4,615 4,984 5,133 5.00$ 3,029 3,371 3,352 5.00$ 3,431 3,788 3,863



62

Key Takeaways U.S. Onshore Oil Production Can Grow 500,000-700,000 Bbls/d Per Year Through 2016: We have conducted a number of scenarios ranging from status quo drilling (current rig counts held flat) to a very detailed Monte Carlo simulation. While the results vary considerably by scenario, the general takeaway is that U.S. onshore oil growth is capable of big growth for a long period of time. Our lowest growth scenario (current rig counts with a 20% reduction in IPs) would yield oil resource play growth of 460,000 Bbls/d per year, which after deducting declines on non-resource play production, would yield onshore U.S. growth of 350,000 Bbls/d per year through 2016. Our highest growth scenario, which incorporates moderate rig fleet expansion and cycle time improvements, would yield resource play growth of 830,000 Bbls/d per year through 2016. After deducting non-resource play declines this would leave onshore production growth in the 700,000 Bbls/d per year range through 2016. Our base case view is U.S. resource play production growing in the 650,000 Bbls/d per year range yielding annual growth of approximately 530,000 Bbls/d per year through 2016. We note that these outcomes reflect liquids only from the well head; we expect NGL production from gas plants to also grow ~200,000 Bbls/d per year through 2016.

Forecasts beyond 2016 start to involve an even greater level of uncertainty but generally speaking our scenario analysis yields growth ranges from 267,000 Bbls/d per year from 2016 to 2020 (assuming today’s rig count simply held flat) to 867,000 Bbls/d if we continue to model gradual improvements in cycle times and rig fleet expansion in line with U.S. production growth rates. By this point, declines in non-resource play production will likely be in the 115,000 Bbls/d per year range (lower decline rates on a smaller base) bringing the 2016-2020 onshore U.S. oil growth rate to 152,000-750,000 Bbls/d per year (and an average of 336,000-730,000 Bbls/d per year from 2011-2020). See Exhibit 51 for a full breakdown.

Permian, Eagle Ford & Bakken Remain The Growth Drivers Much of the growth to date has been due to big growth out of the Permian plays (horizontal and vertical development) as well as the Bakken and more recently the Eagle Ford – and we expect this to continue for the foreseeable future although increasingly contributions from other emerging plays (Mississippi Lime and many others) will play a role. With Bakken pricing discounts vs. WTI remaining relatively high, we view Bakken returns as reasonable but meaningfully disadvantaged vs. many of the emerging PADD 3 plays. This ultimately could mean that rigs migrate from the Bakken to PADD 3 plays thereby lowering Bakken growth forecasts – potentially quite meaningfully. However, from a macro perspective, any rigs freed up will likely just migrate to other oil plays with reasonably similar deliverability (some potentially better) which would leave overall oil growth forecasts still within our identified ranges.

Gas Is Not Sustainable At Current Rig Counts Our current rig count scenario clearly depicts how unsustainable the current gas rig count is. At current levels we see U.S. shale production largely holding flat in 2013 (after growing at a rate of 4-6 Bcf/d per year for the past three years). Flat resource play production, combined with an expected decline of approximately 1 Bcf/d in non-shale production, implies a significantly different macro environment for natural gas than we have seen anytime in the past four years.

At current rig counts, we see production from gas resource plays growing only 1.7 Bcf/d per year through 2016, a stark contrast to the 4-6 Bcf/d per year growth seen from 2009-2012. Layering in anticipated declines of ~0.8 Bcf/d per


63

year from non-resource play production along with anticipated extraction losses for increasing NGL output, leaves U.S. dry gas production relatively flat with current levels. To believe this outcome is sustainable assumes no growth in demand – which we do not believe is realistic.

At What Price Do Rigs Move Back To Dry Gas? On average, we expect natural gas demand growth to average 0.5-1.5 Bcf/d per year through 2016 and 1.5-2.5 Bcf/d per year post 2016 as we incorporate LNG exports. For supply to meet projected demand growth through 2016, we need to see gas prices signals strong enough to attract another ~100 rigs back towards natural dry gas drilling or see another ~150 rigs allocated towards liquids-rich drilling. For either of these scenarios to unfold, substantially higher natural gas prices are required to pull rigs away from tight oil drilling. This conclusion arises from two considerations: 1) most dry natural gas plays do not compete with the big tight oil plays (with oil in a US$85/Bbl range) until gas is in the ~US$5/Mcf range; and 2) most gas-weighted producers need prices in the US$4-US$5/Mcf range to have sufficient cash flow to drill sufficient gas wells.

Gas Growth Split Between Liquid-rich, Associated Gas And Marcellus There are many factors at play in long-term gas forecasts. If we model on the basis of current rig counts, we see production from the dry gas plays pretty flat as big declines in the Haynesville are offset by continued gains from the Marcellus. The Eagle Ford will continue to deliver big growth in gas volumes both from associated gas in the crude oil window and liquids-rich gas in the transition window. On average, we expect to see gas production from the Eagle Ford grow ~0.8 Bcf/d per year through 2016. Associated gas production from the Bakken and Permian plays will average ~0.4 Bcf/d per year through 2016.

Sensitivity Of Growth Expectations To Price There is always an inherent and somewhat circular reference in macro growth forecasts as price impacts pace of activity and pace of activity impacts price – and there is no escaping this reality. Our forecasts for U.S. and Canadian production growth assume a domestic oil and natural gas price and what amount of rigs can be operated within those pricing constraints. Based on the historical relationship between oil prices and oil rigs and gas prices and gas rigs, at the current forward curve of ~US$90/Bbl and US$3.70/Mcf for 2013, statistically we would expect a rig count of ~1,714 rigs – within 10% of the current actual rig count and right in line with average rig counts seen in 2011. A 10% swing in commodity prices in either direction would impact our rig count forecasts by ~11%.

Efficiency Gains Could Still Be Meaningful With the rapid expansion in drilling on plays like the Eagle Ford, where the rig count has moved from nil to ~270 rigs in the course of three years, our analysis of cycle times still indicates we are a long ways from optimal levels. In the Eagle Ford, we calculate that average cycle times are still generally in the 60-day range, far below the optimal 40-day range. We see similar results out of the Bakken where measured cycle times are in the 80-day range vs. optimal expected ranges of 40 days. We believe the biggest challenge is for emerging drillers to adequately build out supply chains, secure takeaway capacity and move to full pad drilling. However, these issues will be rectified over time and further reductions in cycle times can mean a big impact on growth forecasts. For instance, in our scenario where we modeled improvements in cycle times, our growth forecast for oil production increased ~200,000 Bbls/d per year through the 2016 time frame.


64

Industry Can’t Support Gas Boom AND Oil Boom At Same Time What has become abundantly clear through this report is that the U.S. industry has been running at quite close to full utilization over the past 12 months. Within this full utilization, there has been a clear shift from gas to oil. However, what this also implies is that there is no way the industry can either fund or logistically support a boom in natural gas and oil drilling simultaneously – when services are running at near full utilization, rigs will be allocated on the basis of returns and strategic value (primarily land retention).

Liquids Lands; 25,000-40,000 Wells Needed To Hold New Oil Lands – Leaving Little Flexibility To Move Rigs A key factor that has exacerbated the natural gas price weakness over the past few years is the need for producers to drill wells to hold shale gas lands. This need prodded companies to drill wells that, in many cases, made no economic sense but had to be done to secure future opportunities. Fortunately, after three years of pain, we believe the land retention driven programs on most of the key dry gas-focused plays such as the Haynesville and Marcellus have largely been met by industry.

A common view is that there is no upside in natural gas. This view supposes that as soon as natural gas prices rise, industry will react by locking in higher prices and quickly ramp up drilling, immediately re-exacerbating the supply problem. We have generally agreed with this view in the past, however, there are two new developments that could impact this thesis and make natural gas prices rebound to the US$5-US$6/Mcf range sustainably. These factors are: 1) the need for the new “liquids-focused” players to drill to meet land commitments on liquids plays; and 2) the fact that even at US$5/Mcf, most dry gas plays do not compete with the many of the newer liquids plays.

The need for producers to maintain active levels in liquids plays, regardless of price, should not be underestimated. Producers have moved VERY aggressively over the past 18 months to lock up positions on oil or liquids-rich resource plays, many of which have the same short land tenure that the dry gas plays had. Based on our analysis of just the Bakken, Eagle Ford, Niobrara, Utica and Mississippi Lime, producers have locked up over 17 million acres (26,000 sections) of land. Using an assumption of 1.0-1.5 wells to hold a section of land, implies the need to drill over 26,000-39,000 wells on these plays to meet land commitments (generally within a three- to five-year time frame) – an aggressive requirement. Overall, we believe we are on the cusp of a new land retention driven boom, this time focused on new liquids plays. What this means for gas prices is that, even if gas prices rise, producers are more likely to use the incremental cash flows to accelerate drilling on liquids plays (to meet commitments) rather than accelerate on dry gas plays where they already hold the majority of their lands.


65

GOM – Shelf Declines But Deep Production Should Rebound In 2014-16 Time Frame Within North America, oil sands and tight oil are the main growth focal points. This is true particularly in the post-Macondo world, which put a multi-year delay in front of any big growth out of the U.S. GOM. However, it is important to not leave out the GOM as it does have important (albeit delayed) growth potential.

The following chart depicts Wood Mackenzie’s outlook for U.S. GOM oil and natural gas production. We have sorted the data to reflect the profile from currently producing assets vs. future planned projects. While the base deep GOM profile moves to meaningful declines, it is important to make note of the large project inventory that lies behind it. Based on these forecasts, the Deep GOM is expected to grow from 980 MBbls/d in 2011 to 1.7 MMBbls/d in 2016 (150,000 Bbls/d per year) and relatively flat thereafter. Predictably, most of the focus in the GOM is towards oil but associated gas production will keep overall Deep GOM natural gas supply relatively flat from 2.3 Bcf/d in 2011 to 2.2 Bcf/d in 2016 but dropping to 1.5 Bcf/d by 2020.

Exhibit 58. Deep GOM Production – Oil & Natural Gas

0

250

500

750

1,000

1,250

1,500

1,750

2,000

2,250

2,500

2,750

2011 2012E 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

Oil

Prod

uctio

n (M

Bbl

/d)

Current Production HadrianTiber Buckskin St Malo Big Foot Knotty Head Vito Appomattox Gunflint Lucius

0

250

500

750

1,000

1,250

1,500

1,750

2,000

2,250

2,500

2,750

2011 2012E 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

Nat

ural

Gas

Pro

duct

ion

(Mm

cf/d

)

Future ProductionCurrent Production

Source: CIBC World Markets Inc. and Wood Mackenzie

As depicted above, the growth in Deep GOM production is split between many projects with the biggest growth drivers through the 2016 time frame being the Hadrian field (operated by Exxon), Vito operated by Shell, Lucius operated by Anadarko (APC-NYSE), Jack/St. Malo operated by Chevron (CVX-NYSE), and Bucksin operated by Chevron. Of these projects, only Lucius and St. Malo is actually under construction today with the remainder likely to see sanction within the next 18 months. As with any unsanctioned growth, there is risk of deferral and, as such, in our GOM forecasts (incorporated into overall U.S. oil balances in a later section of the report), we generally risk growth projects in the 50% range leading to a growth rate more in the 80,000 Bbls/d per year range through 2016.

As with any projects, growth depends on price and economics. The half cycle break-evens for Deep GOM average US$65/Bbl – very competitive with onshore tight oil and generally better than Canadian oil sands costs. We note that the big exploration costs and very long cycle times for Deep GOM would weigh on full cycle costs more than other projects, however, the main point of this exercise is

Based on these forecasts, the Deep GOM is expected to grow from 980 MBbls/d in 2011 to 1.7 MMBbls/d in 2016 (150,000 Bbls/d per year). We assume 80,000 Bbl/d per year growth in our modelling.


66

to determine which projects at FID are most likely to proceed – and from this perspective GOM developers (as with tight oil and oil sands developers) will focus primarily on the half cycle costs.

Unsurprisingly, activity levels remain low in the shallow GOM. As depicted below, we expect reinvestment in the shallow GOM production to decline from ~266,000 Bbls/d in 2011 to 190,000 Bbls/d in 2016 (annual decline of 15,000 Bbls/d) and 77,000 Bbls/d by 2020 (annual decline of ~21,000 Bbls/d). The shallow GOM is more meaningful from a gas price perspective as it accounts for approximately 4% of total U.S. gas production (vs. shallow GOM that accounts for only 2% of U.S. oil production). Natural gas production in the shallow GOM is steep decline, and is expected to go from 2.6 Bcf/d in 2011 to 2.4 Bcf/d in 2016 and 1.1 Bcf/d in 2020.

Exhibit 59. Shallow GOM Production – Oil & Natural Gas

0

50

100

150

200

250

300

2011 2012E 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E 2021E 2022E

Oil

Prod

uctio

n (M

Bbl

/d)


0

500

1,000

1,500

2,000

2,500

3,000

2011 2012E 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E 2021E 2022E

Nat

ural

Gas

Pro

duct

ion

(Mm

cf/d

)


Source: CIBC World Markets Inc. and Wood Mackenzie.


67

Canadian Resource Play Growth

Resource Play Development – Canadian Style The U.S. and Canadian approaches to resource development are very different. With over 100 MMBbls of tight oil and over 2,000 Tcf of natural gas resources in Western Canada, there is no shortage of resource to develop. On the surface then, it is somewhat surprising that there is no Canadian equivalent to the magnitude of dramatic growth seen out of the U.S. plays such as the North Dakota Bakken or the Eagle Ford. To understand why this is the case, one must understand a few key differences between the oil and gas sectors in the U.S. and Canada.

Perhaps the biggest difference is the considerably greater capital intensity possible in the U.S. due to the size of its oilfield services sector. In the Eagle Ford alone, 2012 saw the rig count exceed 270 drilling rigs. Such a pace of development in one play is simply impossible in Canada, as our total available deep drilling fleet sits at just 400. Other key differences include the fact that in Canada (at least on the oil side) much of the rights to prospective tight oil acreage was already “held by production” when horizontal multi-stage fraccing rejuvenated the sector (i.e., operators producing from either the same zone or deeper zones were already holding the rights of emerging resource plays).

Most oil prone lands in Canada were largely regarded as mature opportunities, and, as such, were largely sold off by the big producers to royalty trusts in an earlier era (where these assets were a great fit to the trusts given their relatively low declines). What was obviously not known at the time of this asset transition was that assets that were thought to have limited development upside have now been found to have very significant upside indeed. With rights held by production in many cases (and in other cases held on five-year tenure with the government), operators in Canada have been able to afford a more measured pace of development compared to the U.S.

Exhibit 60. Production Growth In Canada Coming, But Not Quite As Fast As In The U.S.

Canadian Oil Production (On shore, Non-Oil Sands)

-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

1,800,000

2009

2010

2011

2012

E20

13E

2014

E20

15E

2016

E20

17E

2018

E20

19E

2020

E

Bbl/d


Historical Forecast

Canadian Natural Gas Production

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

2009

2010

2011

2012

E20

13E

2014

E20

15E

2016

E20

17E

2018

E20

19E

2020

E

Mm

cf/d


Historical Forecast

Source: geoSCOUT and CIBC World Markets Inc.

The U.S. and Canadian approaches to resource development are very different.

Canadian lands have much more generous tenure, leaving producers with more flexibility as to how and when they develop resources.


68

Canadian Tight Oil Through Inflection Point Although Canadian tight oil and shale gas resource development is proceeding slower than in the U.S., that doesn’t mean it’s not happening. In fact, as depicted in the following chart, Canadian tight oil growth is starting to impact overall production in a meaningful way. Overall Canadian light oil production was up 35,000 Bbls/d in 2011 vs. 2010 as tight oil growth more than offset stagnant production in conventional light oil. Production will no doubt increase again in 2012 as April production is already 70,000 Bbls/d higher than last year and drilling activity remains strong (see Exhibit 61).

Exhibit 61. Canadian Oil Production: Resource Play Vs. Non-resource Play

Canadian Oil Production (On-shore, Non-Oil Sands)

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

Q2/08

Q3/08

Q4/08

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

Q4/10

Q1/11

Q2/11

Q3/11

Q4/11

Q1/12

Q2/12

Bbl/d

Non Resource Play Oil Production Resource Play Oil Production Source: geoSCOUT and CIBC World Markets Inc.

Looking Back – Saskatchewan Bakken & Cardium Have Shown The Biggest Growth … As with development in the U.S., the drivers behind the resurgence in Canadian light oil production are easy to identify – tight oil plays. As illustrated below in Exhibit 62 (which breaks down growth by play), growth has thus far been relatively widespread (i.e., many contributors as opposed to one dominant driver). The Saskatchewan Bakken stands out as having been the biggest grower in the past. However, we note that growth in the Bakken has plateaued in recent quarters and the Bakken has been supplanted by the Cardium as the fastest growing Canadian play.

Exhibit 62. Canadian Oil Production Growth By Resource Play To 2012

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

500,000

550,000

600,000


Bbl

s/d

Montney - Gas Montney - Oil Deep Basin Hz Horn River Bakken

Duvernay Shaunavon Cardium Viking Amaranth

Glauconite Nikanassin Pekisko Seal Carbonates

Montney

Bakken

Cardium

Viking

Carbonates

Seal

Canadian Tight Oil Growth by Play (to 2012)

(20,000)

-

20,000

40,000

60,000

80,000

100,000

120,000

140,000

2009 2010 2011 2012E

Bbl

s/d

Montney - Oil Montney - Gas Horn River Deep Basin HzDuvernay Bakken Shaunavon CardiumViking Amaranth Glauconite NikanassinPekisko Seal Carbonates Total Production Chng

Cardium

Viking

Montney

Bakken

Carbonates

Shaunavon

Seal

Canadian Tight Oil Growth by Play (YOY Change to 2012)


Overall Canadian light oil production was up 35,000 Bbls/d in 2011 vs. 2010 and is was up ~70,000 Bbld on April data.

The Bakken has been supplanted by the Cardium as the fastest growing Canadian play.


69

Looking Forward – Cardium, Carbonates, And The Duvernay Likely The Biggest Sources Of Growth Looking into the future as far as 2020, we expect the Cardium will continue to be one of the principal drivers of light oil growth in Canada. In addition, the Tight Carbonates (principally on the Alberta Swan Hills and Slave Point trends of Alberta) and the Duvernay are expected to be principal drivers of liquids growth. Honorable mention also goes to the Viking, which (while its individual wells have lower productivity) we also think will be a material contributor to growth in the Western Canadian Sedimentary Basin.

Exhibit 63. Forecast Canadian Oil Production Growth By Resource Play To 2020

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

1,800,000

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

Bbl

s/d




Carbonates

Bakken

Duvernay

Cardium

Viking

Montney

Historical Forecast

Canadian Tight Oil Growth by Play (to 2020)

(20,000)

-

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

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

Bbl

s/d

Montney - Oil Montney - Gas Deep Basin Hz BakkenHorn River Duvernay Shaunavon CardiumViking Amaranth Glauconite NikanassinPekisko Seal Carbonates Total Production Chng

Canadian Tight Oil Growth by Play (YOY Change to 2020)


CAPP Expectations For Canadian Light Oil Growth Likely Conservative As depicted in our aggregate base case scenario below in Exhibit 64, we see total Canadian light oil production growing by 550,000 Bbls/d from 2011 to 2016 (~100,000 Bbls/d per year). In this scenario, total Canadian light oil production would be over 1,200,000 Bbls/d in 2016 and 1,650,000 Bbls/d by 2020. We note that CAPP’s forecasts are much more conservative than ours, as CAPP forecasts only 40,000 Bbls/d of light oil growth per year to 2016. Exhibit 64 also provides a “status quo” development scenario, which assumes no acceleration in the pace of development.

Exhibit 64. Onshore Canadian Oil Production Set To Increase Materially


-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

1,800,000

2009

2010

2011

2012

E20

13E

2014

E20

15E

2016

E20

17E

2018

E20

19E

2020

E

Bbl/d


CAPP On Shore Production Status Quo Production

Historical Forecast


We see total Canadian light oil production growing by 550,000 Bbls/d from 2011 to 2016 (~100,000 Bbls/d per year) – well above CAPP forecasts of ~40,000 Bbl/d per year.


70

Canadian Natural Gas A Different Picture Canadian natural gas resource play has been a very different picture than the U.S. While U.S. production has been booming, total Canadian production has been declining as resource play drilling has not been sufficient to offset other declines. When the flood of U.S. gas supply sent North American natural gas prices plummeting, Canada was more affected due to its transportation differential. Many operators in Canada had less access to capital then their U.S. peers, so while Canadian natural gas resource play development has continued to creep forward, most operators have sought out more economic liquids prospects.

Part of the rationale behind slower development is also that Canadian plays have much longer land tenure, which has meant that producers have had the luxury of drilling at a measured pace rather than having to externally finance aggressive gas drilling in a low price environment. So even cross border Canadian players such as Talisman and Encana (with relatively comparable economics on prospects on both sides of the border) strategically decided to focus much more on their U.S. opportunities to hold lands.

Exhibit 65. Canadian Gas Production: Resource Play Vs. Non-resource Play


-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

Q2/08

Q3/08

Q4/08

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

Q4/10

Q1/11

Q2/11

Q3/11

Q4/11

Q1/12

Q2/12

Mm

cf/d

Non Resource Play Gas Production Resource Play Gas Production Source: geoSCOUT and CIBC World Markets Inc.

Looking Back – The Montney & Deep Basin Have Shown Biggest Growth While total natural gas production in Canada has declined 8% overall since 2008, there have undoubtedly been bright spots from a number of gas resource plays. Most notable have been the Deep Basin and the Montney. In the Deep Basin, HZ multi-stage fraccing has seen the multi-zone play grow production by over 200% to 1.0 Bcf/d since 2008. In the Montney, growth has been nothing short of dramatic since 2008, with the play growing over 700% to 2.2 Bcf/d.

Exhibit 66. Canadian Natural Gas Production Growth By Resource Play To 2012

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000


Mm

cf/d




Montney

Deep Basin

Horn River

Glauc.

Canadian Natural Gas Growth by Play (to 2012)

(200)

-

200

400

600

800

1,000

1,200

1,400

1,600

2009 2010 2011 2012E

Mm

cf/d

Montney - Oil Montney - Gas Deep Basin Hz Horn RiverDuvernay Bakken Shaunavon GlauconiteCardium Viking Amaranth NikanassinPekisko Seal Carbonates Total Production Chng

Montney

Deep Basin

Horn River

Canadian Natural Gas Growth by Play (YOY Change to 2012)


Most notable have been the Deep Basin and the Montney. In the Montney, growth has been nothing short of dramatic since 2008, with the play growing over 700% to 2.2 Bcf/d.


71

Looking Forward – Duvernay And Horn River Also Potential Growth Drivers As shown in Exhibit 67 below, we expect the Montney and the Deep Basin will continue to be the principal drivers of resource play natural gas growth in Canada. Beyond 2015, however, we note that we expect both the Duvernay and the Horn River will begin to be much bigger contributors to Canadian supply.

Exhibit 67. Forecast Canadian Natural Gas Production Growth By Resource Play To 2020

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

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

Mm

cf/d

Montney - Oil Montney - Gas Deep Basin Hz Horn River Bakken



Montney

Duvernay

Deep Basin

Horn River

Historical Forecast

Canadian Natural Gas Growth by Play (to 2020)

(200)

-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

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

Mm

cf/d

Montney - Oil Montney - Gas Deep Basin Hz Horn RiverDuvernay Bakken Shaunavon CardiumViking Amaranth Glauconite NikanassinPekisko Seal Carbonates Total Production Chng

Canadian Natural Gas Growth by Play (YOY Change to 2020)


Low Natural Gas Prices Weigh On Near Term, But Growth On The Horizon As depicted in our aggregate base case scenario below in Exhibit 68, we see total Canadian natural gas production growing by 1.4 Bcf/d from 2011 to 2016 (~240 MMcf/d per year). In this scenario, total Canadian natural gas production would be 16 Bcf/d in 2016 and 19 Bcf/d by 2020. We note that Exhibit 68 also provides a “status quo” development scenario, which assumes no acceleration in the pace of development. We note that the majority of natural gas growth is growth being developed for LNG export projects.

Exhibit 68. Canadian Gas Production Flat In Near Term, But Growing Long Term


-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

2009

2010

2011

2012

E20

13E

2014

E20

15E

2016

E20

17E

2018

E20

19E

2020

E

Mm

cf/d


Status Quo Production

Historical Forecast


We see Canadian natural gas production growing by 1.4 Bcf/d from 2011 to 2016 (~240 MMcf/d per year) – but primarily driven by LNG development.


72

Canada Vs. The U.S. U.S. Production Growth Clearly Outstripping Canada As shown in Exhibit 69, U.S. production growth has clearly been outstripping Canada in both light oil and natural gas. On the oil side, U.S. production has grown 38% to 4,800,000 Bbls/d since 2008, while in Canada production gas grown just 7% to 740,000 Bbls/d. On the natural gas side, U.S. production has grown 22% to 70 Bcf/d since 2008, while in Canada production gas actually declined 8% to 14.5 Bcf/d.

Exhibit 69. Canadian Production Growth Lags U.S. U.S. Oil Production (On-Shore)

-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

4,500,000

5,000,000

Q1/08

Q2/08

Q3/08

Q4/08

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

Q4/10

Q1/11

Q2/11

Q3/11

Q4/11

Q1/12

Bbl/d



-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

Q2/08

Q3/08

Q4/08

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

Q4/10

Q1/11

Q2/11

Q3/11

Q4/11

Q1/12

Q2/12

Bbl/d


U.S. Natural Gas Production

-

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

Q1/08

Q2/08

Q3/08

Q4/08

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

Q4/10

Q1/11

Q2/11

Q3/11

Q4/11

Q1/12

Mm

cf/d



-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

Q2/08

Q3/08

Q4/08

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

Q4/10

Q1/11

Q2/11

Q3/11

Q4/11

Q1/12

Q2/12

Mm

cf/d

Non Resource Play Gas Production Resource Play Gas Production Source: geoSCOUT and CIBC World Markets Inc.

Why Has Growth Been Slower In Canada? Not Economics… Why has production growth been slower in Canada? To address this question first in the negative, we believe the reason is certainly not economics. As shown below in Exhibit 70, when we stack up Canadian and U.S. plays by profitability (using P/I index as a measure), Canadian and U.S. plays are very comparable. (We note that the P/I index is calculated by dividing a play’s mid-cycle NPV per well by drilling costs, and 0.2x is considered a reasonable P/I hurdle rate).

Exhibit 70. Economics Of Canadian Plays Comparable To U.S.

A-Tax Profit/Investment Ratio2 (P/I)(US$90/Bbl, US$3.50/Mcf, C$3.00/Mcf)

-0.5x 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x

Colorado ShaleNikanassin HZ

Horn RiverMontney Gas (Dry)

CadominNotikewin

Nikanassin VTDeep Basin HZ

EllerslieDeep Basin VT

WilrichBluesky

Tight Carbonates GasTight Carbonates Oil (Slave Point)

Montney Gas (Liquids Rich)Tight Carbonates Oil (Swan Hills)

GlauconiteCardium Gas

Seal (Thermal)Duvernay Shale

Montney Oil (Base)Viking

Cardium OilShaunavon

PekiskoBakken

AmaranthSeal (Cold)

Montney Oil (Kaybob)Seal Multi-Lateral (Cold)

Oil Plays

Gas Plays

Midcycle1 PROFITABILITYA-Tax Profit/Investment Ratio2 (P/I)

(US$90/Bbl, US3.50/Mcf, C$3.00/Mcf)

-0.5x 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x

Eagle Ford (Dry Gas)

Haynesville

Fayetteville

Barnett

Marcellus

Woodford

Anadarko Hz

Permian Hz

Eagle Ford (Wet Gas)

Mississippi Lime

Bakken (US)

Marcellus (Wet Gas)

Eagle Ford (Crude)

Eagle Ford

Oil Plays

Gas Plays

Midcycle1 PROFITABILITY



73

…Not Magnitude Of Attractive Prospects Either If not profitability, are the number and size of tight oil and tight gas prospects in Canada just too small? Again, we argue that the answer is no. As illustrated in Exhibit 71, Canada is in fact opportunity rich when it comes to resource plays. If anything, we believe the Canada oil & gas sector doesn’t have enough capital to pursue the opportunities currently in front of it.

Exhibit 71. Size Of The Resource Play Prize In Canada Large And Growing

Gas Resource Plays(Resource In Place)

2%2%5%7%1%4%<1%28%16%<1%<1%

2.5

15.0

20.0

10.0 10.07.5 6.0

5.0 4.3 2.5

4.0

25.0

20.0

15.0 15.0

0

5

10

15

20

25

Bakk

en(A

lber

ta)

Seal

Duv

erna

y

Car

dium

Tigh

tC

arbo

nate

s

Viki

ng

Bakk

en

(SE

Sask

.)

Low

erSh

auna

von

Peki

sko

Amar

anth

Mon

tney

Oil

Bar

rels

of O

il (B

ln)

Total Resource In Place (Bln barrels)

Recovered-to-Date

Oil Resource Plays(Resource In Place)

250

15256569

164200218

239250300

500

50

100

200

300

400

500

600

Hor

n R

iver

Col

orad

o Sh

ale

Mon

tney

Duv

erna

y

Dee

p Ba

sin

CBM

Mnv

l

CBM

HSC

Cor

dova

Doi

g

Utic

a Sh

ale

Car

dium

Gas

Nik

anna

ssin

Not

ikew

in

Gla

ucon

ite

Orig

inal

GIP

(Tcf

)

Optimistic Resource Estimate (Tcf)

Conservative Resource Estimate (Tcf)

250


In Fact, We Would Argue That Canada Has An Ironic Advantage In Resource Play Quality Rather then being disadvantaged on profitability and the number and size of quality resource play prospects, we believe Canada (on the contrary) is ironically advantaged on the liquids side by the fact that our conventional oil pools have had lower recoveries in the past. As such, we expect that there is a greater amount of low hanging fruit in Canada in the form of legacy redevelopments. Ironically, what once could be thought of as “bad” conventional pools, are now some of the very best prospects for development with horizontal multi-stage fraccing today. With tongue in cheek we like to say, “Bad rock is good, and Canada has a lot of bad rock – and that is Canada’s ironic advantage in the resource play game.”

Below are 4 key points that we believe characterize the opportunity for “brownfield” redevelopment of our liquids plays in Canada:

1. Bad rock is good – the ironic Canadian advantage: Compared to the U.S., Canadian conventional reservoirs are generally tighter in nature, and ideally suited to multi-stage fraccing for the same reasons that the technology has worked so well in unconventional tight oil plays such as the Bakken play in southeast Saskatchewan.

2. Tight oil does not equal oil shale: In contrast to many of the shale oil plays in the U.S. (such as the Niobrara or the Tuscloosa plays), most Canadian tight oil plays are tight sands rather than shales (and therefore have better reservoir characteristics).

3. Low geological risk: Resource is there, question is economics. Since legacy pools have already been delineated with vertical wells and older technology, we already know where to find the resources, and geological uncertainty is minimal.

4. Expansion of legacy pool boundaries possible: Since the limits of many pools were defined by economics in the past, we believe that many of Canada’s legacy pools can now be expanded with more efficient technology, and resource in place estimates in many legacy pools are likely to increase.


74

Canadian Disadvantages More Related Services & Infrastructure Capacity, As Well As Access To Capital We have summarized the key disadvantages that we believe have contributed to slower growth in Canada vs. the U.S. below:

1. Oilfield services capacity: Perhaps the biggest difference between Canada and the U.S. is the far greater capital intensity possible in the U.S. due to the size of its oilfield services sector. In the Eagle Ford alone, 2012 saw the rig count exceed 270 drilling rigs. Such a pace of development in one play is simply impossible in Canada, as our total deep drilling fleet sits at just ~400.

2. Infrastructure constraints: In some cases, such as the Horn River shale gas play in northeast B.C., while the resource is widely considered to be of high quality, infrastructure does not yet exist to economically bring production to market.

3. Access to capital: For many Canadian operators, capital is less accessible than it is for American peers

4. Land tenure: While we don’t believe land tenure issues are really a Canadian disadvantage, they do explain why development has been slower in Canada. At least on the oil side of the equation, much of the rights to prospective tight oil acreage was already “held by production” when horizontal multi-stage fraccing rejuvenated the sector (i.e., operators producing from either the same zone or deeper zones were already holding the rights of emerging resource plays). With rights held by production in many cases (and in other cases held on five-year tenure with the government), operators in Canada have been able to afford a more measured pace of development compared to the U.S.

5. Seasonality: There is significant seasonality in Canadian drilling, with many parts of the WCSB only accessible in the winter months and even those areas that do have summer drilling, they are still prone to long break-up periods that curtail activity. In contrast, most U.S. plays have very little seasonality allowing for much more efficient resource development by keeping crews fully employed year-around and allowing producers to keep ahead of decline curves.

At root, we believe Canada has a large, attractive inventory of resource play opportunities; however, unlike the U.S. the rights to much of these resources were already held by legacy production and we have a smaller oil & gas sector and less access to capital with which to pursue these opportunities.

Production Growth In Canada Coming, But At A More Measured Pace Weighing Canada’s ironic advantages against its practical disadvantages, we believe growth in Canada will undoubtedly come, but at a more measured pace than in the U.S. We expect labor and services capacity will continue to be periodic bottlenecks, with the most notable required infrastructure builds including LNG export capacity on the west coast as well as the Northern Gateway oil pipeline. As has already begun, we expect foreign capital will continue to flow into Canada to help fill the funding deficit faced in the development of what we consider to be an attractive set of resource play opportunities.


75

Allocating Capital – Where Does The Canadian Resource Play Dollar Go? As discussed in the U.S. section, industry has demonstrated an ability to shift capital quickly in response to price signals. The rapid pace with which capital can be reallocated from play to play makes it very important to understand the relative economics of various plays to get an understanding of where producers will favor oil plays vs. liquids-rich gas plays vs. dry gas plays.

Exhibit 72 below is a useful tool in understanding economic sensitivities and where producers will allocate capital for the main Canadian resource plays. We note that the size of the potential prize and repeatability are equally as important considerations as profitability when allocating capital. As depicted, the gap between oil plays and dry gas plays remains very wide. For plays such as the Horn River (which is far from infrastructure and has dry gas with high CO2 content), we would need to see natural gas prices of AECO $6.00/Mcf (roughly equivalent to US$5.50/Mcf NYMEX) to close the gap of returns. However, we note that Horn River is unique in that its development could still be secured depending primarily on the success of West Coast Canada LNG as key Horn River players such as Apache (APA-NYSE), EOG and Encana are partnered in the proposed 1.4 Bcf/d Kitimat LNG project, which would be fed from the Horn River.

Exhibit 72. Potential “Size Of The Prize” Just As Important As Economics In Deciding The Allocation Of Capital Gas Resource Plays

(Resource In Place)

A-Tax Profit/Investment Ratio2 (P/I)(MID: US$90/Bbl, C$3.00/Mcf)

-0.5x 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x



CadominNotikewin


EllerslieDeep Basin VT

WilrichBluesky

Tight Carbonates GasTight Carbonates Oil (Slave Point)

Montney Gas (Liquids Rich)Tight Carbonates Oil (Swan Hills)

GlauconiteCardium Gas

Seal (Thermal)Duvernay Shale

Montney Oil (Base)Viking

Cardium OilShaunavon

PekiskoBakken

AmaranthSeal (Cold)

Montney Oil (Kaybob)Seal Multi-Lateral (Cold)

Oil Plays

Gas Plays

A-Tax Profit/Investment Ratio2 (P/I)(HIGH GAS: US$100/Bbl, C$4.00/Mcf)

0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x 3.5x


Montney Gas (Dry)Cadomin

Horn RiverNotikewin

Nikanassin VTTight Carbonates

EllerslieDeep Basin VTDeep Basin HZ

Tight Carbonates OilBluesky

Tight Carbonates OilWilrich

Montney GasSeal (Thermal)

Duvernay ShaleMontney Oil (Base)

Cardium GasGlauconite

Cardium OilViking

ShaunavonPekiskoBakken

AmaranthSeal (Cold)

Montney Oil (Kaybob)Seal Multi-Lateral

Oil Plays

Gas Plays

A-Tax Profit/Investment Ratio2 (P/I)(LOW: US$65/Bbl, C$2.00/Mcf)

-1.0x -0.5x 0.0x 0.5x 1.0x 1.5x



CadominNotikewin


EllerslieWilrich

Deep Basin VTBluesky

Montney Gas (Liquids Rich)Tight Carbonates Gas

Tight Carbonates Oil (Slave Point)Glauconite

Cardium GasTight Carbonates Oil (Swan Hills)

Duvernay ShaleSeal (Thermal)

VikingMontney Oil (Base)

ShaunavonCardium Oil

PekiskoBakken

AmaranthMontney Oil (Kaybob)

Seal (Cold)Seal Multi-Lateral (Cold)

Oil Plays

Gas Plays

Midcycle1 PROFITABILITY

2%2%5%7%1%4%<1%28%16%<1%<1%

2.5

15.0

20.0

10.0 10.07.5 6.0

5.0 4.3 2.5

4.0

25.0

20.0

15.0 15.0

0

5

10

15

20

25

Bakk

en(A

lber

ta)

Seal

Duv

erna

y

Car

dium

Tigh

tC

arbo

nate

s

Viki

ng

Bakk

en

(SE

Sask

.)

Low

erSh

auna

von

Peki

sko

Amar

anth

Mon

tney

Oil

Bar

rels

of O

il (B

ln)


Recovered-to-Date

Oil Resource Plays(Resource In Place)

250

15256569

164200218

239250300

500

50

100

200

300

400

500

600H

orn

Riv

er

Col

orad

o Sh

ale

Mon

tney

Duv

erna

y

Dee

p Ba

sin

CBM

Mnv

l

CBM

HSC

Cor

dova

Doi

g

Utic

a Sh

ale

Car

dium

Gas

Nik

anna

ssin

Not

ikew

in

Gla

ucon

ite

Orig

inal

GIP

(Tcf

)



250



76

New Plays Could Lead To Eagle Ford-esque NGL Boom The big wildcard for Western Canadian NGLs is the promise of the Duvernay shale – which has been compared in some cases to the prolific Eagle Ford shale in Texas (recall the Eagle Ford has grown from 11 to 427 MBoe/d in only three years). While it is still early days for the Duvernay, initial results appear promising and appear to be indicating quite a high liquids yield. (See page 219 in the Appendix of this report for details on the Duvernay.)

While there is no shortage of uncertainties in the Duvernay, we believe producers’ lust for liquids (in today’s depressed natural gas environment) and the large potential resource prize will drive development in the play. With most available acreage in the Kaybob and Willesden/Pembina areas now held, we believe the industry is on the verge of a ramp-up in drilling activity. Our work suggests that industry has spud close to 50 Duvernay wells to date and we have 16 public data points for liquids levels, indicating a median liquids yield of ~125 Bbls/MMcf.

We estimate the size of the prize in the Duvernay could be over 150 Tcf of gas and 10 billion Bbls of liquids with a 20%–50% recovery rate. Key risks in the Duvernay include, in our view, stabilization rates for new wells, breadth of productive liquids-rich window, prospectivity of the oil window, potential services constraints, and identity of land owners.

While it would be nearly impossible for the Duvernay to be developed the same pace as the Eagle Ford where activity ramped up to over 250 rigs in three years, we do believe Duvernay development could proceed more aggressively than in many Canadian resource plays as this is one liquids play where big players (such as Encana, Talisman) are all major owners and which have big incentive to build out their liquids exposure.

In addition to the Duvernay, we also have our eyes on the Northern Alberta Muskwa, which has many similar properties to the Duvernay. Recent land sale activity around Rainbow Lake in northern Alberta has shown growing interest in the Muskwa shale (the Duvernay’s northern equivalent). In November 2009, EOG brought a Muskwa well on production near Rainbow Lake. The Muskwa well was drilled for close to $12MM and was brought on production in November 2009 and has been producing at between 50 Bbls/d and 200 Bbls/d. Since then, land sale activity has begun to pick up in the area. While we consider the northern Rainbow Lake area to be at an earlier stage of development and in an area with limited infrastructure, we would highlight Rainbow Lake as an area to watch for future Muskwa/Duvernay development.

We have included quite aggressive growth forecasts for the Duvernay, reflecting our view that results have been encouraging enough to support accelerated development in 2013. We model Duvernay drilling (wells coming on stream) going from ~34 in 2012 to 100 in 2013 and 200 in 2014. Our Duvernay type curve is 7.5 MMcfe/d IP rates, with approximately 50% being crude and well head condensate with additional liquids being extracted downstream. With these assumptions, we see the Duvernay ramping to ~300 MMcfe/d in 2013, 750 MMcfe/d in 2014 and over 1 Bcfe/d in 2015 (all approximately half liquids).

Six Key Plays In Canada To Watch In our opinion, the three key liquids plays to watch in Canada over the next five to 10 years will be the Cardium, the Tight Carbonates, and the Duvernay. The three key natural gas plays we would watch over the next five to 10 years include the Montney, the Horn River, and the Deep Basin. The next few pages summarize a few key considerations for each key play.

We estimate the size of the prize in the Duvernay could be over 150 Tcf of gas and 10 billion Bbls of liquids with a 20%–50% recovery rate.

With these assumptions we see the Duvernay ramping to ~300 MMcfe/d in 2013, 750 MMcfe/d in 2014 and over 1 Bcfe/d in 2015 (all approximately half liquids) – although we note the margin of error on these forecasts is quite high.


77

Key Canadian Liquids Play #1: The Cardium With a known resource in place of over 10 billion barrels, which we believe has the potential to double in size, the Cardium represents the first Canadian legacy pool to see active redevelopment. While we estimate that the economics of the Cardium are not as attractive as other tight oil plays such as the Bakken or Montney oil at Kaybob, we believe the large “size of the prize” and the derisking of the play from legacy drilling will lead the Cardium to be one of the most actively developed tight oil plays in Canada in the coming years.

Exhibit 73. The Cardium

Cardium Oil - Area Map (Circa August, 2012) Cardium Oil - Resource Potential

Source: GeoScout; CIBC World Markets Inc.

Cardium Oil - Area Production Growth

Note: Map updated as of August 2012. Source: GeoScout; Company reports; Geological Atlas of Western Canada; The Edge; Canadian Discovery Digest; CIBC World Markets Inc. Source: GeoScout; CIBC World Markets Inc.

Cardium Oil - Distribution By Peak I.P. Rates Cardium Oil - Land Position by Operator

Source: GeoScout and CIBC World Markets Inc.Notes 1) 1 section = 640 acres; 2) Denotes private company. Land positions are approximations based on company disclosure and public data, and do not adjust for prospectivity. Source: Company reports; GeoScout; CIBC World Markets Inc.

<1% <1%16%

28%

<1%4% 1% 7% 5% 2% 2%

4.0 2.5

4.3 5.0

6.07.5

10.010.0

20.0

15.0

2.5

15.015.0

20.0

25.0

0

5

10

15

20

25

Bakk

en(A

lber

ta)

Seal

Duv

erna

y

Car

dium

Tigh

tC

arbo

nate

s

Viki

ng

Bakk

en

(SE

Sask

.)Lo

wer

Shau

navo

n

Peki

sko

Amar

anth

Mon

tney

Oil

Bar

rels

of O

il (B

ln)


Recovered-to-Date

Cardium Land Holders

300

265

219

209

204

195

149

132

124

120

118

110

102

100

91 81 80 75 71 67 60 57 52 51 50 49 48 47 40 38 27 25 20 17 13

050

100150200250300350400450500

Penn

Wes

tBo

navi

sta

Petro

Bakk

enPe

ngro

wth

Angl

eC

onoc

oPhi

llips

NAL

Verm

ilion

ARC

Whi

teca

pVe

roBo

nter

raBe

llatri

xFa

irbor

neSi

nope

cN

uVis

taAn

ders

onTa

lism

anEx

xon/

Impe

rial

Com

pton

Para

mou

ntSu

ncor

TriO

ilTA

QA

Nor

thSp

arta

nC

roco

ttaAp

ache

Dev

onEn

erpl

usPe

rpet

ual

KNO

C(2

)C

rew

Hus

ky BPD

elph

iEq

ual

Net

Sec

tions

(1)

1039

Cardium

-

50

100

150

200

250

300

350

400

450

Q2/

08Q

3/08

Q4/

08Q

1/09

Q2/

09Q

3/09

Q4/

09Q

1/10

Q2/

10Q

3/10

Q4/

10Q

1/11

Q2/

11Q

3/11

Q4/

11Q

1/12

Q2/

12Q

3/12

Q4/

12Q

1/13

Q2/

13Q

3/13

Q4/

13Q

1/14

Q2/

14Q

3/14

Q4/

14Q

1/15

Q2/

15Q

3/15

Q4/

15

Tota

l Pro

duct

ion

(MB

oe/d

)

0

50

100

150

200

250

300

350

400

450

Liquids Production (MB

oe/d)

Pre 2008 2008 2009 2010 2011

2012 2013 2014 2015 Liquids

Actual Forecast

Distribution by Peak I.P. Rate HORIZONTAL Cardium Oil Wells

0

100

200

300

400

500

600

700

800

900

1000

1100

1200

50 100

150

200

250

300

350

400

450

500

550

600

650

700

750

800

850

900

950

1000

1050

1100

1150

1200

1250

1300

Well Count

Pea

k I

.P.

Rat

e (B

oe/

d)

2008 & Earlier (3 Wells)

2009 (46 Wells)

2010 (405 Wells)

2011 (737 Wells)

2012 (156 Wells)

Median

Mean (Average)

Top/Bottom Quartile

Distribution Curve

050

100150200250300350400

0

15

0

30

0

45

0

60

0

(Boe/d)

Co

un

t


78

Key Canadian Liquids Play #2: The Tight Carbonates Like the Cardium, the Tight Carbonates (namely the Slave Point and Swan Hills trends) are partially derisked legacy developments with a large potential resource prize. In this case, we believe our estimate of 7.5 billion barrels in place has the potential to double. While the Carbonate play is somewhat less derisked than the tight sands reservoir of the Cardium and the completion techniques are slightly different (i.e., the carbonate reservoirs are typically fracced with acid instead of sand), we believe economies of scale and upside to completion techniques will contribute to the carbonates being a key driver of Canadian growth.

Exhibit 74. The Tight Carbonates: Slave Point And Swan Hills Trends

Tight Carbonates - Area Map (Circa August, 2012) Tight Carbonates - Resource Potential


Tight Carbonates - Area Production Growth

Note: Map updated as of Aug. 2012. Source: GeoScout; Company reports; Geological Atlas of Western Canada; The Edge; Canadian Discovery Digest; Sherwin; CIBC World Markets Inc. Source: GeoScout; CIBC World Markets Inc.

Tight Carbonates - Distribution By Peak I.P. Rates Tight Carbonates - Land Position by Operator

Source: GeoScout and CIBC World Markets Inc.1) 1 section = 640 acres; 2) Denotes private company; 3) Denotes CIBC/Geoscout Estimate. Note: Land positions include acreage accessible via farm-in agreements. Source: Company reports; GeoScout; CIBC World Markets Inc.

<1% <1%16%

28%

<1%4% 1% 7% 5% 2% 2%

4.0 2.5

4.3 5.0

6.07.5

10.010.0

20.0

15.0

2.5

15.015.0

20.0

25.0

0

5

10

15

20

25

Bakk

en(A

lber

ta)

Seal

Duv

erna

y

Car

dium

Tigh

tC

arbo

nate

s

Viki

ng

Bakk

en

(SE

Sask

.)Lo

wer

Shau

navo

n

Peki

sko

Amar

anth

Mon

tney

Oil

Bar

rels

of O

il (B

ln)


Recovered-to-Date

Tight Carbonate Land Holders545

266208

150108 100 100 100

72 64 64 63 45 23 14 30 29 23 15

0

100

200

300

400

500

600

Pen

n W

est

Pen

grow

th

Cor

al H

ill (

2)

Arc

an

Apa

che

(3)

KN

OC

/Har

vest

(2)(

3)

Dev

on (

3)

Pin

ecre

st (

3)

AR

C

Lone

Pin

e (2

)

For

est

Oil

Pac

e

Sec

ond

Wav

e

Bay

tex

Wild

Str

eam

Dol

omite

(2)

Pac

e

Bay

tex

Wild

Str

eam

Net

Sec

tio

ns

(1)

Carbonates

-

25

50

75

100

125

150

175

Q2/

08Q

3/08

Q4/

08Q

1/09

Q2/

09Q

3/09

Q4/

09Q

1/10

Q2/

10Q

3/10

Q4/

10Q

1/11

Q2/

11Q

3/11

Q4/

11Q

1/12

Q2/

12Q

3/12

Q4/

12Q

1/13

Q2/

13Q

3/13

Q4/

13Q

1/14

Q2/

14Q

3/14

Q4/

14Q

1/15

Q2/

15Q

3/15

Q4/

15

Tota

l Pro

duct

ion

(MB

oe/d

)

0

25

50

75

100

125

150

175


oe/d)

Pre 2008 2008 2009 2010 2011

2012 2013 2014 2015 Liquids

Actual Forecast

Distribution by Peak 30-Day I.P. Rate HORIZONTAL Tight Carbonates Wells

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

10 20 30 40 50 60 70 80 90100

110

120

130

140

150

160

170

180

190

200

210

220

230

240

250

260

270

280

290

300

310

320

330

340

350

360

370

380

390

400

Well Count

Pea

k I.P

. Rat

e (B

oe/

d)

2008 & Earlier (8 Wells)2009 (12 Wells)2010 (81 Wells)2011 (241 Wells)2012 (64 Wells)MedianMean (Average)Top/Bottom Quartile

Distribution Curve

0

20

40

60

80

100

120

140

0

200

400

600

800

(Boe/d)

Cou

nt


79

Key Canadian Liquids Play #3: The Duvernay Different than the Cardium and the Tight Carbonates, the Duvernay is not a legacy redevelopment, and as such majors such as Encana and Talisman have been able to consolidate large land positions. While there is no shortage of uncertainties in the Duvernay, we believe the major’s lust for liquids and the large potential resource prize will drive development in the play. We estimate the size of the prize in the Duvernay could be over 150 Tcf of gas and 10 billion Bbls of liquids with a 20%–50% recovery rate. Our work suggests that industry has spud close to 50 Duvernay wells to date, and we have 16 public data points for liquids levels, indicating a median liquids yield of ~125 Bbls/MMcf.

Exhibit 75. The Duvernay

Duvernay - Area Map (Circa August, 2012) Duvernay - Liquids and Gas Resource Potential .

Source: GeoScout; CIBC World Markets Inc.y

Duvernay - Area Production Growth

Note: Map updated as of June 2012. Source: GeoScout; Company reports; Geological Atlas of Western Canada; The Edge; Canadian Discovery Digest; CIBC World Markets Inc. Source: GeoScout; CIBC World Markets Inc.

Duvernay - Company Activity Duvernay Play - Land Position by Operator

Source: GeoScout and CIBC World Markets Inc.

Notes 1) 1 section = 640 acres; 2) Denotes private company. Land positions are approximations based on company disclosure and public data, and do not adjust for prospectivity. (3) Due to licensing data we believe Shell has acquired 42.6 sections from PetroBakken; however, we believe Shell likely has much more land. Source: Company reports; GeoScout; CIBC World Markets Inc.

<1% <1% 16% 28%<1% 4% 1% 7% 5% 2% 2%

4.0 2.5

4.3 5.0 6.07.510.010.0

20.0

15.0

2.5

15.015.0

20.0

25.0

0

5

10

15

20

25

Bakk

en(A

lber

ta)

Seal

Duv

erna

y

Car

dium

Tigh

tC

arbo

nate

s

Viki

ng

Bakk

en

(SE

Sask

.)

Low

erSh

auna

von

Peki

sko

Amar

anth

Mon

tney

Oil

Bar

rels

of O

il (B

ln)


Recovered-to-Date

250

256569

164200218239250250

300

500

15 50

100

200

300

400

500

600

Hor

n R

iver

Col

orad

oSh

ale

Mon

tney

Duv

erna

y

Dee

p Ba

sin

CBM

Mnv

l

CBM

HSC

Cor

dova

Doi

g

Utic

a Sh

ale

Car

dium

Gas

Nik

anna

ssin

Not

ikew

in

Gla

ucon

ite

Orig

inal

GIP

(Tcf

)



Duvernay Land Holders

625 623563

400

313

225 195 172 156 156 145 141 125 123 113 86 86 79 79 73 70 59 58 43 43 31 23 18 12

1000

?

0

100

200

300

400

500

600

700

800

900

1,000

Ath

abas

ca

Enc

ana

CN

RL

Tal

ism

an

Bon

avis

ta

Che

vron

Tril

ogy

Sin

ope

c

Ce

ltic

Pen

n W

est

Gui

de

Pet

roba

kke

n

Co

noco

Phi

llips

TA

QA

Nor

th

Lon

gvie

w

Ene

rplu

s

Ter

ra

Hus

ky

Del

phi

Son

de

Ang

le

Chi

nook

Birc

hclif

f

Ver

o

Bel

latr

ix

Wes

tfire

Co

nnac

her

Cre

w

Yoh

o

Ceq

uenc

e

She

ll (3

)

Net

Sec

tio

ns

(1)

Celtic 13-36 (~80Bbl/Mmcf)

Shell 09-34 (+100Bbl/Mmcf)

Athabasca 07-18 (390Bbl/d oil & 1.5Mmcf/d gas)

The million dollar question for the Duvernay is the extent of the prospective liquids window. Recent data points from Encanaand Athabasca (in the oil window to the north) have added confidence to the liquids story of the play.

Celtic 15-33 (75Bbl/Mmcf)

Encana 16-05 (200Bbl/Mmcf)


Yoho 13-22 (109Bbl/Mmcf)

Yoho 14-16 (~105Bbl/Mmcf)

BXE 8-24 little liquids


Bonavista 16-33 (75Bbl/Mmcf)

Trilogy 03-13 (80Bbl/Mmcf)

Talisman 01-18 (~0Bbl/Mmcf)


Conoco 11-16 (+20-30Bbl/Mmcf)



Shell 09-34 (+100Bbl/Mmcf)

Athabasca 07-18 (390Bbl/d oil & 1.5Mmcf/d gas)

The million dollar question for the Duvernay is the extent of the prospective liquids window. Recent data points from Encanaand Athabasca (in the oil window to the north) have added confidence to the liquids story of the play.

Celtic 15-33 (75Bbl/Mmcf)



Yoho 13-22 (109Bbl/Mmcf)

Yoho 14-16 (~105Bbl/Mmcf)

BXE 8-24 little liquids


Bonavista 16-33 (75Bbl/Mmcf)

Trilogy 03-13 (80Bbl/Mmcf)

Talisman 01-18 (~0Bbl/Mmcf)


Conoco 11-16 (+20-30Bbl/Mmcf)


Duvernay

-

300

600

900

1,200

1,500

1,800

2,100

2,400Q

2/08

Q3/

08Q

4/08

Q1/

09Q

2/09

Q3/

09Q

4/09

Q1/

10Q

2/10

Q3/

10Q

4/10

Q1/

11Q

2/11

Q3/

11Q

4/11

Q1/

12Q

2/12

Q3/

12Q

4/12

Q1/

13Q

2/13

Q3/

13Q

4/13

Q1/

14Q

2/14

Q3/

14Q

4/14

Q1/

15Q

2/15

Q3/

15Q

4/15

Tota

l Pro

duct

ion

(Mm

cfe/

d)

0

50

100

150

200

250

300

350

400


oe/d)

Pre 2008 2008 2009 2010 20112012 2013 2014 2015 Liquids

Actual Forecast

Confidential TOTALProducing Drilled/Spud TOTAL Locations Drilled or

Company Ticker Wells Wells Drilled (Licensed) Licensed1 EnCana ECA 2 4 6 7 132 Celtic CLT 6 5 11 1 123 Trilogy TET 3 4 7 1 84 Athabasca ATH 1 4 5 3 85 Shell RDS.A-NYSE 1 3 4 3 76 Husky HSE 5 5 1 67 Yoho YO 5 5 1 68 Talisman TLM 1 3 4 2 69 Chevron CVX-NYSE 1 1 2 3

10 Westfire WFE 1 1 2 311 ConocoPhillips COP-NYSE 1 1 2 212 Blaze PRIVATE 1 1 1 213 Charger CHX 2 214 Alta Enrg Prtnr PRIVATE 1 1 115 Angle NGL 1 1 116 Antelope PRIVATE 1 1 117 Bellatrix BXE 1 1 118 Bonavista BNP 1 1 119 Mke MKE-ASX 1 1 120 Taqa North TAQA-ADX 1 1 121 Arriva PRIVATE 1 1

Total (gross) 12 39 51 27 78


80

Key Canadian Natural Gas Play #1: The Montney As the first unconventional natural gas play in Canada to see active development with horizontal multi-stage fraccing, production from the Montney has already grown dramatically from close to 0.5 Bcf/d in 2006 to over 2.0 Bcf/d today. We estimate a resource in place in the Montney between 125 Tcf and 250 Tcf and believe the play will be the largest contributor to dry gas growth in Canada in the mid-term.

Exhibit 76. The Montney

Montney - Area Map (Circa August, 2012) Montney - Resource Potential


Montney - Area Production Growth


Montney - Distribution By Peak I.P. Rates Montney - Land Position by Operator


250

25

6569

164200

218239250250

300

500

15 5

0

100

200

300

400

500

600

Hor

n R

iver

Col

orad

o Sh

ale

Mon

tney

Duv

erna

y

Dee

p Ba

sin

CBM

Mnv

l

CBM

HSC

Cor

dova

Doi

g

Utic

a Sh

ale

Car

dium

Gas

Nik

anna

ssin

Not

ikew

in

Gla

ucon

ite

Orig

inal

GIP

(Tcf

)



Montney Land Holders1281

10831011

841

694 688

303 266 264201 195 195 190 180 152 144 133 80 78 70 67 55

0

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ress

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l Pro

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oe/d)

Pre 2008 2008 2009 2010 2011

2012 2013 2014 2015 Liquids

Actual Forecast

Distribution by Peak 30-Day I.P. Rate HORIZONTAL Montney Wells

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. R

ate

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cfe

/d)


Distribution Curve

0306090

120150180210240270300

0 2 4 6 8 10 12 14 16

(Mcfe/d/d)

Cou

nt


81

Key Canadian Natural Gas Play #2: The Horn River While the Horn River is generally regarded as one of the highest-quality shales in North America, the remoteness of the play and the dry gas nature of its production means that it will likely that the Horn River will have to wait until the post 2017 time frame to be a major contributor to Canadian supply. We note that Horn River is unique in that its development will likely be contingent on success of the development of West Coast Canada LNG as key Horn River players such as Apache, EOG and Encana are partnered in the proposed 1.4 Bcf/d Kitimat LNG project, which would be fed from the Horn River.

Exhibit 77. The Horn River

Horn River & Cordova Embayment - Area Map (Circa August 2012) Horn River/Cordova - Resource Potential


Horn River - Area Production Growth


Horn River - Distribution By Peak I.P. Rates Horn River - Land Position By Operator


250

256569

164200

218239250250

300

500

15 5

0

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Hor

n R

iver

Col

orad

o Sh

ale

Mon

tney

Duv

erna

y

Dee

p Ba

sin

CBM

Mnv

l

CBM

HSC

Cor

dova

Doi

g

Utic

a Sh

ale

Car

dium

Gas

Nik

anna

ssin

Not

ikew

in

Gla

ucon

ite

Orig

inal

GIP

(Tcf

)



Horn River Land Holders531

450

313266 245

203156 148 139 141 138 116 113

84

15

0

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Exxo

n/Im

peria

l

EnC

ana

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he

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on

EOG

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Con

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rces

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t

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row

th

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en

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w

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tions

(1)

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-

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Distribution by Peak I.P. Rate HORIZONTAL Horn River Gas Wells

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k I.

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e (M

cfe/

d) 2008 & Earlier (17 Wells)

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Distribution Curve

0510152025

0.0

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(Mcfe/d/d)

Co

unt


82

Key Canadian Natural Gas Play #3: The Deep Basin The multi-zone nature of the Deep Basin means that it is truly a number of plays (largely ranging from Cadomin to the Cardium) rather than one single play. The Deep Basin has seen active development in the past, but is now being developed much more economically with HZ multi-stage fraccing. In addition to its multi-zone potential, the Deep Basin is marked by the liquids-rich nature of many of its horizons.

Exhibit 78. The Deep Basin

Deep Basin - Area Map (Circa August, 2012)

Note: Map updated as of May 2012. Source: GeoScout, Sherwin Geoedges, Canadian Discovery Digest, The Edge, Geological Atlas of Western Canada, Core Laboratories, Company reports, CIBC World Markets

Deep Basin Hz + Vt

-

600

1,200

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83

Where To From Here – Canadian Resource Play Growth In summary, Canadian growth in both light oil and natural gas production is certainly on the horizon, even if it arrives at a slower pace than it does in the U.S. As summarized in Exhibit 79 below, we see Canadian light oil production growing by an average of ~10% per year from 2011 to 2016 (~100,000 Bbls/d per year, compared to CAPP’s estimate of just 40,000 Bbls/d per year) and 8% per year from 2016 to 2020. On the natural gas side, we see Canadian gas production growing ~2% per year from 2011 to 2016 (~300 MMcf/d per year) and 4% per year from 2016 to 2020. In this scenario, total Canadian light oil production would be 1,650,000 Bbls/d by 2020 and natural gas would be 19 Bcf/d by 2020.

Exhibit 79. Canadian Growth On The Horizon, Although At A Slower Pace Than In The U.S. Canadian Oil Production (On-shore, Non-Oil Sands)

-

200,000

400,000

600,000

800,000

1,000,000

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1,600,000

1,800,000

2009

2010

2011

2012

E20

13E

2014

E20

15E

2016

E20

17E

2018

E20

19E

2020

E

Bbl/d


CAPP On Shore Production Status Quo Production

Historical Forecast


-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

2009

2010

2011

2012

E20

13E

2014

E20

15E

2016

E20

17E

2018

E20

19E

2020

E

Mm

cf/d


Status Quo Production

Historica Forecast


Key Takeaways For Canadian Resource Plays Weighing Canada’s ironic advantages against its practical disadvantages,

we believe growth in Canada will come, but at a more measured pace than in the U.S.

We expect labor and services capacity in Canada will continue to be periodic bottle necks, with the most notable required infrastructure build including the LNG export capacity on the west coast as well as the Northern Gateway oil pipeline.

As has already begun, we expect foreign capital will continue to flow into Canada to help fill the funding deficit faced in the development of and attractive set of resource play opportunities.

Canadian resource play economics are competitive with U.S. plays, as is the depth of development opportunities.

Key Canadian liquids plays to drive growth include Cardium, Tight Carbonates, and the Duvernay.

Key Canadian natural gas plays to drive growth include the Montney, Deep Basin, and the Horn River.

Canadian light oil growth has already arrived and will continue to see capital in the near-term. We believe CAPP growth forecasts to be conservative.

Canadian dry gas plays pretty far down the value chain….but LNG will still yield meaningful development.

To

o M

uch

Of A

Go

od

Th

ing

... - Au

gu

st 15

, 20

12

84

Exhibit 80. Forecasts For Individual Canadian Plays To 2015 – LIQUIDS PLAYS


To

o M

uch

Of A

Go

od

Th

ing

... - Au

gu

st 15

, 20

12

85

Exhibit 81. Forecasts For Individual Canadian Plays To 2015 – NATURAL GAS PLAYS



86

Oil Sands – Vast Resource But Can It Compete? Only two years ago, the oil sands were regarded as the last major “oil resource play”. Technology has clearly reacted quickly to create significant competition for the oil sands, to the point where it is beginning to impact the growth outlook for this vast resource. In this section, we examine the outlook for oil sands growth in the context of competition from the many emerging domestic tight oil resource plays.

Growth Plans Vs. Pipeline Constraints The key part of any oil sands growth projection is pipeline capacity vs. planned projects. Historically pipeline capacity has not been a major concern but in the past 12 months the environment has changed radically. The first fundamental change was the denial of the Keystone XL pipeline. While we still believe the pipeline ultimately gets approved, it clearly brings to the forefront the risk of anticipated pipeline capacity not being built. The second fundamental shift has been the explosion in output from the tight oil resource plays that is starting to choke off market access for oil sands. The combination of the U.S. Bakken growing at a rate of ~110,000 Bbls/d per year for the past two years (and likely to be 200,000+ Bbls/d in 2012) and Canadian tight oil growing (100,000 Bbls/d) has the PADD 2 refining market, which was the main anticipated near-medium term outlet for Canadian Crude, bursting at the seams. As depicted in the previous example, the sensitivity to incremental price discounting (a reflection of full PADD 2 markets) has a meaningful impact on economics/break-evens.

The following charts depict oil sands growth scenarios for SAGD, mining and then for all oil sands rolled together. We present the following scenarios; 1) corporate unrisked – this is the sum of each company’s stated oil sands growth plans/project sequencing; 2) CAPP 2012 oil sands growth outlook; and 3) CIBC risked case in which we handicap projects from Scenario 1 based on our assessment of a company’s regulatory status and ability to finance and execute. We have also layered on the overall regulatory status for these oil sands projects.

Exhibit 82. Mining Oil Sands Growth

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

1,800,000

2,000,000

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

Min

ing

Prod

uctio

n (b

bls/

d)

Producing Construction Approved Submitted Disclosed CAPP Mining (2012) CIBC Estimates Source: CAPP, company reports and CIBC World Markets Inc.


87

Exhibit 83. SAGD Oil Sands Growth

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

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

SAG

D P

rodu

ctio

n (b

bls/

d)

Producing Construction Approved Submitted Disclosed CAPP In-Situ Forecast (2012) CIBC Estimates Source: CAPP, company reports and CIBC World Markets Inc.

As depicted above, there is no shortage of oil sands growth projects competing for development. On an unrisked basis (i.e., if corporations collectively followed through with current plans), oil sands would grow from 1.6 MMBbls/d in 2011 to 3.0 MMBbls/d by 2016 (280,000 Bbls/d per year growth) and to 5.0 MMBbls/d by 2020 (380,000 Bbls/d per year growth). On the other end of the spectrum, CAPP foresees oil sands reaching a more conservative 2.5 MMBbls/d by 2016 (180,000 Bbls/d per year growth) and 3.2 MMBbls/d by 2020 (180,000 Bbls/d per year growth).

When plotted against planned pipeline capacity, it becomes abundantly clear that not all company planned oil sands projects can proceed. Even if Keystone XL, TransMountain, Northern Gateway and the tentative TransCanada (TRP-SP) West Coast Line were all built, there would still not be enough pipeline capacity to handle planned growth through 2020! Layering in the very real risk that at least one of these pipelines (likely two) may not be built in this time frame implies the need for 1.5 MMBbls/d of projection rationalization/cannibalization from current company forecasts.

Another way of looking at oil sands growth is maximum possible growth given pipeline capacity. If Keystone XL is built and Alberta Clipper is expanded, western Canadian oil production can grow ~1.2 MMBbls/d from current levels. This sounds like a lot but when one considers our forecast of Western Canadian light oil growth of ~100,000 Bbls/d per year and oil sands producers are aiming to grow by over 260,000 Bbls/d per year through 2016 (or ~340,000 Bbls/d including diluent), the capacity goes away quite quickly. From there, the main pipelines are West Coast options (Northern Gateway and TransMountain) – both of which carry very high political risk and a very early-stage proposal from TransCanada to send crude east. IF these pipelines are not built, oil sands producers would have to rationalize their 2020 growth targets downward by 2.5 MMBbls/d.

On an unrisked basis, oil sands would grow from 1.6 MMBbls/d in 2011 to 3.0 MMBbls/d by 2016 and to 5.0 MMBbls/d by 2020.

When plotted against planned pipeline capacity, it becomes abundantly clear that not all company planned oil sands projects can proceed.


88

Exhibit 84. Western Canadian Oil Growth Vs. Pipeline Capacity

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2011 2012E 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

Oil

Ex

po

rts

(M

bb

l/d)

CAPP Company Forecasts CIBC EstimatesCurrent Capacity TranscCanada Keystone XL Kinder Morgan TMXEnbridge Northern Gateway TransCanada Eastern Canada Enbridge Mainline Expansion 1Enbridged Mainline Expansion 2

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

Labor Pains The third major question mark for oil sands development is labor availability. The oil sands is a massively labor intensive project type. A typical 100,000 Bbls/d non-upgraded mine requires peak labor of approximately 5,000 workers. A typical upgraded mine can require anywhere from 5,000-10,000 peak labor force depending on pace of construction (historically peak was 10,000 but more companies are planning to stretch construction to have better work force control). SAGD is less labor intensive but, even still, a typical 35,000 Bbls/d SAGD project still requires a peak labor force of approximately 700 workers over a two- to three-year construction period (smaller projects at shorter end of scale) and with so many projects in the queue, the labor needs are still massive.

There are no longer any good public sources for anticipated labor needs for the oil sands over the very long term. The Construction Owners Association of Alberta (COAA) publishes estimates that seem reasonably credible for the short term but lack needs for the planned projects post 2014. Given this limitation, we have constructed our own oil sands labor model incorporating COAA data historically along with calculated labor needs for future growth projects. While the margin of error is admittedly quite high, it still provides a useful idea of the real labor requirements that come along with current oil sands growth plans.


89

The following chart depicts the anticipated construction labor needs through 2020 to complete current operator growth forecasts (i.e., the unrisked sum of all individual company plans). The key takeaway is that to meet industry growth forecasts to the 2016/17 time frame, the available labor force in the oil sands would need to expand approximately 80% from 2012 levels. Clearly, at face value, these forecasts entail a massive external labor need – and we note this does not include the potential for the North West upgrader (potentially another 5,000 people) or competing labor demands for LNG construction on the BC Coast or potential for GTL (admittedly a far less likely venture).

Exhibit 85. Oil Sands Construction Labor Needs

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

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

Con

stru

ctio

n C

raft

Pers

onne

l

. Additional Labour Needs (CIBCe)

COAA Forecasts

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

Prices/Costs & Pipelines Will Rationalize Development…It Is Only A Matter Of How Far As discussed previously, there are a massive amount of projects on the planning board that cannot simply be taken at face value given the major development constraints such as pipeline capacity and labor. This implies a need for major projection rationalization/cannibalization that will be accomplished through some combination of accelerating inflation, lower prices or more stringent/discerning external capital.

To first gauge what the price impact is on oil sands development, we must understand the approximate break-evens. Exhibit 86 depicts the break-even oil price at today’s cost for a variety of in situ and mining oil sands projects. Recognizing that break-even costs are not a static figure, we also depict expected break-evens in five years assuming 5% per year cost inflation. As depicted, there is wide range of outcomes. At today’s costs, high-quality SAGD (i.e., similar to Cenovus’ Foster Creek and Christina Lake) break even at ~US$40/Bbl while more marginal projects (i.e., SOR in the 3.5 range with lower productivity wells) require an oil price in the US$70/Bbl range. Non-upgraded mining projects (Kearl) require an oil price in the US$70/Bbl range to break even while upgraded mining projects require an oil price in the US$85/Bbl range.

To meet industry growth forecasts to the 2016/17 time frame, the available labor force in the oil sands would need to expand approximately 80% from 2012 levels


90

We also note that these break-evens are hyper sensitive to realized price discounts. For non-upgraded projects, the sensitivity relates to the light-heavy oil differentials. The aforementioned break-evens were assuming 20% WCS discount to WTI. If we increase the WCS discount to 25%, the break-evens increase to US$49/Bbl for a high-quality lease to as high as US$82/Bbl for lower-quality leases. For upgraded projects, the sensitivity relates to the SCO-WTI discount. Historically, this has been zero but in the past six months we have seen it average ~7% reflecting the changing light oil balances in PADD 2. If we assume a 5% SCO discount to WTI long term, the break-even price increases to US$88/Bbl.

Exhibit 86. Oil Sands Break Even

Today 5-Years Today 5-Years Today 5-Years

Low Cost SAGD $43.47 $47.95 $46.19 $50.95 $49.27 $54.34Avg Cost SAGD $56.02 $61.99 $59.52 $65.87 $63.49 $70.26High Cost SAGD $72.13 $79.60 $76.64 $84.57 $81.75 $90.21Non-Upgraded Mining $66.96 $76.67 $71.14 $81.47 $75.89 $86.90Upgraded Mining $83.30 $95.58 $87.68 $100.61 $92.56 $106.20

25% WCS & 10% SCO Discount$/Bbl Break Even Cost

15% WCS & 0% SCO Discount 20% WCS & 5% SCO Discount


In an efficient market, price or costs will rationalize the supply/demand balance – and oil sands is no exception. As recently as the 2005-2008 cycle, we saw inflating costs substantially rationalize the pace of planned oil sands development – and we will see that again. We need to see that again. The following chart depicts our aggregated oil sands growth forecasts (the unrisked sum of corporate forecasts), grouped by our assessment of supply costs. As depicted, to achieve all company growth targets would require long-term oil in the $100/Bbl range. As oil price assumptions drop, meaningful amounts of planned oil sands growth would be curtailed. For instance, if oil prices fell to US$70/Bbl, there would be over 1 MMBbls/d of planned production that would not justify proceeding.

Exhibit 87. Oil Sands In Situ Growth By Approximate Supply Cost

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

2012E 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

Prod

uctio

n (b

bls/

d)

Producing and Under Construction $0 - $50 Supply Costs $50 - $60 Supply Costs $60 - $70 Supply Costs $70 - $100 Supply Costs


If oil prices fell to US$70/Bbl, there would be over 1 MMBbls/d of planned production that would not justify proceeding.


91

Exhibit 88. Oil Sands Mining Growth By Approximate Supply Cost

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

1,800,000

2,000,000

2012E 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

Prod

uctio

n (b

bls/

d)

Producing and Under Construction $0 - $50 Supply Costs $50 - $60 Supply Costs $60 - $70 Supply Costs $70 - $100 Supply Costs


Oil Sands – Higher Cost Projects The First To Fall In A Competitive North American Market The North American market is clearly saturated with oil resource development opportunities ranging from tight oil to deep Gulf development to oil sands. In a market that is oversaturated, there will no doubt be rationalization and the first projects to get squeezed will be those with higher supply costs and a riskier capital profile. Unfortunately, higher cost oil sands projects seem like the first to get rationalized.

The oil sands fall short in terms of capital profile risk as operators have to make significant investments for three to five years before production is realized – far different than a tight oil operator that can manage capital well by well and realizes cash flow very quickly. This means that oil sands operators, when approving a project, are making bigger and riskier decisions. Smaller projects cost half a billion dollars while bigger investment decisions will be approaching $10 billion – in stark contrast to tight oil where capital can essentially be managed well by well. The different scale of investment decision means that operators must have a higher degree of confidence in the macro environment or a bigger economic cushion to feel comfortable making that spending commitment.

From a supply cost perspective, oil sands cover a very wide spectrum and it is grossly misleading to group all the projects in one basket. Lower cost/higher quality oil sands projects can compete in terms of rate of return vs. tight oil development and will no doubt remain in the race to develop resource. Higher supply cost oil sands assets such as many mining projects and higher cost in situ assets will face a much more challenging time justifying investment as planned and will likely be the first projects to be rationalized.

In a market that is oversaturated with oil, there will no doubt be rationalization and the first projects to get squeezed will be those with higher supply costs and a riskier capital profile. Unfortunately, higher cost oil sands projects seem like the first to get rationalized.


92

Exhibit 89. Oil Sands Supply Costs vs. Tight Oil Supply Costs

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

$100

Upgraded

Mining

SAGD - High C

ost Pro

ducer

Mining

SAGD - Avg

Cost

Produce

r

Shaunav

on

Montney O

il (Bas

e)

Viking

Tight Carb

onates O

il (Swan

Hills

)

Cardium O

il

SAGD - Low C

ost Pro

ducer

Tight Carb

onates O

il (Slav

e Point)

Amaranth

Bakke

n

Pekisk

o

Montney O

il (Kay

bob)Sea

l

US$/Bbl

Source: Company reports and CIBC World Markets Inc.(SAGD & Mining based on 20% WCS Diff & 5% SCO Diff both Vs WTI)

Oil Sands Are Down But Not Out – Technology Optionality Is Still Large Although much of our top-down macro view of the oil sands is quite bearish, there is one very real theme that needs to be highlighted – the potential role of technology. We have just seen (and discussed) how completion technology has had a profound impact on opening up shale and tight resources. The oil sands share similarities to shales in that they are another big, discovered resource but where R&D efforts are still in the very early innings. There is an unprecedented amount of R&D dollars flowing into oil sands looking at technologies ranging from evolutionary (solvent assisted SAGD, in-fill drilling, non-condensable gas, etc.) to revolutionary (combustion technologies, pure solvent techniques, electrical conductive technologies, technologies to eliminate diluent, etc.).

Importantly, we are just starting to see the impact of technology. Cenovus has had very good, quantifiable results with its in-fill wells and will soon be the first to roll out SAP on a commercial scale. MEG recently surprised the market with its emSAGP approach, which uses non-condensable gas injection with in-fill wells to dramatically lower the SOR and free up more steam to add low-cost production. The overall point is that current supply costs do not reflect the potential of technology to change the oil sands landscape. This is a dynamic theme that we will continue to monitor, which could have an impact on the competitiveness of oil sands vs. tight oil resources.

Conclusions/Takeaways On Oil Sands Growth Overall, the oil sands has almost unlimited resource potential but the real question once again boils down to how much can (or should) get built in an environment that has substantial competition, particularly for labor and pipeline access.

There is no possible way the sum of company forecasts can be achieved. The sum of company forecasts implies oil sands growth of 380,000 Bbls/d per year through 2020. In such a scenario, even if every pipeline currently being planned was built (Keystone XL, Alberta Clipper expansion, TMX Expansion,

There is an unprecedented amount of R&D dollars flowing into oil sands looking at technologies.

Technology could be instrumental in reducing oil sands supply costs to more competitive levels with tight oil.


93

Gateway and TransCanada’s gas pipeline conversion), there would still not be enough capacity to meet company targets! The obvious conclusion is that growth will need to be rationalized – the only question is by how much?

No company voluntarily gives up the quest for growth…But Some Will Have To. This leaves the onus on market forces to rationalize that growth. The main market drivers will either be hyper inflation, regulatory delays and/or lower pricing either due to lower global benchmark pricing or localized discounting due to insufficient pipeline capacity. The most likely outcome is some combination of all these factors but our biggest concern at the moment is pipeline access.

Pipelines will likely be the biggest factor to dictate the pace of oil sands growth. We continue to believe that Keystone XL (the full line) will get built but one can’t deny there is still a level of risk to that. The Enbridge Alberta Clipper and Line 9 reversals are also clear go-aheads in our view. Access to the West Coast, either through the proposed TMX expansion or Northern Gateway, is looking riskier by the day as provincial governments squabble over revenue sharing and broad based political support in B.C. appears very low. If neither of these lines go ahead, oil sands growth targets for 2020 (company forecasts) would have to be rationalized by approximately 1.7 MMBbls/d from current levels.

TransCanada’s idea (not yet formally proposed) of converting one of its natural gas pipelines to oil is gaining a lot of traction. This is loosely estimated to be capable of ~650,000 Bbls/d and could carry oil to Eastern Canada and could be put on ship in Quebec or in the Maritimes for export. This pipeline though is generally better for light oils as the Eastern Canada market or the Eastern U.S. or European market has little heavy oil coking capacity. In any case, moving more light oil east would effectively ease access for heavies into PADD 2 and 3, which would be still beneficial to oil sands. If this pipeline, as well as the West Coast pipelines, did not proceed, we would need to see oil sands growth rationalized 2.4 MMBbls/d from current planned activity levels.

More Challenging Macro Environment For Oil Sands Likely To Continue To Impact M&A Parameters: Oil sands were once a hot focus for M&A activity. Back in the 2005-2008 time frame, typical deals for long-date oil sands resource were about US$1/Bbl. With higher prices in recent years, we have seen deal parameters steadily decrease – particularly in recent months. The rationale behind this divergence is increasing awareness from prospective buyers of the pipeline takeaway uncertainty and cost inflation risk. Additionally, many of these same buyers have many opportunities to invest in tight oil resources, which have created more competition for M&A/JV dollars for the oil sands. This trend will likely continue although we note there are many factors that will impact transaction parameters in the oil sands such as scale of the resource for sale (smaller resources typically get less interest and lower value), quality and state of regulatory approval. Overall, we believe there is still room for oil sands M&A but likely continuing the recent trend of sub US$1/Bbl parameters.


94

Impact Of North American Tight Oil Renaissance On Global Supply Demand Balances

High North American Growth Likely To Loosen Medium-term Oil Balances As unconventional natural gas supply boomed, it took many years for investors to fully come to grips with the likelihood that North American natural gas would be severely pressured for the foreseeable future. The question now is: will the boom in North American tight and oil sands upset the global supply/demand balance the same way we saw North American gas prices react to the supply boom?

There are certain parallels between the tight oil boom and the gas boom but there are many differences as well. The key difference is the size of the market. U.S. demand at the start of the shale boom was approximately 63 Bcf/d or, in oil terms, approximately 10.5 million Boe/d versus the current global oil market of 89.1 MMBbls/d of demand. This clearly implies a much larger market to absorb the impacts of booming North American supply versus what occurred in the North American gas market.

However, while the global oil market is much larger than the U.S. gas market, that does not mean that the U.S. boom will not alter the global supply/demand equation. Rapidly growing North American oil production will have an impact – the question is how big?

As depicted in Exhibit 90, we believe tight oil growth can drive U.S. onshore production growth of ~500,000 Bbls/d per year through 2016, oil sands should grow ~230,000 Bbls/d per year while conventional Canadian production (driven by tight oil) should easily grow 100,000 Bbls/d per year and GOM production growth should be up ~40,000 Bbls/d per year on average. All told, it is not hard to get to a North American growth assumption in the 800,000-900,000 Bbls/d per year range through 2016.

We believe North American oil production can grow 800,000-900,000 Bbls/d per year through 2016 – well above current consensus of ~340,000 Bbls/d.


95

Exhibit 90. North American Oil Growth Scenarios

Oil Ramp Up - (Bbl/d) 2011 2016 2020 '11-'16 '16-'20 '11-'20

On-Shore US OilLow Case (Scenario A from Ex 51) 4,177,000 6,597,784 7,208,065 484,157 152,570 336,785Base Case 4,177,000 7,179,901 8,990,148 600,580 452,562 534,794High Case (Scenario D from Ex 51) 4,177,000 7,762,017 10,772,230 717,003 752,553 732,803

US GOMLow Case 1,438,167 1,588,648 1,481,263 30,096 (26,846) 4,788Base Case 1,438,167 1,672,261 1,559,224 46,819 (28,259) 13,451High Case 1,438,167 1,755,874 1,637,185 63,541 (29,672) 22,113

Oil SandsLow Case 1,604,838 2,625,716 2,844,266 204,176 54,638 137,714Base Case 1,604,838 2,767,709 3,856,862 232,574 272,288 250,225High Case 1,604,838 2,909,703 4,869,457 260,973 489,939 362,735

Canadian Conv/Tight OilLow Case 1,111,922 1,357,936 1,558,359 49,203 50,106 49,604Base Case 1,111,922 1,603,949 2,004,795 98,405 100,211 99,208High Case 1,111,922 1,972,970 2,674,450 172,210 175,370 173,614

Total North American OilLow Case 8,331,927 12,170,084 13,091,952 767,631 230,467 528,892Base Case 8,331,927 13,223,820 16,411,028 978,379 796,802 897,678High Case 8,331,927 14,400,563 19,953,323 1,213,727 1,388,190 1,291,266



Exhibit 91 depicts the consensus view of medium-term call on OPEC. As depicted, the official consensus view is that North American oil production growth will average 343,000 Bbls/d per year through 2015 (note that not all the same forecasters are encapsulated in both estimates as disclosures and forecast horizons vary considerably). As mentioned above, we believe it is not hard to see a scenario where North American growth is more in the 800,000-900,000 Bbls/d per year range – well above current consensus expectations. Even our low-case scenario of ~650,000 Bbls/d per year is well above current consensus forecasts.

Exhibit 91. Consensus North American Production & Call On OPEC

Consensus Supply View (mbbl/d) 2011 2015

Annual Growth

Canada 3,639 4,261 144 US 8,478 9,442 227 Total Canada + US 11,389 12,851 343 Mexico 2,953 2,576 (88) Total North America 15,096 16,490 334

Other Non-OPEC Growth 38,380 39,122 185 Total Non-OPEC 52,985 55,208 536

Consensus Demand View (mbbl/d) 2011 2015

Annual Growth

Canada 2,220 2,203 (5) US 19,203 19,027 (30) Total Canada + US 21,423 21,230 (35) Mexico 2,204 2,274 15 Total North America 23,542 23,526 (0)

Other Demand 55,815 58,500 637 China Demand 9,626 11,753 511 Total World Oil Demand 88,983 93,779 1,148

Consensus Call On OPEC 35,998 38,572 612 Call On OPEC With CIBCe Low North American Growth 35,998 37,312 328 Call On OPEC With CIBCe Base Case North American Growth 35,998 36,392 98 Call On OPEC With CIBCe High North American Growth 35,998 35,596 (101)



96

Medium-term Spare Capacity Expands – Should Take SOME Of The Political Premium Out Of Oil If we extend the analysis to the implied call on OPEC (i.e., leaving all other parts of consensus unchanged but updating to reflect our range of North American deliverability), it becomes quite apparent that North American growth can have an impact on medium-term markets. Using our assumptions for North American supply growth would reduce the consensus call on OPEC through 2015/16 from 600,000 Bbls/d to 0-300,000 Bbls/d – a very significant change. In our view, this change implies that as global forecasters move to more realistic North American supply growth assumptions that the consensus view of tightness in the market will also change with a slightly bearish undertone. These weaker medium-term balances are the key reason we recently trimmed our long-term Brent assumption from US$100/Bbl to US$95/Bbl.

Political risk is always one of the most important variables in the global oil price equation. Obviously there is no way of predicting long-term political risk; however, we can reasonably estimate the OPEC spare capacity cushion and how that will change over the coming years. As discussed previously, we believe as major forecasters incorporate more realistic North American production growth over the next five years, the view of market tightness will change as the call on OPEC is reduced to 0-300,000 Bbls/d per year. In addition to this, OPEC will more than likely continue to reinvest in production capacity. As depicted in the chart below, if OPEC builds production capacity, as stated, combined with the lower call on OPEC, the spare capacity cushion builds quite meaningfully – reaching ~8 MMBbls/d by 2015, which would be one of the widest levels in many years.

This is not to say that the political premium, which is variable but ever-present in oil prices, will evaporate. After all, OPEC will still make up ~40% of global oil production through 2015 (i.e., OPEC remains extremely important) and, while unpredictable, odds are high that political turbulence in the Middle East is not going to disappear anytime soon.

Exhibit 92. OPEC Spare Capacity Sensitivity To North American Growth Scenarios

Consensus OPEC Spare Capacity (mbbl/d) 2011 2015Annual Growth

Consensus OPEC Production Capacity 40,229 45,446 1,304 Consensus Spare Capacity 4,231 6,875 661 Spare Capacity - % Of Global Demand 4.8% 7.3%Spare Capacity With CIBCe Low North American Growth 4,231 8,135 976 Spare Capacity - % Of Global Demand 4.8% 8.7%Spare Capacity With CIBCe Base Case North American Growth 4,231 9,055 1,206 Spare Capacity - % Of Global Demand 4.8% 9.7%Spare Capacity With CIBCe High North American Growth 4,231 9,851 1,405 Spare Capacity - % Of Global Demand 4.8% 10.5%


U.S. Reliance On Imports Lessens Considerably (But Pure Oil Independence Is Still A Long Ways Off) The recent boom in tight oil and liquids-rich resource play drilling has raised the possibility of the U.S. achieving oil independence or, at the very least, significantly reducing the need for imported oil. We generally agree with this thesis but not that the U.S. achieving pure energy independence is still a long ways off. Our base case view, which assumes relatively flat demand (in line with the EIA long-term energy outlook), we see U.S. required imports dropping from ~11 MMBbls/d in 2011 (and nearly 13 MMBbls/d in 2008) down to ~7.6 MMBbls/d by 2016 and 4-6 MMBbls/d by 2020 (depending on growth scenarios).

Using our assumptions for North American supply growth would reduce the consensus call on OPEC through 2015/16 from 600,000 Bbls/d to 0-300,000 Bbls/d – a very significant change.

If OPEC builds production capacity, as stated, combined with the lower call on OPEC, the spare capacity cushion builds quite meaningfully – reaching ~8 MMBbls/d by 2015, which would be one of the widest levels in many years.

Higher NA growth will take pressure off OPEC but will by no means reduce OPEC to irrelevancy as it will still produce ~40% of global oil production through 2015

We see U.S. required imports dropping from ~11 MMBbls/d in 2011 (and nearly 13 MMBbls/d in 2008) down to ~7.6 MMBbls/d by 2016 and 4-6 MMBbls/d by 2020


97

Exhibit 93. U.S. Oil Production Vs. Imports

-

2,500

5,000

7,500

10,000

12,500

15,000

17,500

20,000

22,500

25,000

27,500

30,000

2008

2009

2010

2011

2012

E20

13E

2014

E20

15E

2016

E20

17E

2018

E20

19E

2020

E

Oil

('000

bbl

/d)

US Oil Production Canadian Oil Imports

Required Foreign Oil Imports US Oil Demand

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

The picture changes yet again when one considers the impact of Canadian production. As highlighted above, with Canadian based imports expected to grow meaningfully over the coming years, foreign oil imports (which we define as imports other than Canada) decline from 8.8 MMBbls/d to 2.1 MMBbls/d by 2020. We note that the Canadian wedge on this chart could be much larger if the U.S. government were to allow more unfettered access of Canadian crudes into the U.S. market. This highlights the often contradictory U.S. energy policy which wants to “wean itself off foreign oil”, yet at the same time is forcing Canadian producers to look to market oil into Asia.

Impact Of Crude Renaissance On North American Regional Pricing The explosion in U.S. and Canadian oil production will have an impact on a global level, but arguably the bigger impact is on regional North American pricing and basis differentials. The big discounting seen to date this year for Canadian and Bakken crudes gives a glimpse of what is at risk and how important these basis differentials can be. Oddly enough, few of the basis differentials are unresolvable as there is plenty of demand in the U.S. for imported crude oil (or movements across the U.S.). However, it takes considerable time to build new pipe (especially cross border pipe as seen by the Keystone XL debacle and the current debate around West Coast pipelines in Canada) and some of the key issues longer term are legislative – such as the Jones Act and the impact on U.S. coastal movements of crude oil and the fact that exports of Crude oil are not allowed from the U.S. (refined products exports are). The following section delves into our views on Canada and U.S. basis differential risk in the short and long term.

The biggest impact of the oil boom will be on regional North American pricing and basis differentials.


98

Crude Glut Means Canada + PADD 2 Crudes Will See Excess Volatility & Periodic Discounting Through 2014 In the short term, basis differential risk remains very high for Canadian and PADD 2 U.S. crudes (primarily Bakken). As we published in our report on March 6, The Double Discounting Of Canadian Crudes, we expect Canadian differentials versus WTI to remain exceptionally volatile through the 2014 time frame. As depicted in Exhibit 94, volatility has been extreme with three cycles of widening differentials over the past six months. There is little doubt in our minds that we will see several more cycles over the coming months as supply pressures mount and infrastructure scrambles to keep up. With PADD 2 pretty much at full capacity, every refinery hick-up (planned or unplanned) or pipeline restriction will result in discounting – as depicted in the following charts:

Exhibit 94. Crude Pricing And Differentials

2011-2012 Crude Pricing (US$/Bbl)

$50

$60

$70

$80

$90

$100

$110

$120

$130

Jan-11

Feb-11

Mar-11

Apr-11

May-11

Jun-11

Jul-1

1

Aug-11

Sep-11

Oct-11

Nov-11

Dec-11

Jan-12

Feb-12

Mar-12

Apr-12

May-12

Jun-12

Jul-1

2

US Bakken Light WTI Syncrude Blend Dated Brent WCS

2011-2012 Crude Differentials vs. WTI (US$/Bbl)

($40)

($30)

($20)

($10)

$0

$10

$20

$30

$40

Jan-11

Feb-11

Mar-11

Apr-11

May-11

Jun-11

Jul-1

1

Aug-11

Sep-11

Oct-11

Nov-11

Dec-11

Jan-12

Feb-12

Mar-12

Apr-12

May-12

Jun-12

Jul-1

2

US Bakken Light Syncrude Blend Dated Brent WCS


Why The Canadian Discount?: Reasons for last year’s widening of the Brent-WTI differential are well documented, driven by Cushing inventories reaching very full levels in addition to the limited ability to move barrels out of Cushing into PADD III. A bigger question is: why have Canadian crudes started to discount relative to WTI? We believe there are a number of factors but the simplest explanation is that pipeline capacity into Cushing from other parts of PADD II is limited, which is backing up crudes further in the system and, consequently, discounting Canadian crude prices.


99

Volatility Highlights How Tight PADD 2 Is: The main triggers behind differentials widening or narrowing comes down mainly to refinery maintenance on the demand side and oil sands outages on the supply side. Year-to-date refinery throughput in PADD 2 & PADD 4 has averaged ~162,000 Bbls/d higher than last year. The difference is that even with higher throughput, every bit of refinery downtime is having significant pressure on PADD 2 & Canadian pricing. In our view, this provides a very clear look at how over saturated the PADD 2 market remains.

Bakken & Oil Sands Production Pressures Continue To Mount: We believe U.S. Bakken production will continue growing at ~10,000 Bbls/d–20,000 Bbls/d per month, with the natural market being PADD 2. SAGD oil sands volumes will likely continue to grow at ~7,000 Bbls/d per month in 2012 and close to 10,000 Bbls/d per month in 2013. Mining output will also receive a big boost in late 2012 with the start-up of the 110,000 Bbls/d Kearl oil sands mine. Overall, production from key plays where PADD 2 is the natural market could increase 550,000 Bbls/d–750,000 Bbls/d from current levels by year-end 2013.

PADD 2 Refinery Maintenance Will Be A Big Issue In 2012: PADD 2 refineries have been running at very robust rates to date in 2012. We are somewhat concerned by the high levels of planned maintenance in PADD 2, with current plans detailing 186,000 Bbls/d offline over the remainder of 2012 versus 85,000 Bbls/d last year and the five-year average of 131,000 Bbls/d. A similar story exists in PADD 4 where there are plans for 29,000 Bbls/d to be offline over the remainder of 2012 versus 12,000 Bbls/d last year and normal levels of ~16,000 Bbls/d. Exceptionally strong crack spreads may prompt refiners to defer maintenance as they did last year, but there are likely limits as to how far maintenance can safely be deferred.

Changing Crude Diet In PADD 2 Solidifies The Balance Of Power For Refiners: Refinery demand within PADD 2 is just embarking on a major change. ConocoPhillips (COP–NYSE) recently brought on the CORE refinery conversion project, adding ~160,000 Bbls/d of heavy capacity but displacing ~130,000 Bbls/d of light capacity. Over the next ~12 months, we will see an additional 310,000 Bbls/d of increased heavy capacity in PADD 2 at the expense of 300,000 Bbls/d of light oil capacity – at a time when light oil production is rapidly increasing. However, refiners that have added this new heavy capacity can still move back to light crude oil slates if pricing warrants such a move. With refiners gaining greater flexibility with their crude slates, there is little doubt they will use this to create “crude-on-crude” competition and drive down prices for light streams, such as SCO and Bakken, and WCS.

Seaway Provides Relief But Largely Playing Catch-up: Many investors believe that the Seaway pipeline reversal will fix the WTI-Brent disconnect and the more recent disconnect of Canadian pricing versus WTI. The more analysis we undertake, however, the more we believe this is not going to be the case. Seaway will provide some important relief but will largely be playing catch-up to existing supply pressures within PADD 2.

Keystone XL South Should Alleviate Brent-WTI Diff But Canadian Discounting Could Last Until 2014: Overall, we believe the Brent-WTI differential should largely be resolved with the start-up of the southern portion of Keystone XL in H2/13 (likely in the mid to latter part of that range). Canadian prices would rise at least partially with WTI but could still face some discounting until 2014 when either Keystone XL or Flanagan South is built (there are still capacity constraints within PADD 2 to Cushing).


100

There is no magic formula to determine the appropriate short-term discounts for WTI versus Brent and for Canadian Crudes versus WTI as this is largely uncharted territory. Directionally, we believe the market is still generally presuming 0% SCO differentials and ~20% differentials between WCS and WTI and the risk is clearly tilted toward wider differentials. We would not be surprised to see a scenario over the next 18 months whereby SCO/Bakken Light differentials bounce around a 0%–15% discount versus WTI and where WCS resides around a 15%–20% discount to SCO (i.e., a 15%–30% discount versus WTI). Where in the range the crude slates trade depends on supply build versus timing of relief valves coming online (i.e., Seaway and southern portion of Keystone XL).

Discounting Of North American Crudes Likely To Remain Long Term – But Discounting Shifts To LLS Vs. Brent Our previous report (Double Discounting Of Canadian Crudes) examined the oversupply issue facing PADD 2 through the 2014/2015 time frame. Our general view at that time was that once there was sufficient infrastructure connecting PADD 2 to PADD 3 (south part of Keystone XL and full Seaway reversal) as well as better mobility within PADD 2 (full Keystone XL and Flanagan South) that the big discounts versus global benchmarks would dissipate. As we look deeper into North American oil balances post 2014, we now believe North American oil basis differentials will remain wide over the long term – although manifesting in different ways than we are currently experiencing. We expect WTI to move towards transportation discounts versus LLS in the 2014 time frame (once Seaway and south part of Keystone XL are built) but we believe the new discount that will emerge is LLS starting to disconnect versus Brent oil.

The basic issue that will emerge in PADD 3 is an influx of oil from PADD 2 (Bakken) and Canada (Tight oil and oil sands) plus dramatic growth out of PADD 3 plays such as the Eagle Ford, Permian, Mississippi Lime and potentially other emerging plays such as the Tuscaloosa. Basically, with U.S. oil production growing ~600,000 Bbls/d per year through 2016, coupled with severe export constraints, makes a massive wave of oil supply in a large but stagnant market.

When PADD 3 Stops Importing Light Oil (In Next 6-12 Months)…The Natural Link Of LLS-Brent Dissipates Canadian companies have long looked at PADD 3 access as the Holy Grail of the North American energy markets. The appeal of PADD 3 is obvious in that it is a large refining market with 8.6 MMBbls/d of capacity, including about 3.2 MMBbls/d of heavy crude capacity.

PADD 3 remains a very import driven market and the need for imports will not likely be completely eliminated through the 2020 time frame. However, the nature of the imports is changing very quickly and will start to have an impact on Gulf Coast pricing very soon. Exhibit 95 depicts the trend of oil imports into PADD 3 by type from Q1/08 to Q1/12. As depicted, not only have imports declined but the type of crude being imported is changing meaningfully.

As we look deeper into North American oil balances post 2014, we now believe North American oil basis differentials will remain wide over the long term – although manifesting in different ways than we are currently experiencing.

Canadian companies have long looked at PADD 3 access as the Holy Grail of the North American energy markets. However, by the time we get there, it will already be flooded with light oil.


101

Exhibit 95. PADD 3 Crude Imports By Crude Type

PADD 3 Imports PADD 3 Imports - Q1/12

0

500

1,000

1,500

2,000

2,500

3,000

Q1/08

Q2/08

Q3/08

Q4/08

Q1/09

Q2/09

Q3/09

Q4/09

Q1/10

Q2/10

Q3/10

Q4/10

Q1/11

Q2/11

Q3/11

Q4/11

Q1/12

PADD 3 - Light SweetPADD 3 - Light SourPADD 3 - Med & Heavy

39%

49%

12%

PADD 3 - Light SweetPADD 3 - Light SourPADD 3 - Med & Heavy

b


While most of the decline in PADD 3 imports to date has been because of smaller draws from PADD 2, this will change dramatically over the coming years as PADD 3 production booms and PADD 2 production begins being dumped into PADD 3 following the Seaway expansion and South Keystone XL (Historically PADD 2 took about 1 MMBbls/d from PADD 3 and this will soon be completely reversed).

Exhibit 96 depicts the need for foreign oil imports into PADD 3 through 2020 based on our various scenario analyses. As depicted, within the next 12 months, there will be no need to import light sweet crude into PADD 3 (most recent monthly imports were already down to only ~532,000 Bbls/d). At this point, we believe there will start to be more pressure on LLS pricing to begin competing more aggressively with lower grade crudes that price at lower levels.

Exhibit 96. PADD 3 Foreign Oil Imports

-

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

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

Fo

reig

n O

il I

mp

ort

s In

to P

AD

D 3

(B

bls

/d)

Light Sweet Light Sour Medium & HeavyBase Case Low Growth Case High Growth Case


As depicted, within the next 12 months, there will be no need to import light sweet crude into PADD 3 (most recent monthly imports were already down to only ~532,000 Bbls/d). At this point, we believe there will start to be more pressure on LLS pricing


102

LLS – Brent Differentials…How Wide Will They Go? As we have now laid out, we believe the upcoming theme in the market will be the gradual decoupling of LLS versus Brent. As with any differential, identifying the magnitude is challenging. On the one hand, it can be argued that so long as crude is trapped in PADD 3 that we could ultimately see LLS-Brent discounts in the range of what we have seen Brent-WTI blow-out to over the past 18 months – averaging US$15.86/Bbl and ranging from US$3/Bbl-US$30/Bbl. On the other hand, factors such as crude oil blending and potential ship borne movements from Gulf Coast to East Coast should moderate the level of discount. We believe a long-term Brent-LLS discount in the US$5/Bbl range is a reasonable assumption at this point, but note that there is a high degree of uncertainty around this call. We discuss some of the influencing factors on the Brent-LLS Spread now.

LLS Will Compete Against Lower Grade Crudes: As mentioned previously, within the next six months, we will likely no longer see any requirement for light sweet imports into PADD 3, at which point, the natural link between Brent-LLS breaks (no longer need to import light sweet barrels but legislation keeps those barrels trapped in PADD 3). This implies that to a certain degree, LLS will start pricing against other lower crude slates. The following chart depicts the historic discounting of Light Sour crude (MARS) and heavy sour (Maya) in the Gulf Coast. As depicted, once light sweet is in surplus in PADD 3 (very soon), LLS will compete first against light sour imports, which historically priced ~US$4/Bbl lower than LLS. Imports of light sour would be required until roughly the 2014/2015 time frame in our base case production growth scenario but could be truncated to 2013/2014 if widespread light-heavy blending occurs (discussed below). Once light sour imports are knocked out, one can make the case for further pressure on LLS-Brent.

Exhibit 97. Heavy And Light Sour Pricing Differential Vs. LLS (US$)

($30)

($25)

($20)

($15)

($10)

($5)

$0

$5

Aug-07

Nov-07

Feb-08

May-08

Aug-08

Nov-08

Feb-09

May-09

Aug-09

Nov-09

Feb-10

May-10

Aug-10

Nov-10

Feb-11

May-11

Aug-11

Nov-11

Feb-12

May-12

Maya vs. LLS Mars vs. LLS


Shipping PADD 3 Light Oil To East Coast Refineries Or Railing U.S. Bakken Direct To PADD 1: Once the Brent-LLS spread opens up, it will start to make sense to consider moving under priced PADD 3 crude oil into the U.S. East Coast (PADD 1) refinery system by ship (i.e., from Gulf Coast to East Coast) or, alternatively, for Bakken producers to rail more volumes to PADD 1 from their current focus of railing into PADD 1.

The biggest challenge to shipping from Gulf Coast to PADD 1 is the Jones Act. Under current regulations (the Jones Act), to move crude (or refined products) between U.S. ports it must done on a U.S. built, manned and flagged ship. Needless to say there are not very many of those in existence and many of those that are, are already serving other routes. The EIA estimates there are fewer than 40 tankers capable of the Gulf Coast-East Coast route, and many of those are in operation. Additionally, there are a few new Jones Act tankers coming on later this year but there are few plans and this point to invest in the fleet expansion.

We believe a long-term Brent-LLS discount in the US$5/Bbl range is a reasonable assumption.

Within the next six months, we will likely no longer see any requirement for light sweet imports into PADD 3, at which point, the natural link between Brent-LLS breaks

Once the Brent-LLS spread opens up, it will start to make sense to consider moving under priced PADD 3 crude oil into the U.S. East Coast (PADD 1) refinery system by ship or, alternatively, for Bakken producers to rail more volumes to PADD 1.


103

The only real viable way for the option of moving discounted PADD 3 crudes to the East Coast is if the U.S. government was to waive Jones Act shipping requirements for crude oil. This would make sense in that it would help ensure the viability of East Coast refineries (lower priced feedstock), which implies job sustainability, etc. However, our understanding is there is very limited will in Washington to push for a relaxation of the Jones Act. Overall, this remains a key factor to watch but it would only make sense to ship LLS priced crudes to the East Coast if they were at a discount to Brent. However, this would likely moderate the level of discounts that could otherwise be quite substantial.

We have already seen an explosion in crude oil by rail, primarily from the U.S. Bakken into PADD 3 where producers can currently receive Brent (and LLS currently on par with Brent) type pricing. If LLS starts to discount meaningfully vs. Brent (which we expect), we will likely see more crude volumes by rail diverted directly to PADD 1 instead of the PADD 3 market. However, we believe the rail cost of going east is approximately $5/Bbl higher than going South into PADD 3 and to do this would require a build out of receiving terminals.

Simple Refinery Runs To Re-label “Crude” As “Product” To Allow Exports: Another potential factor that could in theory mitigate a Brent-LLS spread, is the ability of refiners to do very simple crude runs to effectively be able to re-label “crude oil” as “refined product”, which is allowed to be exported from the U.S. (in fact the U.S. net-exports of refined product are 2.8 MMBbls/d). A simple refinery run would basically take crude through the distillation tower, just enough refining to be able to label it as refined product.

The idea of PADD 3 refiners moving to simple runs to get around crude oil export restrictions is appealing, but likely only has limited opportunity in practicality as: 1) there are limits to excess refining capacity in PADD 3 as GOM refinery capacity is running about 88% of current capacity. While this still leaves ~1 MMBbls/d of notional capacity if PADD 3 refineries ran at 100%, but it is virtually impossible to achieve these kind of rates as a calendar day average (note that with all-time record crack spreads over the past 18 months in PADD 2, refiners have tried with utilization averaging 91%); and 2) the motivation of the refiner is not necessarily aligned with the motivation of the producer. The refiner is motivated to get as big a margin as possible, which, in all but the most dire of scenarios, would be for a refiner to take discounted PADD 3 light crude and run a full slate to export into the global market a full suite of refined product, rather than just running lower margin exports.

Refinery Blending: Refineries routinely blend different types/grades of crude oil to maximize margin. The threshold to blending is driven by a complex mix of yields and price. Refinery blending is one factor that could limit the magnitude of Brent-LLS spread but we do not see this as a specific floor value. The logic is that if light sweet oil is over-abundant in PADD 3 (which it will be), once it becomes sufficiently discounted refiners will start to blend light sweet barrels with medium-heavy barrels to approximate light sour imports. Such a measure would generally be beneficial to light sweet pricing in the near term (next few years) but would actually accelerate the rate at which imports of light to medium sour crudes are imported, and over the longer term would mean that, in the baseness of any of the aforementioned factors materializing, LLS would lose any of its link to global light oil prices.

The “Refinery X-Factor” & Balance Of Power: As highlighted before, quantifying price discounts is a complex matter. The logic is relatively straight forward when it is simply transportation and quality related. However, the third component is the most difficult to define, and that is what we term the “refinery X factor”. What we mean by this is that when a situation arises in which a product is oversupplied into a constrained market, the consumer (refineries in


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this case) have the balance of power. With hundreds of market participants all fighting for limited refinery capacity, discounting emerges and it is largely at the hands of the refiner as to where the magnitude of those discounts.

A prime example of this today is the market conditions in PADD 2. There is no quality or transportation cost that can argue why SCO and Bakken Light have averaged 4% and 9% discounts YTD vs. WTI. They are generally quite comparable quality products. The challenge though is that there are very few options outside of this market to sell their oil, and with many different sellers representing many different product slates, refineries have the ability to play sellers against each other to the detriment of pricing. Unless the U.S. government were to allow U.S. light oil exports (or as a shorter-term issue waive Jones Act requirements to at least move more crude across U.S. ports), the same type of dynamic will emerge in PADD 3. We do note however that the PADD will not be as dire as the current PADD 2 situation as PADD 3 will still need to import crude oil through 2020 (just low amounts and increasingly weighted towards heavy).

The Fight For Refinery Access In PADD 3, Lots Of Coking Capacity But Refiners Have Flexibility: PADD 3 is the largest Coking market in the world with approximately 3.2 MMBbls/d of heavy oil capacity. With this much installed capacity, it seems quite a natural fit for lower-quality Canadian crudes such as WCS or for continued intake of Maya. However, just because PADD 3 is home to significant coking capacity, doesn’t mean it will all be used. Any refinery that has coking capacity can take a higher-quality crude oil slate (the opposite clearly doesn’t hold true though). There are many tradeoffs involved in the equation but it basically boils down to margin. A high complexity coking refinery may opt to run at slightly lower rates by taking a higher slate of light oils. The decision will be governed almost entirely by their margin analysis, which would incorporate the higher yield typically obtained from a lighter barrel together with factors such as lower wear and tear on the refinery and fewer catalyst costs, etc. In our discussions with refiners, we have typically heard that heavier barrels like Maya could not sustain a differential vs. light barrels of anything beyond US$5-US$9/Bbl. Indeed this seems to correlate with historical Maya vs. LLS differentials, which have averaged in the US$10/Bbl range. The overall point from this discussion is that there will be significant competition from not only WCS vs. Maya for access to the PADD 3 market, but also for light oil trying to get access to higher complexity refineries. As discussed previously, this multifaceted competition shifts the balance of power to the refiners – which they will use to their advantage (as we have seen already in PADD 2).

WTI-LLS Differential Should Approximate Marginal Transportation Cost To Gulf Coast As highlighted previously, we believe LLS-Brent will move from transportation equivalent pricing to LLS gradually moving to a ~US$5/Bbl discount versus Brent. As we move further inland, pricing will continue to be further discounted from a combination of pipeline tolls and potentially further discounts if pipeline capacity lags production growth. From a transportation standpoint, we believe there is little risk beyond 2014 in terms of capacity out of Cushing into the Gulf Coast. By this point, Seaway will be fully reversed and the south part of Keystone XL will be on-stream. Furthermore, Seaway twinning will be well advanced and the market will have gotten over the “surprise” of Bakken growth and better able to accommodate growing pipeline needs from PADD 2 into PADD 3.

There will be significant competition from not only WCS vs. Maya for access to the PADD 3 market, but also for light oil trying to get access to higher complexity refineries. A complex refiner will take light oil…if the price is right.


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With this backdrop, WTI discounting to LLS should be relatively close to marginal pipeline shipping costs (i.e., what an uncontracted party would pay to ship on those pipelines). From this perspective, WTI should be discounted in the US$4/Bbl-US$5/Bbl range versus LLS reflecting pipeline tolls and bringing the long-term Brent-WTI differential to the ~US$10/Bbl range (~US$5/Bbl LLS plus ~US$5/Bbl transportation costs). In periods where production capacity has outpaced pipeline capacity start-ups, differentials will temporarily balloon to the US$15+/Bbl range (similar to what we have seen over the past 18 months).

Consensus Brent-WTI Diffs Likely Too Low While much attention has recently been shone on the high growth out of U.S. oil plays, we believe the market impact is still in the early stages of being understood. We won’t claim to be the first to postulate on the growing LLS-Brent and WTI versus LLS discounts – but we are far from the last. Current consensus long-term Brent-WTI differentials are currently ~US$3/Bbl from Canadian brokers.

Given our view of long-term Brent-WTI differentials sustaining more in the US$10/Bbl range (~US$5/Bbl Brent-LLS plus ~US$5/Bbl transport to Cushing), we clearly believe that over the coming months/years that consensus WTI and Canadian price expectations will consistently be revised down – a death by a thousand cuts kind of theme. Consensus WTI forecasts declining by US$5/Bbl-US$10/Bbl has meaningful impacts on producer cash flows and profitability and may continue to hamper equity performance until fully embedded.

Consensus View Of Medium- To Long-term Refining Margins Likely To Widen As much of our call for wider differentials is generally negative for upstream players, it is generally very bullish for downstream players (or relatively neutral for integrateds). There is no official consensus available for Mid-Continent or U.S. Gulf Coast refining margins, but generally we believe the street is modeling supernormal margins to continue in 2012 and 2013 but generally normalizing thereafter. For context, Mid-Continent spreads that are currently over US$30/Bbl would eventually come back to the ~US$12/Bbl range that they averaged pre-2010. If Brent-WTI stays in the US$10/Bbl range long term as we are forecasting (US$5/Bbl for Brent-LLS plus US$5/Bbl for LLS-WTI), we are effectively arguing that mid-continent spreads will remain ~US$10/Bbl elevated vs. historical ranges and even Gulf Coast spreads will see meaningful improvement.

Canada Will Need Big Pipe Build To Escape Long-term Discounting Before we can begin any discussion on longer-term Canadian discounts, we must emphasize a key point. Canada NEEDS pipe. U.S. pipe, West Coast Canada pipe, East Coast Canada pipe – we need it all. If pipe is built, Canadian netback pricing can be reasonably estimated off anticipated transportation costs which we discuss in the following sections. If pipe is not built, Canadian crude prices will be sustained at very low pricing vs. WTI (which already expect to stay ~US$10/Bbl off Brent long term). In this scenario, pricing would have to go low enough to knock out much of the anticipated growth – particularly from the oil sands.

WTI should be discounted in the US$4-US$5/Bbl range versus LLS reflecting pipeline tolls and bringing the long-term Brent-WTI differential to the ~US$10/Bbl range (~US$5/Bbl LLS plus ~US$5/Bbl transportation costs).

Current consensus long-term Brent-WTI differentials are currently ~US$3/Bbl.


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Time To Smoke The Peace Pipe – Plenty Of Proposals On The Table But Political Risk Mounting CIBC’s pipelines analyst Paul Lechem published a very detailed report on longer-term pipeline initiatives in early March and will provide a more detailed follow-up in the not too distant future (reflecting TransCanada’s emerging plans and recent Enbridge announcements). The general conclusion is that there are plenty of pipeline proposals on the table longer term but many of those proposals are facing increasing levels of political risk. The following table provides an overview of the main current export proposals.

Exhibit 98. Proposed Long-haul Pipeline New Build/Expansions

Pipeline Routing Capacity (Bbls/d) CommentsKeystone XL Hardisty, AB to Port Arthur, TX 830,000 Presidential permit denied; will reapply upon re-routing in

Nebraska. Potential in-service early 2015

Northern Gateway Bruderheim, AB to Kitimat, BC 525,000 (crude) 193,000 (diluent)

Public/regulatory hearings begun Jan/12, regulatory decision expected late 2013; potential in-service 2017

TMX Edmonton, AB to Burnaby, BC 450,000 Open season completed; regulatory decision expected late 2014; potential in-service late 2016

Alberta Clipper Expansion

Hardisty, AB to Superior, WI 350,000 No new pipe required - additional pump capacity only; initial expansion of 120,000 Bbls/d underway; mid-2014 in-service date

TransCanada Mainline Conversion

Hardisty, AB to Montreal, PQ 600,000 (est.) Analysis underway for potential partial conversion of existing gas Mainline to oil service. In-service 2016 (est.)

Total 2,755,000 (crude) 193,000 (diluent)

Source: Company reports and CIBC World Markets Inc. (Paul Lechem)

Sadly, all but the Albert Clipper expansion remain mired in politics. Any decision on the main portion of Keystone XL is unlikely until early in 2013. Rhetoric towards both the West Coast pipelines is running rampant and at this point we would regard the West Coast pipelines as no better than 50/50 odds that they are built before the end of this decade. Even though the federal government ultimately maintains the right to push the projects through, we are not fully convinced the political will is lasting long term – particularly if the B.C. provincial government opposes the pipeline. TransCanada’s emerging plan to convert a portion of its West-East gas pipelines to oil service is appealing in many ways, but it’s still too early to gauge the risks/benefits for sure.

Pipeline Pinch-point Not That Far Off… Exhibit 99 depicts anticipated production growth versus proposed pipeline capacity. For production growth, we use CAPP forecasts as well as unrisked company expectations (i.e., the sum of individual company forecasts) in addition to our own outlook, which is roughly the midpoint between CAPP and unrisked forecasts.

A key observation in the shorter term is that the pipeline pinch-point (i.e., when we run out of export capacity) that industry generally highlighted as being 2015/16 could arrive much sooner if the higher growth forecasts unfold. We estimate that the pipeline pressures really could hit in the 2014 time frame – illustrating that there is NO room for further slippage of the Keystone XL build.

We estimate that the pipeline pressures really could hit in the 2014 time frame – illustrating that there is NO room for further slippage of the Keystone XL build.


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From a longer-term perspective, the key observation is that it is virtually impossible for companies to execute the sum of their plans as even with every pipeline that is currently proposed is built, there would still not be enough capacity. Additionally, in our view, the two proposed West Coast pipelines still face considerable political and regulatory risk. TransCanada’s East Coast pipeline (conversion of natural gas lines) is still at a very early stage and therefore more difficult to count on and could also face additional political risk – particularly the element of exporting oil sands output from Quebec City. Overall, this once again highlights the need for rationalization of growth expectations down to available pipeline capacity. The only question is, does that mean industry growth expectations through 2020 need to be cut by 1 MMBbls/d or 3 MBbls/d (only Keystone XL gets built).

Exhibit 99. Canadian Oil Growth Scenarios Versus Pipeline Capacity

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2011 2012E 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

Oil

Ex

po

rts

(Mb

bl/d

)

CAPP Company Forecasts CIBC EstimatesCurrent Capacity TranscCanada Keystone XL Kinder Morgan TMXEnbridge Northern Gateway TransCanada Eastern Canada Enbridge Mainline Expansion 1Enbridged Mainline Expansion 2

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

The key takeaway from this analysis is that our current long-term forecasts of Canadian light oil discounting versus LLS of ~US$7/Bbl could face considerable risk if any of the aforementioned pipelines are cancelled or face long-term delays.

Canadian Light Should Price A Transportation Discount To Gulf Coast Or Cushing…If Pipe Is Built We have already established the likely widening of Gulf Coast (LLS) pricing versus Global pricing (Brent) and further discounting of WTI versus LLS. What then for Canadian crudes? Western Canadian crudes will largely be tied to a combination of Cushing and Gulf Coast pricing. Transportation costs on Keystone XL are estimated at US$7/Bbl for light oil and approximately US$9/Bbl-US$10/Bbl for heavy oil and similar costs for the Enbridge Flanagan South and Seaway lines. Off LLS of US$90/Bbl (our current long-term assumption) this implies Canadian light oil pricing of US$83/Bbl range. However, we note that this assumption is only valid presuming pipeline growth keeps pace with production growth – which is a bigger risk for Canadian crudes than for PADD 2 crudes.

We assume Canadian crudes price at transportation discounts vs. U.S. long term, but this assumption is only valid if pipelines are built - which is a bigger risk for Canadian crudes than for PADD 2 crudes.


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Exhibit 100. Light Oil Pricing Map

Kitimat

Chicago

Flanagan

Cushing

Houston

Brent @$95/Bbl

SCO Sold Into PADD 2: $86-$86.50/BblSCO Sold Into PADD 3: $82/BblSCO Sold Into Asia: $86-$87/Bbl

SCO Sold Into California:$87-$88/BblSCO Sold Into East Coast US: $87/Bbl

LLS ~$90 /Bbl

Light Transportation

Cost ~$3-$5/Bbl (South

Segment Only)

Light Transportation Cost From Ed To Cushing: ~$3.50-$4.00/Bbl

Light Transportation Cost From Ed to GC: $8/Bbl

($4.00-$5.00)

($4.00-$5.00)

SCO in Cushing approximates WTI: ~$90/Bbl

SCO In Asia Would Likely Sell At Brent: ~$95/Bbl

Estimated Cost via VLCC to Asia~$3/Bbl

Estimated Cost via. VLCC From Kitimat to California: ~$1.00/BblEstimated Cost using Afromax From Vancouver to California: ~$1.50/Bbl

SCO Into California Would Likely Sell At Brent + Transport From Mid-East or Light oil From GC :

~$96-$97/Bbl Or Light

Estimated Costs To East Coast In The ~$8/Bbl Range


WCS…A More Complex Dynamic Pricing out WCS is a more complex equation. On the positive side, as we noted in our report, Double Discounting Of Canadian Crudes, we expect heavy oil demand to increase in late 2012 as new coking projects come on-stream in PADD 2. As summarized in Exhibit 101, these projects will add an incremental 470,000 Bbls/d of potential demand for heavy crudes, while simultaneously displacing 430,000 Bbls/d of light crude oil demand. While this is directionally encouraging for heavy oil producers, we note that refiners are not obligated to take heavy oil when the cokers come on-stream and will instead optimize crude inputs for the best combination of price and yield. In effect, this implies that WCS differentials may narrow to the US$5/Bbl-US$9/Bbl range versus SCO or Bakken Light, but due the big pressure on these price streams WCS pricing will also find itself under pressure (i.e., WCS is less worse off than light streams but still not better than current consensus expectations).


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Exhibit 101. PADD 2 Coking Projects

Refinery Timing

Chg. In Light

Capacity ('000 Bbl/d)

Chg. In Heavy

Capacity ('000 Bbl/d)

Overall Capacity Change

('000 Bbl/d)

Conoco - Wood River CORE Ramping up in Jan/Feb 12 (130) 160 30Marathon - Detroit HOUP Late 2012 (70) 80 10BP - Whiting Refinery Modernization Project H1/2013 (230) 230 0Total (430) 470 40


The WCS environment changes once again as industry gains access to PADD 3. As discussed previously, PADD 3 is a natural market for WCS given the high amount of coking capacity that exist in that market and lack of heavy oil production. Fundamentally, PADD 3 refiners have a strong desire to run WCS (reasonably equivalent to Mayan crude). However, as we have seen in PADD 2, when one oil slate is in oversupply, it can bring pressure on the whole oil complex as refiners play crude slates against crude slates (see prior comment entitled “Balance Of Power Impacts Pricing”). In PADD 3, the emerging big pressure on LLS will likely also put some downward pressure on Maya. In general, we believe that Maya will not likely price better than US$5/Bbl-US$9/Bbl off LLS (this historical Brent-Maya differential is US$9/Bbl), which in our conversations with refiners we understand to be the rough half-cycle costs for a refiner with cokers electing to take a light oil crude slate.

Given this relationship, we can infer that once Canadian producers get access to the PADD 3 market, they will get the Mayan price link they have long sought – but unfortunately Maya will not be as high priced as it had been historically due to the big discounting of light oil in PADD 3. Our best estimate is that off Brent, LLS will price ~US$5/Bbl lower and Maya ~US$5-US$9/Bbl below LLS and transportation costs to Western Canada are approximately US$10/Bbl. In an unconstrained transportation environment, this would imply WCS US$71/Bbl-US$75/Bbl or 75%-77% of Brent and 83%-88% of WTI.

WCS Vs. Maya – Quality Differentials A Question Mark It has generally been assumed that WCS will price quite closely against Mayan crude once Canadian producers get their much needed access to the PADD 3 market. However, even this is open to interpretation and will not be fully answered until we see large deliveries into this market. On the surface, WCS and the newly introduced Christina Lake Blends [Access Western Blend (AWB) marketed by MEG and the Christina Lake Blend (CLB) marketed by Cenovus] are both quite similar to Maya as illustrated in the following table. Just looking solely on an API basis it would appear that Maya is slightly higher quality. However, when adding the sulphur content into the picture, and arguably more important the Total Acid Number [(TAN) – measuring the crude’s content of milligrams of KOH per gram of product], a question mark emerges on actual price comparability.

Fundamentally, PADD 3 refiners have a strong desire to run WCS, which is bullish for light-heavy spreads. However, we believe that the pressure on light pricing will still result in lower WCS pricing than we had previously modelled.


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Exhibit 102. Global Heavy Crude Oil Product Quality

API Sulphur TAN Avg Discount(Degrees) (%) (mg/g) (USD)

Oriente 29.2 0.88% 0.39 ($8.54)Arab Heavy 27.4 2.80% 0.10 ($6.88)Djeno 27.0 0.47% 0.77 ($4.50)Vasconia 24.5 1.01% 0.30 ($3.20)Souedieh 24.1 3.90% 0.15 ($11.39)Maya 22.2 3.30% 0.28 ($9.92)Access Western Blend (AWB) 21.8 3.94% 1.7 naChristina Dilbit Blend (CDP) 20.9 3.73% 1.49 naWestern Canada Select (WCS) 20.6 3.49% 0.93 na


There are many factors at play in crude quality differentials, ranging from refinery yield and price/desire for those feedstocks vs. refinery wear and tear, etc. In our research, we found an interesting study taking a statistical approach to global crude oil discounts (ESMAP Technical Paper 081 – Crude Oil Differentials and Differences in Oil Qualities), incorporating API, sulphur and TAN. We back-tested this against several grades of global heavy oil and found that the statistical relationships still hold strongly even though the study was conducted in 2005. Using this multiple regression, the predicted discount of Maya vs. Brent is ~US$10.60/Bbl vs. the US$10/Bbl actual. The same study applied to Arab Heavy implied a US$6/Bbl discount vs. Brent vs. the actual of approximately US$6.80/Bbl. Overall, we conclude that while not perfect, it is a reasonable basis for quality discount assumptions. Applying the crude characteristics in the aforementioned table to WCS and AWB/CLB would imply discounting vs. Maya in the US$4.75/Bbl range for WCS and ~US$8/Bbl for AWB/CLB. For purposes of our netback analysis, we have assumed US$2.40/Bbl for WCS (mid-point of zero discount and our calculated) and US$4/Bbl for AWB/CLB (mid-point of zero discount and US$8/Bbl calculated). The point of this analysis is to highlight that the comparability of Canadian heavy crudes vs. Maya does arguably carry more risk than the market recognizes.

The pricing for WCS into Asian markets or California is somewhat of a question mark. One of the more transparent heavier crudes into Asia is Arab Heavy. Using the pricing relationship established previously, it would be reasonable to assume meaningful quality discounts for WCS or AWB/CLB vs. this blend reflecting the significantly higher sulphur content and higher TAN. Our best estimate is that WCS would price ~US$9/Bbl off Arab Heavy and that AWB/CLB would price up to US$12/Bbl off Arab Heavy. For the purposes of our netback analysis, we have assumed US$6.75/Bbl discount for WCS and US$9/Bbl for AWB/CLB.

Applying the crude characteristics in the aforementioned table to WCS and AWB/CLB would imply discounting vs. Maya in the US$4.75/Bbl range for WCS and ~US$8/Bbl for AWB/CLB.


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Exhibit 103. Heavy Oil Pricing Map

Kitimat

Chicago

Flanagan

Cushing

Houston

Brent @$95/Bbl

Price (After Transport) Selling To: Cushing Or GC: $68-72/Bbl for WCS & $67-$71/Bbl for AWB

To California: ~$75-79/Bbl fpr WCS & $72-$76/Bbl for AWBTo Asia: ~$73-77/Bbl for WCS & ~$75-79/Bbl for AWB

LLS ~$90 /BblLLS-Maya Discount - $5-$9/bbl

Maya $81-$85/bbl

Heavy Transportation

Cost ~$3-$5/Bbl

Heavy Transportation Cost From Ed To Cushing: ~$4-6/Bbl

Heavy Transportation Cost From Ed to GC: $8-$10/Bbl

$5.00-$6.00

$5.00-$6.00

Maya in Cushing ~ $76-$82/BblWCS in Cushing ~$68-$72/Bbl (Slightly higher TAN)AWB or CDB ~$67-71/Bbl (Significantly higher TAN)

Arab Heavy $88/Bbl (~$7/Bbl Discount)WCS Would Likely Sell ~$4.50-$9.00/Bbl Quality DiscountAWB/CLB Would Likely Sell ~$6-12/Bbl Quality Discount

WCS ~ $73-77/BblAWB/CDB ~ $71-75/Bbl

Estimated Cost via. VLCC to Asia~$3/Bbl

Priced Off: Arab Heavy $88/Bbl (~$7/Bbl Discount) or Maya + Transport ~$88/BblWCS Would Likely Sell ~$4.50-$9.00/Bbl Quality DiscountAWB/CLB Would Likely Sell ~$6-12/Bbl Quality Discount

WCS ~ $75-$79/BblAWB/CDB ~ $72-$76/Bbl

Estimated Cost via. VLCC From Kitimat to California: ~$1.00/BblEstimated Cost using Afromax From Vancouver to California: ~$1.50/Bbl


New Market Access (East Coast Canada Or West Coast) Keep Pricing From Blowing Out But Don’t Lead To Big “Upside” As depicted in the previous exhibits, opening up new market access whether it is through one or both of the proposed new West Coast lines, improved access to PADD 3 or even the newly proposed TransCanada East Coast line (converting gas pipeline to oil) are absolutely necessary for Canadian crudes. One generally held view is that this new market access will lead to substantial improvements in Canadian pricing. In our view, that is not necessarily the case as relatively high transportation costs on new build pipelines combined with some degree of quality discounting leads to acceptable pricing for Canadian crudes, but certainly not “better” than we have seen in recent history (other than the extremes we have seen thus far in 2012). No doubt this new market access will see improved prices or lower discounts than we are seeing today, but not necessarily significantly tighter discounting than we saw in 2010-2011. Overall, the big value of these new pipelines is ensuring that Canadian pricing doesn’t turn into a complete disaster – which would be the case if adequate pipelines are not built and producers were stuck competing for very limited access.


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What About Canadian Exports Through U.S. Ports? The U.S. has adequate pipelines to handle large-scale light oil exports – if it were allowed by law. Canada allows oil exports, but lacks the pipelines to connect large scale volumes to deep water ports. What about exporting Canadian barrels through U.S. ports? This is an idea that is gaining some traction, but there are some real world limitations to implementation. First, the U.S. apparently has been very strict around the legalities of Canadian crudes transiting through U.S. territory, allowing exports only if shippers could guarantee that the Canadian crudes did not contact U.S. crudes in the shipping process – almost an impossibility on a shared pipeline. If the U.S. government sticks to this view, large-scale exports via the U.S. are nearly impossible. Rail would be the one exception though where shippers can guarantee that Canadian oil has not come in contact with U.S. crudes. The limitation to this of course is rail availability on a large scale. Overall, we believe exports of Canadian crudes through U.S. ports will remain a niche play.

Rail – Riding The Rails To Riches Or Just Riding? Rail has emerged as an important piece of the North American oil transport puzzle. No published sources break out oil volumes by rail but total oil & products is available as depicted in the chart below. We can assume that most of the big increases since the start of 2011 are due to rising crude oil volumes (although there are likely more product movements too reflecting East Coast refinery closures). Overall, we would conclude that approximately 50,000-75,000 Bbls/d is moving by rail in Canada and approximately 259,000 Bbls/d in the U.S. – a large volume.

The appeal of rail in the current environment is obvious. As a producer in PADD 2 (primarily Bakken) or in Canada, being able to circumvent Cushing and sell into higher priced markets like the Gulf Coast can lead to big pricing uplift. We see rail continuing to offer some degree of arbitrage into the 2013 time frame. However, if we are correct in our thesis and the Brent-LLS does start to widen out and LLS-WTI ultimately goes back to transportation differentials (still in the US$3-US$5/Bbl range), the value of rail is lessened as the high price Brent market is no longer available. LLS will still price US$3-US$5/Bbl vs. WTI but not likely a big enough gap to justify large rail costs, unless pricing North of Cushing (Bakken and Canada) are discounted due to lack of pipeline capacity – which would be a factor if Keystone XL does not get built.

Exhibit 104. Oil & Petroleum Products Volumes By Rail

0

100,000

200,000

300,000

400,000

500,000

600,000

Jan

Jan

Feb Feb Mar Mar AprApr

AprMay May Ju

nJu

n Jul

Jul

AugAug

Sep Sep Sep Oct Oct NovNov

Dec Dec

Canada - 2011 Car Loads - Bbls/dCanada - 2012 Car Loads - Bbls/d

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

Jan

Jan

Feb Feb Mar Mar AprApr

AprMay May Ju

nJu

n Jul

Jul

AugAug

Sep Sep Sep Oct Oct NovNov

Dec Dec

USA - 2011 Car Loads - Bbls/dUSA - 2012 Car Loads - Bbls/d

Source: Association of American Railroads and CIBC World Markets Inc.

The U.S. apparently has been very strict around the legalities of Canadian crudes transiting through U.S. territory

The appeal of rail in the current environment is obvious. If our call on differentials is correct, the economic advantage that we see from rail today will dissipate…but it still provides an important insurance policy against pipelines not getting built.


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Although the rail financial arbitrage will likely dissipate, we believe there is a permanent role for rail in the North American transportation mix. The advantage that many producers have observed is having more flexibility to reach different markets – and that is a key offering of rail vs. pipelines. Most likely once the Brent-LLS spread widens, we will see a shift of big Bakken volumes moving from the Bakken and Canada down to PADD 3 to a gradual focus to moving into PADD 1

Politics Can Improve Some Of The Potential Discounting…But Don’t Count On It A clear takeaway from our discussions thus far is that at least some of the discounting for North American crudes can be solved by simple changes to U.S. government policy – whether those changes be a relaxation of the Jones Act to facilitate shipping between U.S. ports, allowing exports of U.S. crudes or even easing restrictions surrounding exports of Canadian crudes through U.S. ports. The biggest area of impact to change in government policy would be on the potential for LLS vs. Brent disconnect, although we note that some discounting would still be required to prompt actual movement of barrels from PADD 3 to PADD 1, but likely more in the US$2-US$3/Bbl range vs. the US$5/Bbl range we are currently assuming. We note that this, or any other political decision, would not likely impact our view of LLS-WTI (transportation differential) or discounting back to Canada, which we have also modeled on the basis of transportation differentials.

Mexico & Venezuela…No Threat To PADD 3 Market In Short Term But Not Necessarily Out Of The Picture Declining production from Mexico, particularly for heavy oil, has created a bullish backdrop for heavy oil pricing in PADD 3. For Venezuela, the story is a bit different. Oil production (primarily heavy oil) is growing but increasingly, for political reasons, Venezuela is marketing its heavy oil to Asia (China in particular). While nobody is expecting a short-term rebound in Mexican or Venezuelan heavy deliveries into the Gulf Coast, one cannot remove them from the equation completely.

Exhibit 105. Mexico & Venezuela Production/Exports To U.S.

Mexico Production Venezuela Production

500

1,000

1,500

2,000

2,500

3,000

Jan-10

Mar-10

May-10

Jul-1

0

Sep-10

Nov-10

Jan-11

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Jul-1

1

Sep-11

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MB

bls/

d

500

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2,000

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MB

bls/

d

Exports To USA (Right)Heavy LightTotal

500

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2,500

Jan-10

Mar-10

May-10

Jul-1

0

Sep-10

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Jan-11

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1

Sep-11

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May-12

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bls/

d

500

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1,500

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MB

bls/

d

Exports To USA (Right)Total


For Mexico, the issue on growing production is not a lack of resources as the country has an estimated 10.4 billion barrels of proved reserves with large unexplored potential. It is primarily funding issues surrounding Pemex combined with political squabbling. With a new government in Mexico, the factor to watch is whether or not there are any changes to funding/levels or more aggressive development plans. For Venezuela, the key issues are the next election and


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whether or not Chavez survives to that date. Recent headlines from opposition leaders suggest they would move to end Venezuela’s “preferential oil deals” – such as the deal they have to ship Venezuelan heavy crude to China. It remains to be seen if this is pure rhetoric or if this could mean the potential for more Venezuelan crude to be aimed at the U.S. market. PDVSA (Petroleos de Venezuela S.A.) estimates that 43% of its crude was marketed under these types of “preferential deals” that it is not paid directly for.

In the short term, little is unlikely to change for either country as increasing production in any meaningful way is relatively long cycle time. However, over the medium to longer term though this is still a real risk – that one or both countries finds its way back to growth. As the U.S. represents a whopping 55% of global coking capacity and the next largest market (other than Venezuela or Mexico) is Asia, which is 9,300 miles further away, this implies the U.S. GOM will remain THE destination of choice for Venezuelan, Mexican and Canadian heavy oil – with all producers fighting for share of the same market (that is already over-saturated with light barrels).

Exhibit 106. Global Coking Capacity

US 55%Venezuela 3%

Rest of World (113 Countries) 26%

China 3%Brazil 2%

India 4%

Japan 3%

Mexico 4%

Source: Oil & Gas Journal.

Oil Supply/Demand Balances Key Takeaways North American Growth Takes Some Pressure Off Global Balances: Consensus forecasts are for North American oil growth of ~340,000 Bbls/d per year through 2015 vs. our forecasts of closer to 800,000-900,000 Bbls/d per year. Incorporating our estimates into consensus supply demand balances would imply a relatively flat “call on OPEC” through 2015 (typically corresponding to flat prices). Additionally, spare capacity would grow meaningfully which could take some of the risk premium out of oil prices.

Oil Renaissance Will Continue To Have Big Impact On Regional Price Discounts: The biggest impact of the North American oil renaissance is the impact on regional price discounts and flows. We are already seeing this in PADD 2 and Canada where crudes have been extra volatile and often selling at large discounts vs. benchmarks. This trend will continue long term but the pinch-points will change over time.


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Canada & PADD 2 Discounts To Remain Through 2014: We continue to believe that Canada and PADD 2 crudes will remain very susceptible to discounting through the 2014/15 time frame (when the full Keystone XL is built and Flanagan/Seaway). PADD 2 and pipe within PADD 2 are at capacity, meaning any pipeline curtailment or refinery outage will lead to meaningful discounts. Once the aforementioned pipes are built, we should see Canadian crudes settle into a transportation discount vs. WTI and LLS.

PADD 2 Problems Will Soon Turn To PADD 3 Problems: PADD 3 is already nearly awash in light sweet crude (Eagle Ford, etc.). When Seaway and the south portion of Keystone XL are on-stream, PADD 2 will be sending over 1 MMBbls/d of crude into this market (a good portion of that being light) – fully saturating the market. As it is prohibited by law to export crude oil from the U.S., this means that PADD 3 will become a trapped market for light oil and will soon lead to discounting of LLS to Brent.

We Estimate WTI-Brent In US$10/Bbl Range Long Term: We recently changed our long-term oil price forecasts to reflect a US$10/Bbl discount of WTI vs. Brent, which consists of a US$5/Bbl discount for LLS-Brent plus ~US$5/Bbl transport differential back to Cushing.

No Crude Is Untouched By This Theme: Generally speaking, there will be strong desire for Canadian heavy crudes by PADD 3 refiners, but this by no means WCS has a “reserved” spot in the PADD 3 refinery system. Complex heavy refiners can (and will) take light oil over heavy for the right price – leading to competition for this coveted refinery space. Directionally we believe WCS pricing is less impacted by this theme, but still impacted nonetheless as it is weighed down to a certain degree by pricing on the light complex.

Canadian Crudes Should Price A Transportation Discount; But Only If Pipe Is Built: If adequate pipeline capacity is built, Canadian crudes should trade at transportation costs vs. U.S. equivalent crudes (SCO vs. WTI and WCS vs. Maya with slight quality adjustment). If pipeline capacity is not built, then Canadian prices will move to discounts large enough to eliminate much of the anticipated demand growth – a disastrous scenario for Canadian producers.

Time To Smoke The Peace Pipe: There are adequate proposals being considered to move Western Canadian crudes to the U.S. and new markets such as Asia, California or the East Coast U.S. However, political risk and rhetoric is clearly ramping up, particularly against the crucial West Coast pipelines. We give only 50/50 odds (at best) of West Coast pipe being built before the end of the decade.


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North American Natural Gas Supply/Demand Balances The natural gas market remains in a state of flux, transitioning from a period of hyper supply growth with limited demand growth. What comes next for natural gas? We believe the future looks more optimistic than we have seen in recent years as lower gas prices lead to a gradual structural shift in natural gas demand.

In contrast to the North American oil story, where demand is expected to remain relatively flat, there are many more outcomes on the natural gas demand profile. Natural gas demand growth could range from modest to very large but depends on other macro variables (oil prices and coal prices to name a few). On the demand side of the equation, there are really three major swing factors that will impact the demand outlook through the 2020 time frame: 1) natural gas demand for oil sands; 2) natural gas demand for power generation; and 3) exports of North American gas via LNG. Natural gas demand for transportation remains a wild card but we believe this is still likely a bigger driver in the 2020+ time frame.

Demand Drivers Oil Sands Canadian natural gas production is expected to remain relatively stagnant as reinvestment remains primarily targeted towards tight oil and oil sands growth. On the demand side though, things are different. Oil sands growth will continue to drive significant demand for natural gas in Western Canada. As identified in the previous sections, the outlook for oil sands growth remains highly variable reflecting the higher cost structure vs. other North American oil growth and higher transportation costs and need for infrastructure build. Depending on the oil sands growth scenario, we can see natural gas demand for oil sands rising by 0.2-0.4 Bcf/d per year from 2011 to 2016 (1-1.6 Bcf/d growth in absolute terms) and 0.2-0.6 Bcf/d per year from 2016 to 2020 (0.8-2.4 Bcf/d in absolute terms). The low end of forecasts corresponds to oil sands growth being rationalized to CAPP forecast levels which are roughly equal to capacity if Keystone XL is built. The CIBC case is roughly the mid-point of these lower scenarios and company forecasts (which we present as the unrisked case).

Exhibit 107. Natural Gas Demand Growth For Oil Sands

0.000.501.001.502.002.503.003.504.004.505.005.506.00

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

Gas

Con

sum

ptio

n (b

cf/d

)

Producer Forecast CIBC Forecast CAPP Forecast

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

Depending on the oil sands growth scenario, we can see natural gas demand for oil sands rising by 0.2-0.4 Bcf/d per year from 2011 to 2016 (1-1.6 Bcf/d growth in absolute terms) and 0.2-0.6 Bcf/d per year from 2016 to 2020 (0.8-2.4 Bcf/d in absolute terms).


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Power Generation – Directionally Higher But Views Differ On Magnitude We have seen recently just how big of a factor power generation can be to the natural gas market. Recent displacement of coal generation by natural gas has led to an impressive 5 Bcf/d (24%) increase in gas demand Y/Y over the past six months. These gains are extremely price sensitive and most of this market share will likely revert back as natural gas prices climb. However, it does highlight the importance of the power sector to natural gas and foreshadows the structural shift in natural gas demand that will continue to unfold over the long term.

It is no secret that retirements of coal-fired power generation facilities are going to be quite meaningful over the coming years. However, some of this outlook depends on the upcoming U.S. election. An Obama victory would see the retirements happen on schedule while a Republican victory would likely see an easing of Environmental Protection Agency (EPA) requirements to retire coal fired facilities. The following chart from the EIA depicts what is currently scheduled to come offline over the coming years and, as depicted, there is approximately 18 GW of capacity schedule to come offline from 2013-2016 which would translate to approximately 1.7 Bcf/d of gas demand (if made up by higher gas generation which is a reasonable assumption).

Exhibit 108. Historical & Planned Retirements Of Coal-fired Generators

Source: EIA.

Natural gas will clearly make very meaningful in-roads into the US power mix over the coming years. But what does this actually mean for natural gas demand? Here is where the opinions vary quite considerably. Exhibit 109 depicts the outlook from both the EIA and from IHSCera. The EIA is projecting demand growth of 0.26 Bcf/d per year from 2011-2016 and relatively flat thereafter. On the more optimistic side, IHSCera is forecasting 0.9 Bcf/d per year growth from 2011 to 2016 and 1.2 Bcf/d per year from 2016 to 2020.


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Exhibit 109. Gas Demand For Power Generation – Differing Views

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

2001

2002

2003

2004

2005

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2008

2009

2010

2011

2012

E20

13E

2014

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2016

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2020

E

Mm

cf/d

IHSCeraEIA Long-Term Energy Outlook 2012

Historically - 0.6 Bcf/d Per Year Growth

Forecast Growth Varies from 0.1-1 Bcf/d Per Year


Overall, we have based our forecasts on 0.6 Bcf/d per year demand growth from 2011 to 2020, which is based on historical growth rates plus roughly mid-point between EIA and IHSCera forecasts. We note that one of the reasons for the more conservative EIA outlook is its view that renewables grow from 10% of the U.S. power mix to 14% by 2020. If renewables were maintained at 10% rather than growing to the 14% range as forecast by the EIA, the increment would most likely be made up by natural gas which would add ~3.5 Bcf/d (0.4 Bcf/d per year to their growth forecasts) for natural gas.

Exhibit 110. Electricity Generation By Fuel: 2010-2020

Source: EIA.

LNG – The Race Is On We believe North American LNG is going to emerge as a meaningful outlet for North American gas supply in the latter half of this decade. We have published two very detailed reports on LNG, with the most recent being published in January 2012 (LNG - The Race Is On). Our views and projections on LNG are summarized below.

Overall, we have based our forecasts on 0.6 Bcf/d per year demand growth from 2011 to 2020.


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As Expected; LNG Emerging As A Major Theme In 2012: We highlighted that a dominant theme in 2012 will be North American LNG moving from dream to reality. With the Sabine Pass facility recently just passing Final Investment Decision (FID), we now have one facility under construction. Kitimat has been delayed somewhat (from mid-2012 FID to tentative late 2012/early 2013), although we note site clearing and work has already begun.

20 Bcf/d+ Of North American Liquefaction Proposals On The Table: The following table highlights the potential for LNG exports that are currently on the table in North America. We have highlighted approved projects in green, projects that have currently entered the regulatory process in orange and pre-application projects in yellow. Overall, there are ~155 MMtpa (20.2 Bcf/d) of liquefaction facility proposals currently on the table with other proposals likely to emerge through 2012 [Nexen (NXY-SU)/Inpex (1605-T), Imperial/Exxon to name a few].

Exhibit 111. LNG Export Projects

Project Location Type Status 2015 2016 2017 2018 2019 2020

Sabine Pass GC BF Fully financed and recently achieved FID 0.2 1.2 1.8 2.4 2.4 2.4Kitimat NW BC GF Approved, awaiting FID & contracts 0.7 0.7 1.4 1.4 1.4BC LNG NW BC GF Approved, awaiting FID & contracts 0.1 0.2 0.2 0.2

Freeport GC BF Expects all approvals by mid-2013 with start-up in mid-2015, signed preliminary contracts 0.6 0.6 1.2 1.8 1.8Lake Charles GC BF Pre-FERC filing, awaiting DOE non-FTA export approval 1.0 1.0 2.0Cove Point EC BF Pre-FERC filing, awaiting DOE non-FTA export approval 1.0 1.0 1.0 1.0Jordon Cove NW US GF Partially FERC approved, will file for amendments and DOE non-FTA export approval soon 0.8 0.8 1.6 1.6Cameron LNG GC BF Received FERC approval in 2011, awaiting non-FTA approval 1.7 1.7 1.7 1.7Shell Kitimat NW BC GF Applied For Export License 0.8 1.6Freeport Expansion GC BF Pre-FERC filing, awaiting DOE FTA and non-FTA export approval 0.6 1.2Gulf Coast LNG GC GF Pre-FERC filing, awaiting DOE FTA and non-FTA export approval 1.4 2.8 2.8

Progress/Petronas NW BC GF Pre-Application 0.3 0.5 1.0 1.0Oregon LNG NW US GF Pre-Application 1.3 1.3 1.3

Total Fully Approved Projects 0.0 0.7 0.8 1.6 1.6 1.6

Total In Regulatory Process 0.0 0.6 4.1 7.1 11.3 13.7

Other Status 0.0 0.0 0.3 1.8 3.1 3.9

Total 0.0 1.3 5.2 10.5 15.2 17.6

Risked Canada Expectations 0.0 0.6 0.8 1.7 2.4 2.9Risked US Expectations 0.2 1.7 2.9 4.4 5.1 5.6Total Risked Expectations 0.2 2.2 3.7 6.1 7.5 8.5

LNG Export Capacity Anticipated At Year-End (Bcf/d)

Approved Project In Regulatory Process Pre-Application


We Believe ~8 Bcf/d Of LNG Exports By 2020: As depicted in Exhibit 111, we believe there is a reasonable likelihood of seeing approximately 62 MMtpa (8.5 Bcf/d) of export capacity by 2020, with 22 MMtpa (2.9 Bcf/d) likely from Western Canada, and 40 MMtpa (5.6 Bcf/d) from the U.S. (primarily Gulf Coast).

Next DOE Non-FTA Export Approvals Rulings Will Be Major Milestone: The DOE surprised the market in early 2011 by granting approval to the proposed 18 MMtpa (2.4 Bcf/d) Sabine Pass facility, allowing LNG exports to non-free trade countries (a necessity for almost any U.S. LNG project). We are currently waiting on similar approvals for Freeport 14 MMtpa (1.8 Bcf/d), Lake Charles 15 MMtpa (2 Bcf/d), and Cove Point 7.6 MMtpa (1 Bcf/d). The DOE’s primarily concern is security of supply, and with 2,543 Tcf of estimated resources in the U.S. representing 80 years at 2040 projected demand levels, we believe this will not be an issue. The DOE approval of Sabine Pass resulted in a meaningful move in long-term gas futures when it was announced and we could see a similar situation if and when further approvals are granted.


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We Expect To See 2-3 New Non-FTA Export Approvals In Early 2013: Price implications of LNG exports will also be a DOE concern and we believe the DOE is undergoing a substantial review, which it will use to base approval of proposed export facilities. We expect the review to depict similar results as other recent studies; essentially indicating that the price impact will be relatively modest, leaving gas prices at easily acceptable levels for consumers and industry. Overall, we believe there is a high chance the DOE approves 2-3 additional export facilities after the U.S. election in November (effectively early 2013 to announce approval). Most likely they will first grant approval to brownfield conversions of existing regas capacity in the GOM vs. greenfield developments.

Asians VERY Interested In Opening North American LNG Markets: Skeptics continue to be proved wrong as Sabine Pass on the GOM has moved to FID. The project has signed contracts for 16 MMtpa (2.1 Bcf/d) of capacity with Asian consumers making big commitments, despite the very long shipping distance (approximately 11,000 miles). More recently, the proposed Freeport project announced tentative deals with Osaka Gas (9532-T) and Chubu Electric (9502-T) from Japan, once again highlighting the demand from Asian buyers for North American LNG.

Tolling Model In GOM Pulling Some Interest From Canadian LNG But Price Difference Is Not Large: Cheniere (LNG-AMEX) surprised the market by selling out all of the capacity on its Sabine Pass export project. More recently, Freeport LNG announced tentative deals on its first Train with Japanese buyers lining up. Clearly buyers are attracted to the tolling model as an alternative to the traditional LNG oil linked pricing deal. However, we note that the long-term prices are not terribly different. Under current spot prices the gap is large as the cost to get cargoes back to Asia is $8.45 (US$3/Mcf gas plus tolls and shipping) vs. US$11- US$14/Mcf under oil linked pricing. However, on current strip prices, the cost through the tolling model is US$10.41/Mcf (US$4.70/Mcf gas plus tolls) US$11-US$14/Mcf under oil linked pricing (oil curve is relatively flat through 2017). Additionally, under the traditional model the buyer would also take an equity position which further reduces the apparent price gap. Overall, we continue to believe there will be oil linked pricing for Western Canadian LNG – but potentially with a minor natural gas link.

Exhibit 112. Landed Natural Gas Price To Asia From GOM Under Tolling Model

Spot2017

Futures

Gas Cost 2017 Futures Curve $3.00 $4.70Contracted Premium (15% premium to NYMEX to cover Fuel Shrink & basis) $0.45 $0.71Effective Gas Price @ Plant Gate $3.45 $5.41Contracted Toll $3.00 $3.00Shipping Cost (via Panama Canal post expansion - $3/Mcf currently) $2.00 $2.00Landed Gas Price $8.45 $10.41


Kitimat – Behind Schedule But Will Likely Move To FID In Late 2012/Early 2013: Based on our analysis of Australian LNG costs, we believe liquefaction costs are likely in the $800-$1200 per MMtpa ($37,000-$55,000/Boe/d) range, well above original cost estimates. We also expect pipeline costs to have increased to $240-$280 per MMtpa ($11,000-$13,000/Boe/d) for an overall project cost of $1,040-$1,480 per MMtpa ($48,000-$68,000/Boe/d) for Phase 1. We still believe Kitimat may surprise the market by announcing an anchor partner for its full 1.4 Bcf/d of proposed capacity, not just the first 0.7 Bcf/d train. Even with higher


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costs, we still believe Kitimat will deliver reasonable returns with our mid-case modeling yielding $2.8 billion of NPV and a 15% IRR at US$100/Bbl and US$5/Mcf gas. If FID is declared in late 2012/early 2013, we should see first gas exports in the 2016-2017 time frame.

Shell Unveils LNG Canada Plans: After much secrecy, Shell has finally unveiled its plans for LNG Canada in Kitimat. The project is initially envisioned as a 12 MMtpa (1.6 Bcf/d) facility with the intent to double to 24 MMtpa (3.2 Bcf/d). First gas from Train 1 is expected in 2019 with Train 2 on-stream likely six months after. Timing for Trains 3&4 have not been announced but we believe a likely scenario is to continue the pace and bring on these additional trains in about six months intervals.

Petronas Demonstrates Commitment To LNG: While we never doubted Petronas’ (PGAS-KL) intent to develop LNG, following its $5.5 billion bid for Progress (PRQ-SP), there is little doubt it will continue to aggressively pursue LNG. Petronas announced in the spring that it has selected Prince Rupert as the location for its planned LNG facility with first gas still slated for the ~2018 time frame.

Other Parties Still Assessing Canadian LNG: Progress highlighted in its recent information circular that it was approached several times by a party other than Petronas to acquire the firm. Petronas then went on to bid $20.45/share cash and then raised the offer again after the “other” party came back. In our view, this is a clear depiction that there is another large party wanting to get positioned for LNG exports and that desire likely has not gone away following their failed bid for Progress. Some of the parties still thought to be looking at B.C. LNG exports are BG [BG-L] (acquired a site in Prince Rupert but has no resource as of yet), Exxon/Imperial and Nexen [likely to be CNOOC (CEO-NYSE)]/Inpex.

North American LNG Can Compete Effectively With Australian LNG: Greenfield Canadian liquefaction costs will likely be similar to Australia, shipping distances into Asia are only modestly longer (4,300 nautical miles from Canada vs. 3,100 - 4,300 from Australia) and upstream development costs are similar. We also believe that LNG buyers will see some value in diversifying markets away from Australia, which has become a very heated environment.

U.S. Demand Growth Expected To Average 1.4 Bcf/d Per Year Through 2016 And 2.0 Bcf/d Per Year From 2016-2020 As LNG Exports Begin Overall, we estimate that U.S. demand for natural gas should increase approximately 1.4 Bcf/d per year through 2016 and 2.0 Bcf/d per year from 2016-2020 as LNG exports accelerate (1 Bcf/d excluding LNG exports). As discussed, the main growth drivers behind U.S. natural gas demand is power which we expect to grow ~0.6 Bcf/d per year with upside to the 1 Bcf/d per year range. We believe it is reasonable to assume 2-3 U.S. LNG export terminals in operation by the 2020 time frame with aggregate exports in the 4.5 Bcf/d range, representing a big incremental demand driver.


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Supply/Demand Balances – Tighter Markets Ahead Natural gas production from the main resource plays has averaged 4.5 Bcf/d per year from 2008-2011. Overall U.S. dry gas production growth is lower at 2.6 Bcf/d per year due to declines in non-resource play production and increasing NGL extraction losses, but still quite amazing growth. As discussed in our detailed discussions on forecasts for U.S. resource play production, we believe this momentum is finally waning and that there is no chance that the U.S. can sustain the prior growth rates without an increase in gas drilling – which will only occur with a meaningful price increase.

Exhibit 113 recaps our various natural gas production growth scenarios. As depicted, with current rig counts we would see U.S. dry gas production growth average only 0.5 Bcf/d per year through 2016 and similar rates through 2020. Other scenarios where we layer in efficiency improvements and expanding rig fleet lead to dry gas growth in the 1-1.3 Bcf/d per year range. In our view, the most meaningful forecast is the Monte Carlo simulation, which incorporates price volatility and dynamically re-allocates rigs to plays with higher rates of returns, so one can see the impact of prices on growth forecasts. To get dry gas growth into a range that approximates our 2011-2016 demand forecast of ~1 Bcf/d per year, we would need to see prices in the US$4/Mcf range – if producers allocate rigs solely according to IRR. However, as we noted in previous sections, in the short term (next two years), we believe strategic decisions to meet land obligations will continue to keep rigs more weighted to oil/liquids and prices may stay higher than they otherwise would. In the 2016-2020 time frame when U.S. LNG exports begin to take hold, we believe prices would need to be in the US$4-US$5/Mcf range to meet our ~2 Bcf/d per year growth forecast.


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Exhibit 113. Natural Gas Growth – Scenario Summary

Gas Production From Resource Plays (Mmcf/d) 2011 2016 2020 '11-'16 '16-'20 '11-'20A) Scenario 1 Base Case Results 31,775 40,258 45,759 1,696 1,375 1,554B) A + Ramp Up In New Plays 31,775 42,628 49,440 2,171 1,703 1,963C) B + Efficiency Gains 31,775 44,662 53,201 2,577 2,135 2,381D) C + Rig Fleet Growth 31,775 47,689 70,361 3,183 5,668 4,287E) Monte Carlo ($95 WTI, $4 NYMEX) 31,775 45,864 54,723 2,818 2,215 2,550F) E + Ramp Up In New Plays 31,775 49,068 60,227 3,459 2,790 3,161G) Monte Carlo ($95 WTI, $5 NYMEX) 31,775 53,130 64,143 4,271 2,753 3,596H) G + Ramp Up In New Plays 31,775 57,442 70,851 5,133 3,352 4,342

Non Resource Play Gas Production 34,429 29,802 26,420 (925) (845) (890)

Total Wet Gas ProductionScenario A (Same as Scenario 1 Base Case in previous example) 66,204 70,060 72,179 771 530 664Scenario B 66,204 72,430 75,860 1,245 858 1,073Scenario C 66,204 74,464 79,621 1,652 1,289 1,491Scenario D 66,204 77,491 96,781 2,257 4,822 3,397Scenario E 66,204 75,666 81,143 1,892 1,369 1,660Scenario F 66,204 78,870 86,647 2,533 1,944 2,271Scenario G 66,204 82,932 90,563 3,345 1,908 2,707Scenario H 66,204 87,244 97,271 4,208 2,507 3,452


Total US Dry Gas ProductionScenario A (Same as Scenario 1 Base Case in previous example) 63,002 65,593 67,578 518 496 508Scenario B 63,002 67,964 71,259 992 824 917Scenario C 63,002 69,998 75,019 1,399 1,255 1,335Scenario D 63,002 73,025 92,180 2,005 4,789 3,242Monte Carlo ($95 WTI, $4 NYMEX) 63,002 71,199 76,542 1,640 1,336 1,504Monte Carlo ($95 WTI, $4 NYMEX) + Ramp Up In New Plays 63,002 74,404 82,045 2,280 1,910 2,116Monte Carlo ($95 WTI, $5 NYMEX) 63,002 78,465 85,962 3,093 1,874 2,551Monte Carlo ($95 WTI, $5 NYMEX) + Ramp Up In New Plays 63,002 82,778 92,670 3,955 2,473 3,296


Short-term Balances Looks Quite Encouraging While this report was primarily focused on the medium- to long-term outlook for oil and natural gas, we cannot help but point out what are increasingly bullish looking supply/demand balances in 2013. The starting point is our view that Western Canada gas production less demand will be flat to down in 2013 (and likely 2014). In the U.S., we see dry gas production being flat to down 0.5 Bcf/d for net dry gas supply in the U.S. and Canada being down 0-1 Bcf/d Y/Y – the first annual decline in many years!

The U.S. demand side of the equation is more complex. With a five-year average winter, we would see demand up approximately 1.4 Bcf/d on a Y/Y basis (on a calendar year basis – would be much higher growth during heating season). The power side is more price dependant. If prices went back to the US$4/Mcf range, we would risk losing at least half of the 4.6 Bcf/d Y/Y demand gains but overall, we would still see a very tight supply-demand balance – particularly in the early winter months. As discussed in a prior section, there is the risk that prices increase and gas drilling follows suit – but we believe drillers will be reluctant to move rigs back to gas too quickly given past disappointments and the fact that so many producers have large land commitments to meet on liquids focused plays. For the first time in many years, it seems there could be real upside to short-term gas prices (if weather cooperates).

Short-term gas balances are looking surprisingly positive. Western Canada gas production less demand will be flat to down in 2013 (and likely 2014) and in the U.S., we see dry gas production being flat to down 0.5 Bcf/d in 2013.

Price recovery in 2013 will be somewhat limited by demand losses (i.e. if prices rise too quickly we will see significant y/y demand declines from power generation).


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Northeast Region – Growing Marcellus Production Lessens Need For Canadian Imports The Northeastern U.S. is still the largest consuming region of natural gas in the U.S., consuming ~35 Bcf/d in peak winter months. The region has always had a large supply deficit, which was filled from a combination of Canadian imports, Mid-Continent and U.S. Southwest movements (and some LNG imports). As depicted in the chart below, the growth in the Marcellus has been staggering but the region is still by far a large net consumer, even in the summer months.

Exhibit 114. U.S. Northeast Gas Consumption Vs. Production

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Source: Bentek and CIBC World Markets Inc.

Although the US NE is still a large net consumer of gas, the dramatic growth in the Marcellus is having an impact on inter-regional flows as the lower need for imports into the region is meaning that gas that would otherwise be destined for this market is finding a new home. Increasingly, we are starting to see bigger movements of U.S. natural gas into the Eastern Canada market – effectively backing out some of the need for Western Canadian gas in this market.

Importantly, this trend is not going away. At current rig counts (which are off 30% from their highs), we expect Marcellus production to grow from current levels of approximately 6.5 Bcf/d to ~9 Bcf/d by 2016 and in the 12 Bcf/d range by 2020. With a return to 2010-11 rig counts, we could be in the 12 Bcf/d range by 2016 and in the 17 Bcf/d range by 2020. While any of these scenarios still leave the US NE in a net consuming position, it would have a radical impact on intra-regional pipeline flows/market access.

Western Canada Looks Increasingly Isolated The Western Canadian gas market is increasingly facing tougher competition in its historic export markets. The Northern California market has historically been an important market for Canadian gas, but that now sees more competition from the U.S. Rockies due to the start-up of the Ruby pipeline (completed in summer 2011). The Bison pipeline has connected U.S. Rockies supply to the Northern Border system for delivery into the Chicago area, which will also back out some Canadian gas demand. And of course, one of the bigger issues is the aforementioned discussion on diminishing need for Canadian gas in the US NE.

Although the US NE is still a large net consumer of gas, the dramatic growth in the Marcellus is having an impact on inter-regional flows…lessening the need for Canadian gas in Eastern markets.


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To date, the impact on AECO-NYMEX differentials hasn’t been as bad as one would think given this backdrop. Part of the issue is that Canadian gas production has been declining due to overall price weakness for natural gas, which has meant that the “backed out” gas, was essentially voluntarily backed out. The basis risk could become bigger though should overall gas prices increase to a level that prompts higher reinvestment in natural gas drilling in Western Canada, and there is an actual competition for market access.

The following chart depicts our current outlook through 2020 for gas movements out of the Western Canadian gas market. As depicted, we expect only moderate growth in overall dry gas production which combined with potentially very meaningful growth in oil sands, leaves gas movements out of Western Canada declining through the 2016 time frame. The decline in gas movements out of Western Canada would accelerate should LNG exports come to pass (which we believe they will). Overall, we see continued competition for Canadian gas in traditional markets but a continued industry focus on oil, combined with opening of non-traditional markets should lead to AECO-NYMEX basis differentials remain in a reasonable range. In a scenario where gas prices remain sub US$4/Mcf, we could actually see Western Canada gradually emerge as a very independent market as supply would decline to a point where oil sands demand growth and LNG leave very little left to export to the U.S. or Eastern Canada.

Exhibit 115. Western Canadian Gas Available For Export To Eastern Canada/U.S.

Canadian Supply Growth Scenario Flat Canadian Production Scenario

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LNG ExportsOther WC Gas DemandOil Sands Gas DemandGas Available For Export To Eastern Can or US

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cf/d


Takeaways From Natural Gas Supply Demand Balances LNG Becoming A Reality: We believe LNG is well on its way to reality with well over 20 Bcf/d of export projects on the table. Our risked view is that approximately 8 Bcf/d is built by 2020, with approximately 3 Bcf/d of capacity in Western Canada and the remainder in the U.S. (centered in the GOM).

Demand Should Grow By 1 Bcf/d Per Year Through 2016 And 1.5 Bcf/d Per Year From 2016-2020: We expect U.S. natural gas demand to grow on average approximately 1 Bcf/d per year through 2016 driving primarily by higher demand for power consumption due to coal retirements. We expect demand to pick up in the latter half of the decade as LNG exports are added into the mix.


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Surplus WC Gas Flat In Best Case And Meaningful Declines In Worst Case: We expect Canadian supply to be down modestly in 2012 and 2013 and settling into a modest growth profile thereafter, with most of the growth wedge allocated to planned LNG facilities. Demand for gas in Western Canada will increase ~ 0.2-0.4 Bcf/d per year through 2016 and 0.2-0.6 Bcf/d per year through 2020 due primarily to higher demand for natural gas for oil sands. We expect LNG exports out of Western Canada to be up to 3.0 Bcf/d by 2020 (2-3 facilities). Overall, gas available for movement to Eastern Canada or the U.S. will likely remain flat in the growth scenario and down 6 Bcf/d by 2020 in a low price scenario (limited gas drilling).

Shales Decelerating: We expect shale gas growth to decelerate massively from the high growth rates seen in 2008-2010. At current rig counts, shales would only grow ~1.7 Bcf/d per year through 2016 vs. the ~4 Bcf/d per year growth seen previously. Adding in extraction losses and declines in non-shale production would see U.S. dry gas production growth of only 0.5 Bcf/d per year through 2016. We also note that our modeling suggests overall dry gas production flat to down modestly in 2013/14 before beginning to ramp up again.

Tighter Balances: Given the combination of flat to declining Canadian production in 2012-14, combined with flat to declining U.S. dry gas production in 2013/14, and higher demand – we clearly see significantly tighter balance for natural gas in the near future, which should continue price momentum.

Prices Unsustainably Low: The clear takeaway from our modeling (both the linear models and the simulation models), indicates that the current rig count and prices are unsustainably low. However, finding equilibrium remains a real balancing act.

Investment Conclusions Global Investors Likely To Remain Luke Warm On Canada Due To Pricing/Infrastructure Risk: Global investors have generally been moving away from Canadian oil & gas exposure for many reasons, but generally speaking a combination of macro fears (Greece, Spain, China slowing) along with fears regarding short-term differential risk for Canadian oil producers. With the dismal stock performance YTD for Canadian large caps, one could argue that much of our macro thesis is already discounted in stock prices – which is generally true. However, the general negative backdrop with more limited growth visibility and rising pipeline/differential risk means that global investors are unlikely to flock back to Canadian oil and gas exposure anytime soon – unless we see the recent flurry of M&A turn into a full blown wave (possible).

Some Big Players May Adjust Strategies: If our macro view pans out, it will (or should) impact investment decisions by producers. The most likely adjustment will be to those planning mega-projects such as upgraders or mining oil sands projects. We expect operators to move more cautiously on these projects, with a high chance of outright cancellation. On the one hand, lower growth is a negative. However, we believe investors have compressed valuations on many of these stocks due to concerns about low return investment. On balance, we actually believe investors would react favorably to large-cap producers to moving to lower growth but higher returning and higher free cash yielding strategies. For example, we can make a case that Suncor would be worth 40%-50% more if it moved to a slower and more SAGD oriented strategy and paid out excess free cash.


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Negative Backdrop For Long-dated Oil Sands: Much of our macro thesis is very bearish for the value of long-dated bitumen assets. As we highlighted, producer growth forecasts are wildly optimistic and we believe there will be big competition for pipe access and resources to build projects – which leaves the longer-date more fringe resources at a distinct disadvantage. Additionally, investors will likely remain much more cautious on providing the necessary capital for those growth ambitions, meaning that early stage oil sands companies will face far more execution risk than better financed players. Value can still be obtained/recognized for long-dated resource, but this depends more on M&A or JV activity.

Downstream Value Becomes Very Apparent: Our macro view clearly favors companies with downstream assets. In Canada, there are no pure refiners so this by default means that integrated energy companies (Suncor, Cenovus, Husky and Imperial Oil) are best positioned. The rationale is that in-land refineries capture much of the value of lower upstream pricing. We have seen the integrateds outperform PADD 2 exposed names YTD indicating that some of this theme is already reflected in share prices. However, we believe investor expectations are still generally that current downstream cash flows are ‘supernormal’ and will revert to low levels again in 2014+. We believe that downstream cash flows will remain robust over the long term – and that is not reflected in share prices. We highlight Suncor and Cenovus as two of the best positioned integrateds.

Exhibit 116. PADD 2 Vs. Integrated Share Price Performance

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120%

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Mar-28

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US E&P US IntegCAD E&P CAD IntegGlobal Energy PADD II Exposed Cdn E&P


Good Opportunity Still In Quality Gas Producers: For the first time in many years, the outlook for natural gas prices looks quite attractive. With tightening balances in 2013/14 and a rig count that will likely be slow to return to gas drilling gas prices should move into the US$4/Mcf range in 2013. We note that some gas players like Encana are already reflecting ~US$4.50/Mcf natural gas so much of the upside is already built in. However, we still see good upside in some of the smaller-/mid-cap gas names.

Among the dividend-paying corps, our top two ways to play natural gas include Trilogy and Peyto – with Trilogy as the more defensive gas play (due to its 45% liquids weighting) and Peyto as a higher torque gas pick (88% weighted to gas).


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In the junior/intermediate space, Celtic and Painted Pony are our top gas-weighted names. Both companies offer investor meaningful torque to gas prices as they control substantial resource potential from large contiguous land positions. We also highlight NuVista as another gas-weighted pick for its undervalued asset base with 500 drilling locations identified in the Wapiti Montney liquids-rich gas play that is a strong M&A candidate. In addition, we believe the company's shares are trading inexpensively relative to its natural gas peers as measured by Core NAV (P+P reserves value).

Light Oil Players Will See Lower-than-expected Pricing But Low-cost Players Will Still Make Very Strong Returns: Our thesis of lower light oil pricing will take some of the shine off domestic light oil producers. However, we note that producers with low costs and high-quality resources like Crescent Point will continue to prosper (although consensus numbers may be overstated if our macro view holds). Light oil companies with high cost structures and high capital obligations such as Canadian Oil Sands (opex in US$40/Bbl range with sustaining capex in the ~US$30/Bbl range through 2014) will see many challenges in this environment.

Top Picks Large Caps: Among the large caps, we continue to focus on Brent-focused producers and integrateds as our top picks. In order of preference, we highlight Suncor (inexpensive with high-quality downstream), Cenovus (highest quality oil sands and well positioned with downstream) and Talisman (turnaround story, gas assets will get re-rated if prices recover and enough Brent-priced growth projects in Colombia and Asia that will interest investors).

Small- To Mid-cap Oil Sands: From a macro perspective, it is more challenging to get excited about the small- to mid-cap oil sands producers, however, we continue to highlight MEG Energy (innovative and one of lowest cost resources bases) and Athabasca Oil. We remain positive on ATH primarily because we see it reducing oil sands exposure and believe the light oil assets will drive remaining value in short term.

Dividend-paying Corps: Our top picks in this space include our highest netback domestic light oil producers, Crescent Point and PetroBakken (whose margins are better protected in a downside scenario in which crude oil sees pressure). We would also highlight Trilogy as a top pick owing to its strong growth profile and its ability to fund its development (and pay its dividend) within cash flow.

Small And Mid Caps: Our top pick is Angle Energy as it offers exposure to a high netback Cardium oil play at Harmattan, which has become the largest focus area for the company. We highlight that the corporate liquids have increased from 39% at the end of 2010 to 46% projected for Q4/12. We also expect large year-end reserve growth associated with the active drilling program in Harmattan and area.

International Producers – Our two top picks in the International Producer space are Coastal Energy and Gran Tierra Energy. Both companies produce over 90% high netback oil that track to Brent pricing. CEN has a strong balance sheet, good free cash flow generation from its producing properties and significant upside potential with booked P3, 2C and prospective resources. GTE trades at a 20% discount to its 2P NAV but has a surplus of cash on its balance sheet, is expected to generate free cash flow in 2013 and has an active 2H12 planned with potential for significant catalysts.

Appendix - Too Much Of A Good Thing... - August 15, 2012

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Appendix


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Appendix Table Of Contents U.S. NGL Market Dynamics .......................................................................................................................... 132

NGL Supply And Demand .......................................................................................................................... 133 Five NGL Industry Themes ........................................................................................................................ 140

U.S. Resource Plays .................................................................................................................................... 147 Anadarko................................................................................................................................................ 148 Bakken................................................................................................................................................... 152 Barnett................................................................................................................................................... 156 Eagle Ford .............................................................................................................................................. 160 Fayetteville ............................................................................................................................................. 164 Haynesville ............................................................................................................................................. 168 Marcellus ................................................................................................................................................ 172 Mississippi Lime....................................................................................................................................... 176 Permian.................................................................................................................................................. 180 Woodford................................................................................................................................................ 184 Emerging Plays........................................................................................................................................ 188 Canadian Resource Plays ............................................................................................................................. 192

Amaranth ............................................................................................................................................... 194 Bakken (AB)............................................................................................................................................ 198 Bakken (SK)............................................................................................................................................ 200 Carbonates ............................................................................................................................................. 204 Cardium ................................................................................................................................................. 210 Deep Basin ............................................................................................................................................. 214 Duvernay................................................................................................................................................ 218 Glauconite .............................................................................................................................................. 222 Horn River .............................................................................................................................................. 224 Montney Gas ........................................................................................................................................... 226 Montney Oil............................................................................................................................................. 230 Nikanassin .............................................................................................................................................. 234 Pekisko................................................................................................................................................... 236 Seal ....................................................................................................................................................... 238 Shaunavon.............................................................................................................................................. 240 Viking Oil ................................................................................................................................................ 242

Comparative Valuations ............................................................................................................................... 250


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Source: Company reports; Geological Atlas of Western Canada; The Edge; Canadian Discovery Digest; CIBC World Markets Inc.

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The following section of our Appendix pertaining to Natural Gas Liquids (pages 132 to 146 inclusive) has been provided by CIBC World Markets’ analyst David Noseworthy, P.Eng, CFA.

U.S. NGL Market Dynamics In the past few years, liquids-rich U.S. gas production has increased dramatically due to the application of horizontal, multi-stage fractionation drilling technology (Exhibit 1).

Exhibit 1. U.S. Natural Gas Production (Historical And Forecast)

Source: EIA.

Growing supply and pipeline capacity constraints have combined for particularly weak mid-continent NGL prices. The supply of NGLs from U.S. natural gas production has increased faster than demand for both ethane and propane (Exhibit 2), causing prices for both to collapse over the last three months. Compounding this issue, pipeline constraints out of the Midwest (PADD II) into the export-driven U.S. Gulf Coast (PADD III) have resulted in depressed mid-continent NGL pricing. We discuss NGL supply and demand by component and NGL pipeline constraint issues below.

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Exhibit 2. U.S. Forecasted Ethane Oversupply And U.S. NGL Supply from U.S. Gas Production

Supply/Demand imbalanceforecasted to 2015E

Source: LyondellBasell, En*Vantage, Markwest Energy Partners L.P. and CIBC World Markets Inc. (David Noseworthy).

NGL Supply And Demand Ethane We expect weak ethane prices relative to WTI to persist until demand increases.

We expect weak relative prices to persist until several petrochemical plants complete planned expansions. Average Q3/12-to-date Mont Belvieu ethane is trading at 15% of WTI, below its five-year average relative value of 30% (see Exhibit 3). Significant expansions are not expected to come online until beyond 2013 (see Exhibit 4 and Exhibit 5). Near term, we do not expect any sustainable price catalysts for higher ethane prices, barring any fractionator outages. While there is limited intrinsic seasonality in ethane demand, most petrochemical plants on the U.S. Gulf Coast shut down for regular maintenance in Q3, while fractionator turnarounds are completed in Q2 and Q3 as economics are driven more by seasonal propane demand.

Exhibit 3. Quarterly Mont Belvieu Ethane Prices

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2005 2006 2007 2008 2009 2010 2011 2012 2005 2006 2007 2008 2009 2010 2011 2012 2005 2006 2007 2008 2009 2010 2011 2012 2005 2006 2007 2008 2009 2010 2011

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I

The decline of crude oil prices (~US$20/bbl) from early May levels have triggered price declines in 2012.

Q3 2012 ethane prices as a % of WTI decline to 15%.

Supply constraints tightened ethane prices in Q4/11.

Growing NGL production from liquid-rich gas has depressed historical relationship between C2 and WTI

Source: Company reports and CIBC World Markets Inc. (David Noseworthy).

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Exhibit 4. New Crackers / Restarts/ Debottleneck Projects

Proponent Location FeedstockCurrent Ethylene Capacity

(metric tonne/year)

New/ Expansion Ethylene Capacity (metric

tonne/year) Estimated CODDow Chemical (restart) St. Charles, LA Ethane 390,000 N/A End of 2012Westlake Chemicals Lake Charles, LA Ethane ~1,134,000 - ethylene ~125,000 H2/2012LyondellBasell Channelview, TX Ethane ~1,750,000 ~250,000 2012

NOVA Chemicals Corunna, ON Ethane 820,000 - ethylene

2,130,000 - co-productsN/A Late 2013

Westlake Chemicals Lake Charles, LA Ethane ~1,134,000 - ethylene ~125,000 H2/2014NOVA Chemicals Moore Township, ON Ethane 380,000 N/A N/ALyondellBasell LA Porte, TX natural gas ~789,000 ~386,000 2014NOVA Chemicals Sarnia, ON Ethane new N/A Late 2014 - 2017NOVA Chemicals Joffre, AB Ethane new N/A Late 2014 - 2018Dow Chemical (upgrade) Plaquemine, LA Ethane N/A N/A 2014

Royal Dutch Shell Beaver County, PA Ethane new TBDFinal investment decision anticipated to be made in

2015-2016. Dow Chemical (upgrade) TX Ethane N/A N/A 2016Aither Chemicals US Northeast Ethane N/A N/A 2016

Formosa Plastics Point Comfort, TX natural gas new800,000 olefins cracker

300,000 low density polyethylene resin plant

2016

Dow Chemical Freeport, TX Ethane new 1,500,000 2017Chevron Phillips Chemical Baytown, TX Ethane new 1,500,000 2017

Chevron Phillips Chemical near Old Ocean, TX Ethane new2 polyethylene plants each with a capacity of 500,000

2017


Exhibit 5. U.S. Ethane Cracking Capability Due To Expansions Or New Build

Year End

Increases In C2 Cracking Capability (000

bbls/d)

2013 35 Expansion2014 85 Expansion2015 18 Expansion2016 25 Expansion2016 53 New Build2017 198 New Build

2018 78 New Build Source: En*Vantage.

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Propane

Exhibit 6. Conway (LHS) And Mont Belvieu (RHS) Propane As A % Of WTI

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2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Q3/12TD Avg: 27% / $25.038 Year Avg: 78%

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2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Q3/12TD Avg: 41% / $37.518 Year Average: 79%

Source: Bloomberg and CIBC World Markets Inc. (David Noseworthy).

The single-largest determinant for propane demand in North America is winter temperatures. Propane is primarily used for residential and commercial cooking and space heating (40%-50%), petrochemical feedstock (25%-35%), and agricultural uses, including crop drying (5%-10%).

We expect propane to trade at a discount to its historical relationship with WTI absent a colder-than-normal winter. Q3-to-date Conway propane is trading at 27% of WTI, below its five-year average relative value of 52%. We expect this weaker-than-normal relationship to persist as propane storage levels are high (Exhibit 7) following one of the warmest North American winters on record and North American propane demand lags growing supply from increasing U.S. natural gas shale production.

However, we believe the current relative value of propane to WTI is overly depressed, even for the seasonally weak summertime, and will strengthen as we move into the fall and winter, assuming exports continue to increase (Exhibit 8) and normal winter weather. We forecast Conway propane to trade at 30%, 40%, 48%, and 48% of WTI in Q3/12E, Q4/12E, 2013E, and 2014E, respectively, below the five-year average of 57%.

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Exhibit 7. U.S. Propane Storage

US Propane Inventories At The End Of March

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2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 0

00 b

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Five Year Average: 29.5 Mbbls

Highest inventory level reached in the past 12 years - 75.0 Mbbls

March 2012 propane level: 45.0 Mbbls.

Source: EIA.

Exhibit 8. U.S. Propane Storage

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2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012YTD

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2012 YTD US propane exports increased 22% from full year 2011 to 181 Mbbls/d

Source: EIA.

Butane We expect that growing butane demand from the Alberta oil sands and the planned Cochin pipeline reversal in July 2014 should provide price support. Q3-to-date Conway butane is trading at 48% of WTI, below its five year average relative value to WTI of 65%. We forecast butane to trade at 54%, 70%, 73%, and 73% of WTI in Q3/12E, Q4/12E, 2013E, and 2014E, respectively, in line with the five-year average of 71%.

Basin Differentials There are significant basin differentials between the major North American NGL hubs of Mont Belvieu, Texas, Conway, Kansas, Edmonton, Alberta, and Sarnia, Ontario (see Exhibit 9). Differentials between Conway, Kansas, and Mont Belvieu, Texas are due to a combination of access to higher Brent priced markets at Mont Belvieu and NGL pipeline capacity constraints between Conway and Mont Belvieu.

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We expect new NGL pipelines scheduled to be built in 2013 will largely remove these constraints and provide NGLs at Conway access to additional demand from waterborne export markets and, thus, reduce the differential. There have been a number of new NGL pipeline project announcements in recent months. For a full list, please refer to Exhibit 10; otherwise, we highlight four projects below, which we believe will benefit Conway NGL prices.

1. Kinder Morgan Energy Partners spent $30 million to upgrade its existing Cochin pipeline, which will move 13,000 Bbls/d of Conway-sourced E-P mix to Sarnia, Ontario. The project was expected to come online on April 1, but has been delayed due to permitting issues. Kinder Morgan signed a three-year contract with Nova Chemicals. Nova Chemicals is in the midst of expanding its Corunna, Ontario facility.

2. DCP Midstream (DPM–NYSE) is proceeding with the 150,000 Bbls/d common carrier Southern Hills Pipeline between Conway, Kansas and Mont Belvieu, Texas. DCP will convert the Seaway Products Pipeline, which it bought from ConocoPhillips (COP-NYSE) on November 1, 2011, from a refined products pipeline to a NGL pipeline. Southern Hills Pipeline is targeting a mid-2013 in-service date.

3. Oneok Partners (OKS–NYSE) is planning a 193,000 Bbls/d NGL pipeline called Sterling III Pipeline between Medford, Oklahoma (just south of Conway, Kansas) and Mont Belvieu, Texas. Commercial operation is expected by late 2013, assuming construction starts in early 2013. As currently designed, the 16-inch Sterling III pipeline capacity can be expanded to 250,000 Bbls/d with additional pumping stations.

4. On January 3, 2012, Enterprise Products Partners L.P. (EPD-NYSE) announced it had received sufficient commitment to develop its 1,230-mile Appalachia to Texas NGL pipeline, ATEX Express. ATEX Express, originating in Washington County, Pennsylvania, will have 190,000 Bbls/d of capacity and terminate in Mont Belvieu, Texas. ATEX Express is expected to begin commercial operations in Q1/14.

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Exhibit 9. North American NGL Infrastructure And Hub Differentials

1

6

9

5

4

3

2

8 7

3b

10

11

New / Proposed Pipeline

Southern Lights1b

Project Name1 Vantage Pipeline

1b Cochin Reversal2 Baaken NGL 3 Mariner West

3b Mariner East4 ATEX Express5 Sand Hills

6West Texas Gateway

NGL 7 Sterling III8 Southern Hills 9 Texas Express

10 Front Range

11Cajon-Sibon Extension

Mt. Belvieu - Conway 7/13/2012 7/6/2012 6/29/2012Propane 12.47 13.36 11.34Butane 18.94 19.03 17.51All figures in US$/bbl

Propane Differential 7/13/2012 7/6/2012 6/29/2012Mt Belvieu - Conway 12.47 13.36 11.34Mt. Belvieu - Edmonton 17.35 18.23 16.09Mt. Belvieu - Sarnia 2.23 -0.25 0.13Conway - Edmonton 4.87 4.87 4.87Conway - Sarnia -10.25 -13.61 -11.21Edmonton - Sarnia -15.12 -18.48 -15.96

Butane Differential 7/13/2012 7/6/2012 6/29/2012Mt. Belvieu - Conway 18.94 19.03 17.51Mt. Belvieu - Edmonton -0.38 -1.55 -3.49Mt. Belvieu - Sarnia -14.66 -17.51 -19.03Conway - Edmonton -19.32 -20.58 -3.49Conway - Sarnia -33.60 -36.54 -36.54Edmonton - Sarnia -14.28 -15.96 -15.54All figures in US$/bbl

Note: Details of pipeline projects are in Exhibit 12. Source: Encana, Bloomberg and CIBC World Markets Inc. (David Noseworthy).

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Exhibit 10. NGL Infrastructure Pipeline Projects - Announced, In Construction

Project Name Proponent Estimated Capacity

(MBbls/d) Capex

(US$mlns) Est. COD To From 1 Vantage Pipeline Vantage Pipeline Canada ULC 40, Expandable to 60 240 Q4 / 2012 Near Empress, AB Tioga, ND

1b. Cochin Pipeline Reversal

Kinder Morgan Energy Partners 95 30 July 2014 Fort Saskatchewan, AB

Kankakee County, IL

2 Bakken NGL Oneok Partners 60, Expandable to 110 450 - 550 2013 Weld County, CO Sidney, MT

3 Mariner West MarkWest Liberty Midstream & Resources

LLC and Sunoco Logistics LP Initial 50, up to 75 N/A July 2013 Sarnia, ON Houston, PA

3b Mariner East MarkWest Liberty Midstream & Resources LLC and Sunoco Logistics LP

TBD TBD TBD TBD TBD

4 ATEX Express Enterprise Products Partners LP 125, Expandable to 190

N/A Q1 / 2014 Mont Belvieu, TX Washington County, PA

5 Sand Hills DCP Midstream LLC 200, Expandable to 350

N/A Q3 / 2012 Mont Belvieu, TX Ector, TX

6 West Texas Gateway NGL

Lone Star NGL LLC (JV of Energy Transfer Partners LP and Regency Energy Partners

LP) 130 700 Q1 / 2013 Jackson County, TX Winkler, TX

7 Sterling III Oneok Partners 193, Expandable to 250

610 - 810 Late 2013 Mont Belvieu, TX Medford, OK

8 Southern Hills (inc. conversion costs) DCP Midstream LLC 150 780 - 850 Mid 2013 Mont Belvieu, TX Conway, KS

9 Texas Express Enterprise Products Partners LP, Enbridge Energy Partners LP, Anadarko Petroleum

Corp., DCP Midstream Partners (10%) 280 1100 Q2 / 2013 Mont Belvieu, TX Carson County, TX

10 Front Range Enterprise Products Partners LP, Enbridge

Energy Partners LP and Anadarko Petroleum Corp.

150, Expandable to 230

TBD Q4 / 2013 Skellytown, TX Weld County, CO

11 Cajon-Sibon

Extension Crosstex Energy LP 70 230 Q2 / 2013 Mont Belvieu, TX Eunice, LA

Source: Company reports, Oil And Gas Journal and CIBC World Markets Inc. (David Noseworthy).

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Five NGL Industry Themes Five major trends are shaping the NGL industry in Alberta:

1. Increasing oil sands production;

2. Pipelines and differentials;

3. Declining natural gas export volumes;

4. Natural gas producer trends; and

5. Restructuring of the NGL extraction rights market.

Increasing Oil Sands Production Increased oil sands production has positive and negative effects on the NGL industry. First, increased oil sands production will increase condensate demand, which for Pembina may mean an increased demand for its condensate handling and storage services, as well as oil sands condensate supply pipeline opportunities. Second, increased oil sands production will require more natural gas for steam and electricity. This will, in our opinion, lead to declining natural gas export volumes and negatively impact the straddle plants in the area. We discuss both impacts below.

Condensate demand is expected to increase with oil sands production. Condensate is used to dilute heavy oils, such as bitumen, for pipeline transportation. One barrel of condensate is required for every 2.5–3 barrels of bitumen. According to CAPP’s June 2012 forecast, oil sands bitumen production is expected to increase by approximately 800,000 Bbls/d from 2011 to 2015 (Exhibit 11 – Increasing Canadian Crude Oil Production). The increased bitumen production represents a potential increase in condensate demand of 266,000 Bbls/d. To put this in context, condensate production from Alberta and British Columbia in 2010 was about 252,000 Bbls/d. Exhibit 12 demonstrates the pentane plus or condensate supply from natural gas extraction and Alberta demand for condensate.

Exhibit 11. Increasing Canadian Crude Oil Production

Source: CAPP.

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Exhibit 12. Alberta Condensate Supply And Demand

0

200

400

600

800

1000

1998

2000

2002

2004

2006

2008

2010

2012

2014

2016

2018

2020

bbl/d

AB Demand (ex. solvent flood demand)AB Supply (ERCB Estimate)AB Supply Plus Potential Supply From Import Pipelines

Cochin is currently expected to come into service July 2014.

July 2010: Southern Lights is placed into service

Rail opportunity

Source: ERCB.

We expect a significant portion of growing condensate demand to be satisfied by Enbridge Inc.’s Southern Lights pipeline and Kinder Morgan Energy Partners L.P.’s Cochin pipeline reversal.

Southern Lights began operations in July 2010 with an initial capacity of 180,000 Bbls/d and incremental expansion capability to an ultimate capacity of 330,000 Bbls/d. Southern Lights delivers condensate from a variety of refineries and producers near Chicago, Illinois to Hardisty, and Edmonton, Alberta. Currently, two shippers have committed volumes of 77,000 Bbls/d. In 2011, average volumes transported were about 65,000 Bbls/d. The toll for committed volumes in 2011 was about $8.10/Bbl and $16.25/Bbl for committed and uncommitted volumes, respectively. This falls to about $2.20/Bbl and $14.60/Bbl for committed and uncommitted volumes, respectively, when the pipeline is operating at full capacity.

Pembina has a direct pipeline connection to Southern Lights at its Pembina Nexus Terminal in Edmonton, but not at its Redwater facility. We believe an NGL pipeline connection between its PNT facility and Redwater facility could be one of the early integration projects as it would require a relatively short 20 km pipeline within an existing right-of-way between Namao and Edmonton as Pembina already has an NGL pipeline between Namao and Redwater.

On June 5, 2012, Kinder Morgan announced strong binding commercial support for the Cochin pipeline reversal project. The Cochin Reversal project, which is expected to be in-service by July 1, 2014, will allow shippers to move up to 90,000 Bbls/d of mixed product from Kankakee County, Illinois to terminal facilities near Fort Saskatchewan, Alberta. Kinder Morgan will also connect the Cochin pipeline to the Explorer pipeline at Kankakee, Illinois. The Explorer pipeline transports finished products from Houston, Texas to just south of Chicago, Illinois and is owned by Chevron (CVX–NYSE), American Capital Strategies Ltd. (ACAS–NASDAQ), ConocoPhillips, Marathon (MRO–NYSE), Sunoco Logistics (SXL–NYSE), and Shell. This connection will allow shippers to access condensate in Mont Belvieu for transport to Alberta. Proposed tolls are US$4.95/Bbl for committed volumes and US$7.50/Bbl for uncommitted volumes. The Cochin pipeline terminates at Pembina’s Redwater facility.

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We expect demand for NGL storage and logistics to benefit from increased condensate deliveries by pipeline. However, opportunities to import condensate to Pembina’s 75,000 Bbls/d rail offloading terminal at Redwater, for example, may be limited as potentially cheaper pipeline line transportation displaces condensate transportation by rail, which costs about $6.50/Bbl from Chicago to Edmonton and about $15/Bbl from Mont Belvieu to Edmonton. In the case of the Cochin Reversal project, we expect there may be increased rail opportunities to transport propane volumes by rail that were previously transported to the U.S. and Sarnia by the Cochin pipeline.

We also note other pipeline plans to transport condensate from the USGC to Alberta could negatively impact Some NGL rail transportation business. One such plan was recently announced by Plains All American during its Investor Day. Plains All American suggested the Capline pipeline could be used to allow condensate delivery into Enbridge’s Southern Lights system. The 1.2 MMBbls/d Capline is co-owned by Plains All American, Marathon, and BP and stretches from St. James, Louisiana to Patoka, Illinois.

Finally, incremental diluent volumes from Southern Lights and the potential Cochin Reversal into the Redwater/Fort Saskatchewan NGL hub suggest the need for additional pipeline capacity from Redwater to the oil sands. We expect midstream companies to pursue this opportunity as part of a unique integrated diluent service offering to oil sands producers.

Pipelines And Differentials In addition to the pipelines discussed above and their impact on condensate, there are several other proposed North American pipelines that we believe will act to compress differentials between the various North American NGL hubs.

There are significant basin differentials between the major North American NGL hubs of Mont Belvieu, Texas, Conway, Kansas, Edmonton, Alberta, and Sarnia, Ontario. Differentials between Conway, Kansas and Mont Belvieu, Texas are due to a combination of access to higher Brent priced markets at Mont Belvieu and NGL pipeline capacity constraints between Conway and Mont Belvieu. We expect new NGL pipelines to be built in 2013 to largely remove these constraints and provide NGLs at Conway access to additional demand from waterborne export markets and, thus, reduce the differential (Exhibit 9 – North American NGL Infrastructure And Hub Differentials). For more details of the projects, please see Exhibit 10 – NGL Infrastructure Pipeline Projects - Announced, In Construction.

We believe the impact of these new pipelines will be mixed. On the positive side, higher Conway propane pricing should result in higher Edmonton propane pricing. Conversely, tightening differentials will likely reduce the arbitrage opportunities typically captured by marketing groups through the use of railcar fleets.

Sarnia is the premium liquefied petroleum gas (LPG) priced market in North America due to its large petrochemical industry demand and sole source NGL supply from Western Canada. We expect the 50,000 Bbls/d Mariner West ethane pipeline, a joint venture between Sunoco Logistics and MarkWest (MWE–AMEX), to cause the propane and butane pricing in Sarnia to weaken substantially as NOVA Chemicals completes a $250 million upgrade to its facilities to allow it to accept lower-priced ethane feedstock. The Mariner West pipeline will transport ethane from the Marcellus to Sarnia and is expected to be in service July 2013.

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We expect weaker Sarnia pricing to negatively impact Midstream Companies who sell propane production at Empress into the Sarnia market. The extent of the impact will depend on which markets companies ultimately sell their supply into. We believe a business case could be made for a propane export terminal on the Canadian West Coast targeting Asian markets, similar in concept to the liquid natural gas and oil terminal proposals. Exhibit 13 summarizes recently announced U.S. propane export terminal expansions that provide an indication of potential capital costs.

Exhibit 13. Summary Of Recently Announced U.S. Propane Export Terminal Expansions

Date Company Location

Additional Capacity

(MBbls/d) Capex

(US$ mlns.) COD

03-May-12 Enterprise Product Partners L.P. Houston, TX 3.4 N/A Q2/2012 19-Sep-11 Targa Resources Houston, TX 60 $250 Q3/2013 01-Sep-11 ConocoPhillips/Occidental/TransMontaigne Houston, TX N/A N/A N/A 06-May-11 Vitol Group Beaumont, TX Up to 100 N/A Q1/2013 29-Mar-11 Enterprise Product Partners L.P. Houston, TX 120 N/A H2/2012


Declining Natural Gas Exports We expect WCSB natural gas exports to decline 29% between 2011 and 2015E. Increased Alberta oil sands production will require more natural gas for steam and electricity. Furthermore, we expect WCSB natural gas production to remain relatively flat through to 2015. Flat production and increased demand for natural gas within Alberta will, in our opinion, result in declining natural gas export volumes (Exhibit 14 – WCSB Natural Gas Production And Uses). Lower natural gas export volumes will negatively affect Empress straddle plants.

Exhibit 14. WCSB Natural Gas Production And Uses

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

2007 2008 2009 2010 2011E 2012E 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

Prod

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d D

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d (B

cf/d

)

0%

10%

20%

30%

40%

50%

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70%

80%

90%

100%

LNG Exports

WCSB Gas Exports

SK Total Demand

BC Total Demand

Natural Gas used in Oil Sands

Alberta Other

Alberta Commercial Demand

Alberta Residential Demand

WCSB Gas Exports as % of Total (RHS)

Source: NEB, ERCB, CAPP, TRP and CIBC World Markets Inc. (David Noseworthy).

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Declining natural gas export volumes impact straddle plants in two ways: 1) decreased NGL extraction volumes; and, 2) increased NGL extraction fees paid to shippers as the various straddle plant owners compete to process the dwindling supply of available natural gas. For example, we estimate throughput declines at Pembina’s Empress plants of 3%/year from 2011 to 2014. We calculate lower volumes negatively impact Empress gross margins for the company by about $2 million to $3 million per year.

Extraction premiums have increased about 1,000% at Empress over the past six years. Extraction premiums are the fees Empress straddle plant owners pay shippers for the right to extract NGLs from the natural gas being transported on the TransCanada mainline. These fees are paid as a premium on the shrinkage natural gas purchased to replace the heat content of the NGLs extracted. In Q4/2011 Empress extraction premiums were near the mid-point of a $6/GJ to $9/GJ range, according to Provident, while in 2006 extraction premiums were about $0.66/GJ, according to disclosure in the NGL Extraction Inquiry.

We believe lower straddle plant utilization and higher operating costs may prompt consolidation among the Empress straddle plants. Average annual natural gas throughput in 2011 on the TransCanada mainline was about 3.2 Bcf/d compared with the nearly 10 Bcf/d of straddle plant gas processing capacity at Empress. Consolidation will allow for the reduction of extraction capacity and more efficient utilization of the lower-cost plants. Pembina’s position as 65% owner and operator of the deepest-cut, highest efficiency Empress straddle plant may position it as the natural consolidator or, conversely, the most attractive asset to purchase. We question whether the Empress plant fits Pembina’s overall risk profile and strategic direction.

Producer Trends Low gas prices and high NGL prices have resulted in several producer trends, such as: 1) fewer well completions; 2) focus on liquids-rich gas production; 3) a preference for deep-cut field gathering and processing plants in order to maximize the NGL volumes extracted; 4) a propensity among producers to pay for gas processing services under fee-for-service or cost-of-service arrangements, allowing producers to retain control over the NGLs; and, 5) a willingness among capital-conscious producers to outsource gas processing to midstream players.

Canadian natural gas well completions have tapered off with the fall in AECO natural gas prices (Exhibit 15 – Canadian Natural Gas Well Completions). We expect continued depressed gas prices to dampen production in the WCSB. However, historically strong NGL prices have caused natural gas producers to focus on liquids-rich gas production areas such as the Duvernay, Deep Basin, Swan Hills, and Montney formations. Producers have focused on controlling and maximizing the value of the entrained NGLs in the raw gas stream as NGLs become a more significant component of the producers’ netback.

Producer preference for NGL extraction capability in the field has resulted in lower C3+ volumes at straddle plants (Exhibit 16 – NGL Content Of Gas Processed At Alberta Straddle Plants). Reduced C3+ volumes will negatively impact operating margins at Pembina’s Empress facilities as propane, butane, and condensate have higher margins than ethane. However, we believe Pembina is well positioned to benefit from producer demand for deep-cut NGL FG&P facilities, as it is uniquely situated to successfully buy, build, and own many of the incremental deep-cut facilities required by producers within the footprint of Pembina’s NGL pipeline system. Pembina’s integrated legacy asset base allows it to generate multiple revenues and, therefore, higher returns.

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Exhibit 15. Canadian Natural Gas Well Completions

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

2006 2007 2008 2009 2010 2011 2012TD#

of

Wel

l Co

mp

leti

on

s$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

CA

D/G

J

Gas Well Completions (LHS) AECO Nat Gas (RHS)

Canadian well completions have tapered off with the fall in AECO natural gas prices

Source: Bloomberg, Daily Oil Bulletin, and CIBC World Markets Inc. (David Noseworthy).

Exhibit 16. NGL Content Of Gas Processed At Alberta Straddle Plants

32.0

33.0

34.0

35.0

36.0

37.0

38.0

2006 2007 2008 2009 2010 2011

bbl o

f NG

L/m

mcf

of N

atur

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as

12

13

14

15

bbl o

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L/m

mcf

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C2+ (LHS) C3+ (RHS)

C2+ volumes increased as producers focus on liquids-rich plays since natural gas price fell in 2009. However, increased NGL extraction at FG&P plants has resulted in lower C3+ volumes at straddle plants.

Source: ERCB, and CIBC World Markets Inc. (David Noseworthy)

Restructuring Of The NGL Extraction Rights Market We believe the restructuring of the NGL extraction rights market as proposed under Nova Gas Transmission Ltd.’ s (NGTL) NEXT model will be a net negative for Alberta straddle plants operators because: 1) extraction premiums are likely to increase; and, (2) producers are unlikely to be compelled to place liquids-rich gas on the NGTL system if a deep-cut FG&P option is available. Therefore, incremental liquids-rich volumes due to the implementation of the NEXT model are unlikely to be significant.

The NGL Extraction (NEXT) model is a mechanism that allocates extraction rights of the receipt customers (producers) on the Integrated Alberta System (ATCO and NGTL systems) based on proportionate value of NGLs delivered to the system by each producer, and enables customers to use extraction rights to direct gas to extraction plants. Eventual implementation of the NEXT model is a result of the Alberta Energy and Utility Board (AEUB) decision following the NGL Extraction Inquiry, which concluded in 2009.

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The AEUB decision recommended the current model be replaced with the NEXT model. The NEXT model would operate in the same way as the current convention, in that straddle plant owners pay shippers a premium on the shrinkage gas purchased, effectively sharing some of the value added from extracting NGLs from the gas stream. The NEXT model differs from the current convention because receipt shippers, rather than delivery shippers, will receive the premium.

We believe implementation of the NEXT model is unlikely before 2014. Prior to May 25, 2012, NGTL proposed to implement the NEXT model on November 1, 2013, assuming timely National Energy Board (NEB) approval. On May 25, 2012, the NEB suspended proceedings pursuant to NGTL’s request so that NGTL could explore new opportunities that have arisen as a result of falling natural gas prices and increased quantities of available NGLs. NGTL has committed to report back on the status of discussions no later than October 15, 2012.

We expect the extraction rights market to become more liquid and transparent as proposed under the NEXT model, similar to the Natural Gas Exchange (NGX) and Nova Inventory Transfer (NIT) markets. Extraction rights available to a given straddle plant will no longer be restricted to the delivery point, but instead any receipt shipper can sell its extraction rights to any straddle plant. This means a given straddle plant will no longer be competing with only the other plants at its particular export point (e.g., Empress, Cochrane), but instead it will be able to bid for more extraction rights than are contained in the gas to be shipped downstream of that plant. We are uncertain as to how this will work operationally.

In a transparent market we expect NGL extraction premiums to trend toward the economic rents of the marginal extraction plant or nominal new plant, whichever is lower. That is, extraction premiums will equal the NGL fractionation margins of the marginal straddle plant less the full cost of extraction including a return of and on capital.

In our view, incremental liquids-rich volumes in the NGTL system are unlikely to be significant following the implementation of the NEXT model. Under the current NEXT proposal a producer would receive its pro rata share of the value of NGLs entrained in the gas that are extracted at an Alberta straddle plant. In 2011 only 53% of gas produced was processed at a straddle plant. Without the ability to selectively direct liquids-rich natural gas to the straddle plants a producer that contributed 100% of the NGLs on the NGTL system would only receive payments for 53% of these NGLs. With the ability to direct liquids-rich gas to straddle plants and dry gas to intra-Alberta demand this could improve, but we are uncertain as to how NGTL can prevent the co-mingling of rich and dry gas within its system.

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U.S. Resource Plays

Anadarko (Horizontal)

Exhibit 17. Anadarko (Horizontal) Map

Top 5 Producers1 Chesapeake Energy2 Mewbourne3 Linn Energy4 Devon Energy5 Newfield Exploration6 Other

TEXASPermian Barnett

Woodford

OKLAHOMAOchiltree

Moore

Potter

Carson

Roberts

Wheeler

Hemphill

Lipscomb

Ellis

Grady

Exhibit 18. Anadarko (Horizontal) Economics (IRRs)

Anadarko IRRs Anadarko – Top Operators

AnadarkoHzDir $60.00 $70.00 $80.00 $90.00 $100.00 $110.00 $120.00$2.00 -2% 3% 9% 14% 21% 27% 33%$2.50 -1% 4% 10% 16% 22% 29% 35%$3.00 0% 6% 12% 17% 24% 30% 37%$3.50 2% 7% 14% 19% 26% 32% 39%$4.00 3% 9% 15% 20% 28% 34% 41%$4.50 5% 10% 17% 22% 30% 36% 43%$5.00 6% 12% 18% 23% 31% 38% 45%$5.50 7% 13% 20% 25% 33% 40% 47%$6.00 9% 15% 21% 27% 35% 42% 49%$6.50 10% 16% 23% 28% 37% 44% 51%$7.00 11% 18% 25% 30% 39% 46% 54%

Top OperatorsActive Rigs

1 Chesapeake Energy 292 Apache 213 Sandridge 114 Mewbourne Oil 95 Devon Energy 56 Unit Petroluem 5

Source for Exhibits 17 and 18: HPDI, Google Earth and CIBC World Markets Inc.

Anadarko (Hz)

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Exhibit 19. Anadarko (Horizontal) Results by County and Operator

COMMON_OPER_NAME Data GRADY (OK) CARSON (TX) ELLIS (OK) POTTER (TX) MOORE (TX) ROBERTS (TX) OCHILTREE (TX) LIPSCOMB (TX) HEMPHILL (TX) WHEELER (TX) Grand Total

CHESAPEAKE ENERGY CORPORATION Sum of Last Reported Total Prod (Boe/d) 1 89 0 98 3,411 398 3,659 7,429 27,821 43,046

Average of Peak Well Rate (Boe/d) 694 295 470 316 367 199 305 789 1,191 670

MEWBOURNE HOLDINGS INC Sum of Last Reported Total Prod (Boe/d) 27 4,006 7,286 9,709 4,946 26,049

Average of Peak Well Rate (Boe/d) 390 579 363 482 680 468

LINN OPERATING, LLC Sum of Last Reported Total Prod (Boe/d) 0 320 300 202 0 0 1,906 21,086 24,469

Average of Peak Well Rate (Boe/d) 28 134 215 290 119 0 1,104 1,072 534

DEVON ENERGY CORPORATION Sum of Last Reported Total Prod (Boe/d) 321 11,180 12,355 23,906

Average of Peak Well Rate (Boe/d) 283 956 1,390 979

NEWFIELD EXPLORATION COMPANY Sum of Last Reported Total Prod (Boe/d) 0 0 0 18,710 18,776

Average of Peak Well Rate (Boe/d) 151 0 102 911 854

APACHE CORPORATION Sum of Last Reported Total Prod (Boe/d) 0 63 1,351 26 280 13,226 14,952

Average of Peak Well Rate (Boe/d) 235 363 317 74 320 1,104 692

HOLMES EXPLORATION, LLC Sum of Last Reported Total Prod (Boe/d) 8,767 6,172 14,938

Average of Peak Well Rate (Boe/d) 336 316 326

UNIT CORPORATION Sum of Last Reported Total Prod (Boe/d) 0 4,386 37 116 7,547 12,118


EOG RESOURCES INCORPORATED Sum of Last Reported Total Prod (Boe/d) 37 200 3,443 6,226 9,906


SAMSON INVESTMENT COMPANY Sum of Last Reported Total Prod (Boe/d) 0 17 0 316 5,338 3,365 9,036

Average of Peak Well Rate (Boe/d) 646 183 116 300 559 869 603

JONES ENERGY, LTD. Sum of Last Reported Total Prod (Boe/d) 126 52 40 5,338 1,291 6,847


SANGUINE GAS EXPLORATION, LLC Sum of Last Reported Total Prod (Boe/d) 6,355 6,667

Average of Peak Well Rate (Boe/d) 636 634

PIONEER NATURAL RESOURCES COMPANY Sum of Last Reported Total Prod (Boe/d) 35 2,772 2,053 0 0 5,275

Average of Peak Well Rate (Boe/d) 134 262 307 19 1,340 269

CORDILLERA ENERGY PRTNRS III,LLC Sum of Last Reported Total Prod (Boe/d) 642 68 3,198 461 4,368

Average of Peak Well Rate (Boe/d) 1,052 185 552 1,104 690

GRANITE OPERATING COMPANY Sum of Last Reported Total Prod (Boe/d) 48 94 1,026 2,970 4,137

Average of Peak Well Rate (Boe/d) 534 187 271 1,086 684

QEP ENERGY COMPANY Sum of Last Reported Total Prod (Boe/d) 0 23 75 3,462 3,737


CHEVRON, U.S.A., INC. Sum of Last Reported Total Prod (Boe/d) 0 1,741 1,740 3,484

Average of Peak Well Rate (Boe/d) 525 1,259 1,113 656

BP AMERICA PRODUCTION COMPANY Sum of Last Reported Total Prod (Boe/d) 27 234 119 2,284 107 1 2,801


CHALKER OPERATING INC. Sum of Last Reported Total Prod (Boe/d) 2,791 2,791


CIMAREX ENERGY COMPANY Sum of Last Reported Total Prod (Boe/d) 0 311 2,164 2,483

Average of Peak Well Rate (Boe/d) 0 185 556 362

Total Sum of Last Reported Total Prod (Boe/d) 935 1,371 2,370 3,157 4,064 17,052 24,114 39,821 50,764 113,612 261,220

Total Average of Peak Well Rate (Boe/d) 558 243 288 257 255 362 283 305 648 1,047 442


Anadarko (Hz)

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Anadarko Play Profile (Horizontal) Rigs Running Wells Drilled

0

20

40

60

80

100

120

140

160

180

200

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

Rig

s R

unni

ng

HighBaseLow

0

100

200

300

400

500

600

700

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

Wel

ls D

rille

d

HighBaseLow


-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

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Q1/20E

Q4/20E

Mm

cfe/

d

-

83

167

250

333

417

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583

667

Mbo

e/d

Liquids (Right)

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

Q2/19E

Q1/20E

Q4/20E

Mm

cfe/

d

0

83

167

250

333

417

500

583

667

Mbo

e/d

Low Base High


0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

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

HighBaseLow

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

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

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Exhibit 20. Bakken Map

Top 5 Producers1 Continental Resources2 Hess Corp.3 Whiting Petroleum4 EOG Resources5 Brigham O&G6 Other

NORTH DAKOTA

SOUTH DAKOTAMONTANA

Divide

Williams

Roosevelt

Richland

Burke

DunnStark

Billings

McKenzie

Mountrail

Exhibit 21. Bakken Economics (IRRs)

Bakken – IRRs Bakken – Top Operators

Bakken $60.00 $70.00 $80.00 $90.00 $100.00 $110.00 $120.00$2.00 5% 10% 16% 21% 28% 34% 40%$2.50 5% 10% 16% 21% 28% 34% 41%$3.00 5% 11% 17% 21% 28% 34% 41%$3.50 6% 11% 17% 21% 29% 35% 41%$4.00 6% 11% 17% 22% 29% 35% 42%$4.50 6% 11% 17% 22% 29% 35% 42%$5.00 6% 12% 18% 22% 30% 36% 42%$5.50 7% 12% 18% 23% 30% 36% 43%$6.00 7% 12% 18% 23% 30% 36% 43%$6.50 7% 12% 19% 23% 31% 37% 44%$7.00 7% 13% 19% 24% 31% 37% 44%


1 Continental Resources 252 Whiting O&G 213 Hess 184 Brigham Oil & Gas 165 Petro Hunt 126 Oasis Petroleum 10


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Exhibit 22. Bakken Results by County and Operator

COMMON_OPER_NAME Data BILLINGS (ND) STARK (ND) ROOSEVELT (MT) BURKE (ND) DIVIDE (ND) RICHLAND (MT) WILLIAMS (ND) DUNN (ND) MCKENZIE (ND) MOUNTRAIL (ND) Grand Total

CONTINENTAL RESOURCES, INC. Sum of Last Reported Total Prod (Boe/d) 275 177 256 8,187 9,560 17,263 16,848 16,623 1,043 70,498

Average of Peak Well Rate (Boe/d) 167 267 138 374 346 473 489 538 469 418

AMERADA HESS CORPORATION Sum of Last Reported Total Prod (Boe/d) 68 0 12,461 7,796 8,956 32,472 61,800


WHITING PETROLEUM CORPORATION Sum of Last Reported Total Prod (Boe/d) 2,886 3,494 114 217 432 2,365 42,752 52,816

Average of Peak Well Rate (Boe/d) 255 387 146 200 204 408 622 504

EOG RESOURCES INCORPORATED Sum of Last Reported Total Prod (Boe/d) 918 554 1,544 3,993 759 1,841 38,973 48,583


BRIGHAM OIL & GAS, L.P. Sum of Last Reported Total Prod (Boe/d) 881 998 12,270 10,261 8,071 32,481


MARATHON OIL COMPANY Sum of Last Reported Total Prod (Boe/d) 1 14,720 920 12,586 29,949


SLAWSON EXPLORATION COMPANY, INC. Sum of Last Reported Total Prod (Boe/d) 0 285 2,557 241 838 1,452 21,912 27,285


CONOCOPHILLIPS COMPANY Sum of Last Reported Total Prod (Boe/d) 0 2,076 4,855 18,917 0 25,856


XTO ENERGY, INC. Sum of Last Reported Total Prod (Boe/d) 362 94 25 6,888 7,448 3,961 6,195 429 25,402

Average of Peak Well Rate (Boe/d) 287 123 154 313 312 494 337 383 328

PETRO-HUNT CORPORATION Sum of Last Reported Total Prod (Boe/d) 0 63 2,481 459 2,860 2,685 12,920 502 21,971


OASIS PETROLEUM NORTH AMERICA LLC Sum of Last Reported Total Prod (Boe/d) 2,852 480 15 7,685 3,592 4,479 19,102


KODIAK OIL & GAS (USA) INC. Sum of Last Reported Total Prod (Boe/d) 123 6,956 8,191 3,667 18,938


DENBURY RESOURCES INC. Sum of Last Reported Total Prod (Boe/d) 55 0 214 75 2,132 15,007 17,520


ENERPLUS RESOURCES USA CORPORATION Sum of Last Reported Total Prod (Boe/d) 9,025 7,387 147 16,558


SM ENERGY COMPANY Sum of Last Reported Total Prod (Boe/d) 15 4,556 946 7,162 12,750


WPX ENERGY WILLISTON, LLC Sum of Last Reported Total Prod (Boe/d) 4,258 3,696 4,571 12,526


NEWFIELD EXPLORATION COMPANY Sum of Last Reported Total Prod (Boe/d) 107 833 232 386 9,291 10,848


OCCIDENTAL ENERGY COMPANY,INC. Sum of Last Reported Total Prod (Boe/d) 115 1,304 9,221 10,641


RRH CORPORATION (HUNT OIL COMPANY) Sum of Last Reported Total Prod (Boe/d) 0 3,289 430 6,167 9,886


MUREX PETROLEUM CORPORATION Sum of Last Reported Total Prod (Boe/d) 6 4,558 801 3,251 8,616


Total Sum of Last Reported Total Prod (Boe/d) 4,072 4,092 5,206 6,834 21,656 35,624 85,859 90,416 139,252 187,533 586,060

Total Average of Peak Well Rate (Boe/d) 196 322 310 220 289 306 435 416 483 572 423


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Barnett Exhibit 23. Barnett Map

Top 5 Producers1 Devon Energy2 Chesapeake Enegy3 XTO Energy4 EOG Resources5 Quicksilver Resources6 Other

Eagleford

Woodford

TEXAS LOUISIANA

Montague

Haynesville

Cooke

Wise

Denton

Tarrant

Parker

Johnson

Hood

Hill

OKLAHOMA

ARKANSAS

Palo Pinto

MISSISSIPPIEllis

Somervell

Exhibit 24. Barnett Economics (IRRs)

Barnett – IRRs Barnett – Top Operators

Barnett $60.00 $70.00 $80.00 $90.00 $100.00 $110.00 $120.00$2.00 -9.28% -7% -4% -1% 0% 3% 5%$2.50 -6% -3% -1% 2% 4% 6% 8%$3.00 -2% 1% 3% 6% 7% 10% 12%$3.50 2% 4% 7% 9% 11% 13% 16%$4.00 6% 8% 10% 13% 15% 17% 19%$4.50 9% 12% 14% 16% 19% 21% 23%$5.00 13% 15% 18% 20% 22% 25% 27%$5.50 17% 19% 22% 24% 26% 28% 31%$6.00 21% 23% 25% 27% 30% 32% 35%$6.50 24% 27% 29% 31% 34% 36% 38%$7.00 28% 30% 33% 35% 38% 40% 43%


1 Devon Energy 82 EOG Resources 63 XTO 44 DTE Gas Resources 35 Enervest Operating 36 Aruba Petroleum 2


Amaranth Bakken (US) Barnett Barnett

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Exhibit 25. Barnett Results by County and Operator

COMMON_OPER_NAME Data COOKE (TX) DENTON (TX) ELLIS (TX) HILL (TX) HOOD (TX) JOHNSON (TX) MONTAGUE (TX) PALO PINTO (TX) PARKER (TX) SOMERVELL (TX) TARRANT (TX) WISE (TX) Grand Total

DEVON ENERGY CORPORATION Sum of Last Reported Total Prod (Boe/d) 59,866 962 924 46,876 12,021 0 43,823 73,519 237,992


CHESAPEAKE ENERGY CORPORATION Sum of Last Reported Total Prod (Boe/d) 203 1,966 24 1,260 66,388 335 142,508 215,891


XTO ENERGY, INC. Sum of Last Reported Total Prod (Boe/d) 1,872 3 0 1,236 29,218 5,623 0 94,996 2,545 136,005


EOG RESOURCES INCORPORATED Sum of Last Reported Total Prod (Boe/d) 15,505 1,027 4,051 492 51,333 36,448 2,122 2,061 96 795 90 114,755

Average of Peak Well Rate (Boe/d) 329 419 218 121 415 279 286 186 90 856 117 335

QUICKSILVER RESOURCES, INC. Sum of Last Reported Total Prod (Boe/d) 10,008 1,972 14,057 1,711 67 4,190 26,247 58,252


CARRIZO OIL & GAS, INC. Sum of Last Reported Total Prod (Boe/d) 892 18 0 17 0 25,752 26,756


PREMIER NATURAL RESOURCES II,LLC Sum of Last Reported Total Prod (Boe/d) 5,484 16 3,530 5,084 212 2,506 152 710 1,940 21,384


ENERVEST OPERATING, LLC Sum of Last Reported Total Prod (Boe/d) 0 271 0 0 0 935 9,352 313 6,443 17,314


LEGEND NATURAL GAS IV, LP Sum of Last Reported Total Prod (Boe/d) 1,936 337 753 1,905 2,247 2,009 7,446 92 16,907


CONOCOPHILLIPS COMPANY Sum of Last Reported Total Prod (Boe/d) 174 6,971 0 63 0 0 7,308 14,516


VANTAGE FORT WORTH ENERGY LLC Sum of Last Reported Total Prod (Boe/d) 8 1,193 98 0 402 9,466 603 11,770


PIONEER NATURAL RESOURCES COMPANY Sum of Last Reported Total Prod (Boe/d) 291 0 3,484 13 868 1,616 6,272


J-W OPERATING COMPANY Sum of Last Reported Total Prod (Boe/d) 3,626 0 971 761 5,358


TITAN OPERATING, LLC Sum of Last Reported Total Prod (Boe/d) 1,025 99 627 2,783 268 496 5,298


ARUBA PETROLEUM, LTD. Sum of Last Reported Total Prod (Boe/d) 0 223 0 1,451 2,137 3,810


EAGLERIDGE OPERATING, LLC Sum of Last Reported Total Prod (Boe/d) 1,877 1,921 3,798


TEXAS INTERNATIONAL OPER., LLC Sum of Last Reported Total Prod (Boe/d) 2,613 2,613


BARNETT SHALE OPERATING LLC Sum of Last Reported Total Prod (Boe/d) 1,097 221 79 851 2,248


ARP BARNETT, LLC Sum of Last Reported Total Prod (Boe/d) 597 0 1,564 2,161


HILLWOOD O & G OPERATING CO LP Sum of Last Reported Total Prod (Boe/d) 1,947 1,947


Total Sum of Last Reported Total Prod (Boe/d) 16,098 102,352 3,512 8,939 25,134 209,123 42,144 3,056 39,923 4,637 361,823 105,998 930,849

Total Average of Peak Well Rate (Boe/d) 276 198 296 174 173 354 238 137 160 152 364 179 257


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Eagle Ford Exhibit 26. Eagle Ford Map

Major Producers1 EOG Resources2 Geosouthern Energy3 Anadarko Petroleum4 ConocoPhillips5 Talisman Energy6 Other

Barnett

TEXAS

MEXICO

Dimmit

La Salle

Webb

McMullen

Atascosa

Live Oak

Karnes

Wilson

Gonzales

Dewitt

Permian

Exhibit 27. Eagle Ford Economics (IRRs)

Eagle Ford – IRRs Eagle Ford – Top Operators

Eagle Ford $60.00 $70.00 $80.00 $90.00 $100.00 $110.00 $120.00$2.00 17% 26% 37% 44% 58% 68% 80%$2.50 18% 27% 38% 46% 59% 70% 82%$3.00 19% 28% 39% 47% 60% 71% 83%$3.50 19% 29% 40% 48% 62% 73% 85%$4.00 20% 30% 41% 49% 63% 74% 86%$4.50 21% 31% 42% 50% 64% 75% 88%$5.00 22% 32% 43% 51% 65% 77% 89%$5.50 23% 33% 44% 52% 67% 78% 91%$6.00 24% 34% 45% 54% 68% 79% 92%$6.50 25% 35% 46% 55% 69% 81% 94%$7.00 26% 36% 47% 56% 70% 82% 95%


1 Chesapeake Energy 262 Marathon 233 BHP-Billiton 224 EOG Resources 195 ConocoPhillips 116 Pioneer Natural 11


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Exhibit 28. Eagle Ford Results by County and Operator

COMMON_OPER_NAME Data WILSON (TX) ATASCOSA (TX) MCMULLEN (TX) LIVE OAK (TX) DIMMIT (TX) GONZALES (TX) LASALLE (TX) DEWITT (TX) WEBB (TX) KARNES (TX) Grand Total

EOG RESOURCES INCORPORATED Sum of Last Reported Total Prod (Boe/d) 4,609 3,893 1,794 64,238 13,183 241 342 48,403 138,798

Average of Peak Well Rate (Boe/d) 427 366 488 1,099 741 699 350 804 834

GEOSOUTHERN ENERGY CORPORATION Sum of Last Reported Total Prod (Boe/d) 1,340 77,505 294 79,222

Average of Peak Well Rate (Boe/d) 785 1,053 985 1,040

ANADARKO PETROLEUM CORPORATION Sum of Last Reported Total Prod (Boe/d) 48,514 220 17,101 66,325


CONOCOPHILLIPS COMPANY Sum of Last Reported Total Prod (Boe/d) 18,747 14,338 29,260 62,652

Average of Peak Well Rate (Boe/d) 937 1,042 950 959

PIONEER NATURAL RESOURCES COMPANY Sum of Last Reported Total Prod (Boe/d) 911 120 16,961 166 22,856 20,854 62,083

Average of Peak Well Rate (Boe/d) 442 470 832 83 1,025 1,226 965

CHESAPEAKE ENERGY CORPORATION Sum of Last Reported Total Prod (Boe/d) 8,814 22,243 9,080 13,207 55,485


ROSETTA RESOURCES INC. Sum of Last Reported Total Prod (Boe/d) 1,102 162 546 35,373 37,183

Average of Peak Well Rate (Boe/d) 707 780 1,773 926 925

PETROHAWK ENERGY CORPORATION Sum of Last Reported Total Prod (Boe/d) 7,073 21,893 5,273 35,210

Average of Peak Well Rate (Boe/d) 1,102 1,024 1,318 991

SM ENERGY COMPANY Sum of Last Reported Total Prod (Boe/d) 34,381 34,982


EL PASO CORPORATION Sum of Last Reported Total Prod (Boe/d) 0 710 30,258 167 31,317


LEWIS PETRO PROPERTIES, INC. Sum of Last Reported Total Prod (Boe/d) 1,921 6,336 22,414 30,671


MARATHON OIL EF LLC Sum of Last Reported Total Prod (Boe/d) 251 5,436 243 5,894 165 15,573 27,563


TALISMAN ENERGY USA INC. Sum of Last Reported Total Prod (Boe/d) 5,424 1,086 5,026 4,742 6,798 23,223

Average of Peak Well Rate (Boe/d) 481 666 423 1,013 811 628

PLAINS EXPLORATION & PRODUCTION COMPANY Sum of Last Reported Total Prod (Boe/d) 17,869 17,869

Average of Peak Well Rate (Boe/d) 1,011 1,011

MURPHY OIL CORPORATION Sum of Last Reported Total Prod (Boe/d) 410 1,528 1,899 488 12,310 16,635


CARRIZO OIL & GAS, INC. Sum of Last Reported Total Prod (Boe/d) 2,534 3,538 8,533 14,604


PENN VIRGINIA OIL & GAS CORPORATION Sum of Last Reported Total Prod (Boe/d) 12,672 12,672


PALOMA RESOURCES, LLC Sum of Last Reported Total Prod (Boe/d) 2,910 4,402 7,312

Average of Peak Well Rate (Boe/d) 1,227 1,148 1,179

XTO ENERGY, INC. Sum of Last Reported Total Prod (Boe/d) 112 1,598 271 5,314 7,294


COMSTOCK RESOURCES Sum of Last Reported Total Prod (Boe/d) 631 6,072 162 6,865



Total Average of Peak Well Rate (Boe/d) 396 399 646 894 460 994 709 1,041 749 878 747


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

Wel

ls D

rille

d

HighBaseLow


-

2,000

4,000

6,000

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Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

Q2/19E

Q1/20E

Q4/20E

Mm

cfe/

d

-

333

667

1,000

1,333

1,667

2,000

2,333

2,667

3,000

3,333

Mbo

e/d

Liquids (Right)

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

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18,000

20,000

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

Q2/19E

Q1/20E

Q4/20E

Mm

cfe/

d

0

333

667

1,000

1,333

1,667

2,000

2,333

2,667

3,000

3,333

Mbo

e/d

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Base

Low


0

50,000

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

HighBaseLow

0

50,000

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

HighBaseLow


0.0

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00 03 06 09 12 15 18 21 24 27 30 33 36 39 42


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cfe/

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0

83

167

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333

417

500

583

667

750

Boe/

d


0

100

200

300

400

500

600

700

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037

074

01,1

101,4

801,8

502,2

202,5

902,9

603,3

303,7

004,0

704,4

404,8

105,1

805,5

505,9

206,2

906,6

60


Freq

uenc

y


Amaranth

Bakken (US)

Barnett

Eagleford

Eag

le F

ord

H

orn

Riv

er

Montney

VET


163


Amaranth

Bakken (US)

Barnett

Eagleford

Eag

le F

ord

Ho

rn R

iver

Montney

VET

Fayetteville Exhibit 29. Fayetteville Map

Top 5 Producers1 Southwestern Energy2 XTO Energy3 BHP Billiton4 Arrington, David5 Traton6 Other

Woodford

OKLAHOMA TENNESSEE

MISSISSIPPI

TEXAS

Jackson

Pope

Van Buren

Cleburne

Independence

White

Faulkner

Conway

ARKANSAS

Exhibit 30. Fayetteville Economics (IRRs)

Fayetteville – IRRs Fayetteville – Top Operators

Fayetteville $60.00 $70.00 $80.00 $90.00 $100.00 $110.00 $120.00$2.00 -16% -16% -16% -16% -16% -16% -16%$2.50 -10% -10% -10% -10% -10% -10% -10%$3.00 -2% -2% -2% -2% -2% -2% -2%$3.50 6% 6% 6% 6% 6% 6% 6%$4.00 14% 14% 14% 14% 14% 14% 14%$4.50 21% 21% 21% 21% 21% 21% 21%$5.00 29% 29% 29% 29% 29% 29% 29%$5.50 37% 37% 37% 37% 37% 37% 37%$6.00 44% 44% 44% 44% 44% 44% 44%$6.50 52% 52% 52% 52% 52% 52% 52%$7.00 61% 61% 61% 61% 61% 61% 61%


1 Southwestern Energy 112 BHP-Billiton 53 XTO 5456


Amaranth Bakken (US) Barnett Eagleford Fayetteville Fayetteville Montney V

ET

Exhibit 31. Fayetteville Results by County and Operator

COMMON_OPER_NAME Data JACKSON (AR) POPE (AR) INDEPENDENCE (AR) FAULKNER (AR) CLEBURNE (AR) WHITE (AR) CONWAY (AR) VAN BUREN (AR) Grand Total

SOUTHWESTERN ENERGY COMPANY Sum of Last Reported Total Prod (Boe/d) 924 16,962 45,928 41,033 96,314 105,881 307,079


XTO ENERGY, INC. Sum of Last Reported Total Prod (Boe/d) 320 0 5,115 2,161 19,071 28,728 1,548 7,920 64,863


BHP BILLITON PETROLEUM (FAYETTEVILLE), LLC Sum of Last Reported Total Prod (Boe/d) 489 133 10,754 5,678 31,352 5,012 10,777 64,194


ARRINGTON,DAVID H. OIL & GAS,INC Sum of Last Reported Total Prod (Boe/d) 360 0 409 769


TRATON OPERATING COMPANY Sum of Last Reported Total Prod (Boe/d) 129 129


SH EXPLORATION, LLC Sum of Last Reported Total Prod (Boe/d) 44 44


FOUNDATION ENERGY MANAGEMENT, LLC Sum of Last Reported Total Prod (Boe/d) 8 8


WOLF EXPLORATION, INC. Sum of Last Reported Total Prod (Boe/d) 1

Average of Peak Well Rate (Boe/d) 1

Total Sum of Last Reported Total Prod (Boe/d) 808 932 5,608 29,876 70,676 101,113 102,875 125,160 437,086

Total Average of Peak Well Rate (Boe/d) 136 130 228 313 352 328 370 369 344


Amaranth Bakken (US) Barnett Eagleford Fayetteville Fayetteville Montney V

ET


166

Fayetteville Play Profile Rigs Running Wells Drilled

0

5

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15

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30

35

40

45

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

Rig

s R

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ng

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0

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

Wel

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Q1/08

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Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

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Q4/20E

Mm

cfe/

d

-

83

167

250

333

417

500

583

667

750

Mbo

e/d

Liquids (Right)

-

500

1,000

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2,000

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3,000

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Q1/08

Q4/08

Q3/09

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Q1/11

Q4/11

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Q2/13E

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Q3/15E

Q2/16E

Q1/17E

Q4/17E

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Mm

cfe/

d

0

83

167

250

333

417

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583

667

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e/d

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

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

Low Base High


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00 03 06 09 12 15 18 21 24 27 30 33 36 39 42


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cfe/

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0

42

83

125

167

208

250

292

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375

417

Boe/

d


0

50

100

150

200

250

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2 120 238 356 474 592 710 828 946 1,064

Freq

uenc

y


Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Fayett

evil

le

Montney

VET


167


Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Fayette

ville

Montney

VET

Haynesville Exhibit 32. Haynesville Map

Top 5 Producers1 Chesapeake Energy2 EXCO Resources3 Petrohawk Energy4 Encana Corp.5 El Paso Corp.6 Other

Barnett

Eagleford

Woodford

TEXAS LOUISIANA

BossierCaddo

Red River

De Soto

Sabine

Panola

Bienville

Shelby

Nacogdoches

San Augustine

OKLAHOMAARKANSAS

MISSISSIPPI

Exhibit 33. Haynesville Economics (IRRs)

Haynesville – IRRs Haynesville – Top Operators

Haynesville $60.00 $70.00 $80.00 $90.00 $100.00 $110.00 $120.00$2.00 -9% -9% -9% -9% -9% -9% -9%$2.50 -5% -5% -5% -5% -5% -5% -5%$3.00 0% 0% 0% 0% 0% 0% 0%$3.50 5% 5% 5% 5% 5% 5% 5%$4.00 11% 11% 11% 11% 11% 11% 11%$4.50 16% 16% 16% 16% 16% 16% 16%$5.00 22% 22% 22% 22% 22% 22% 22%$5.50 27% 27% 27% 27% 27% 27% 27%$6.00 32% 32% 32% 32% 32% 32% 32%$6.50 38% 38% 38% 38% 38% 38% 38%$7.00 45% 45% 45% 45% 45% 45% 45%


1 Anadarko 82 Exco Resources 53 XTO 54 Indigo Drilling 45 Petrohawk 46 Devon Energy 3


Amaranth Bakken (US) Barnett Eagleford Fayetteville Haynesville Haynesville

VET

Exhibit 34. Haynesville Results by County and Operator

COMMON_OPER_NAME Data PANOLA (TX) SHELBY (TX) SAN AUGUSTINE (TX) BIENVILLE (LA) BOSSIER (LA) NACOGDOCHES (TX) SABINE (LA) CADDO (LA) RED RIVER (LA) DE SOTO (LA) Grand Total

CHESAPEAKE ENERGY CORPORATION Sum of Last Reported Total Prod (Boe/d) 4,235 3,054 5,351 16,648 24,620 47,977 6,893 124,846 238,006

Average of Peak Well Rate (Boe/d) 625 961 1,298 1,231 1,099 1,215 1,634 1,240 1,206

EXCO RESOURCES, INC. Sum of Last Reported Total Prod (Boe/d) 468 18,656 22,268 3,193 159,846 204,785

Average of Peak Well Rate (Boe/d) 1,255 1,637 1,958 896 1,857 1,781

PETROHAWK ENERGY CORPORATION Sum of Last Reported Total Prod (Boe/d) 10,260 36,033 73 8,401 36,284 42,276 27,378 161,871

Average of Peak Well Rate (Boe/d) 956 1,693 657 865 1,283 1,621 1,394 1,433

ENCANA CORPORATION Sum of Last Reported Total Prod (Boe/d) 358 4,348 377 12,102 42,461 19,570 79,447

Average of Peak Well Rate (Boe/d) 1,124 2,046 2,656 1,803 1,980 1,827 1,902

XTO ENERGY, INC. Sum of Last Reported Total Prod (Boe/d) 16,520 27,166 13,421 879 1,669 4,331 4,028 71,739

Average of Peak Well Rate (Boe/d) 1,218 1,073 1,320 584 1,577 1,432 1,592 1,057

RD SHELL Sum of Last Reported Total Prod (Boe/d) 21,755 36,043 10,015 67,812

Average of Peak Well Rate (Boe/d) 1,719 1,928 1,306 1,719

EP ENERGY E&P COMPANY, LP Sum of Last Reported Total Prod (Boe/d) 67,202 67,202

Average of Peak Well Rate (Boe/d) 1,728 1,728

QEP ENERGY COMPANY Sum of Last Reported Total Prod (Boe/d) 35,822 6,346 7,314 9,892 1,393 60,766

Average of Peak Well Rate (Boe/d) 1,393 858 1,393 1,577 1,755 1,384

EOG RESOURCES INCORPORATED Sum of Last Reported Total Prod (Boe/d) 494 7,824 33,248 2,644 333 6,941 51,484

Average of Peak Well Rate (Boe/d) 702 1,497 1,476 1,410 802 1,360 1,411

COMSTOCK RESOURCES Sum of Last Reported Total Prod (Boe/d) 205 3,308 54 35,587 40,184

Average of Peak Well Rate (Boe/d) 884 1,091 752 1,140 1,100

SAMSON INVESTMENT COMPANY Sum of Last Reported Total Prod (Boe/d) 269 307 3,607 188 1,564 3,908 12,497

Average of Peak Well Rate (Boe/d) 1,238 580 1,136 765 1,971 1,280 846

BEUSA ENERGY, LLC Sum of Last Reported Total Prod (Boe/d) 11,786 12,125


NFR ENERGY, LLC Sum of Last Reported Total Prod (Boe/d) 5,201 0 11,514

Average of Peak Well Rate (Boe/d) 1,146 320 604

J-W OPERATING COMPANY Sum of Last Reported Total Prod (Boe/d) 737 211 1,896 237 7,265 10,346

Average of Peak Well Rate (Boe/d) 1,367 576 892 2,410 1,601 1,326

ANADARKO PETROLEUM CORPORATION Sum of Last Reported Total Prod (Boe/d) 6,540 10,011


GMX RESOURCES, INC. Sum of Last Reported Total Prod (Boe/d) 7,808


GOODRICH PETROLEUM COMPANY Sum of Last Reported Total Prod (Boe/d) 570 379 855 3,323 749 1,535 7,777

Average of Peak Well Rate (Boe/d) 516 646 615 1,531 1,510 1,675 979

EAGLECORP Sum of Last Reported Total Prod (Boe/d) 5,678 959 6,636

Average of Peak Well Rate (Boe/d) 1,488 959 1,440

FOREST OIL CORPORATION Sum of Last Reported Total Prod (Boe/d) 147 6,088 6,301

Average of Peak Well Rate (Boe/d) 475 1,469 779

DENBURY RESOURCES INC. Sum of Last Reported Total Prod (Boe/d) 4,163

Average of Peak Well Rate (Boe/d) 9,698

Total Sum of Last Reported Total Prod (Boe/d) 32,441 37,380 51,884 53,049 61,675 65,646 78,653 102,205 147,050 482,893 1,165,187

Total Average of Peak Well Rate (Boe/d) 853 853 1,492 1,224 1,217 1,389 1,272 1,128 1,820 1,461 1,138


Amaranth Bakken (US) Barnett Eagleford Fayetteville Haynesville Haynesville

VET


170

Haynesville Profile Rigs Running Wells Drilled

0

50

100

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

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s R

unni

ng

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1,200

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

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Q4/14E

Q3/15E

Q2/16E

Q1/17E

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Q4/20E

Mm

cfe/

d

0

167

333

500

667

833

1,000

1,167

1,333

Mbo

e/d

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-

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Q1/08

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Q2/10

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Q4/11

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Q2/13E

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Q4/14E

Q3/15E

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Q1/17E

Q4/17E

Q3/18E

Q2/19E

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Mm

cfe/

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0

167

333

500

667

833

1,000

1,167

1,333

Mbo

e/d

Low Base High


-300,000

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

HighBaseLow

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

HighBaseLow


0.0

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/d


0

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300

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1 929 1,857 2,785 3,713 4,641 5,569 6,497 7,425 8,353


Freq

uenc

y


Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Haynesville

Hayn

esv

ille

VET


171


Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Haynesville

Hayn

esv

ille

VET

Marcellus Exhibit 35. Marcellus Map

Top 5 Producers1 Chesapeake Energy2 Talisman Energy3 Cabot Oil & Gas Crop.4 Range Resources5 Anadarko Petroleum6 Other

Susquehanna

BradfordTioga

Wyoming

Lycoming

Clinton

Westmoreland

Fayette

Washington

Greene

Exhibit 36. Marcellus Economics (IRRs)

Marcellus – IRRs Marcellus – Top Operators

Marcellus $60.00 $70.00 $80.00 $90.00 $100.00 $110.00 $120.00$2.00 -10% -10% -10% -10% -10% -10% -9%$2.50 -4% -4% -3% -3% -3% -3% -3%$3.00 6% 6% 6% 6% 6% 6% 6%$3.50 15% 15% 15% 15% 16% 16% 16%$4.00 24% 25% 25% 25% 25% 25% 25%$4.50 34% 34% 34% 34% 34% 35% 35%$5.00 43% 43% 43% 44% 44% 44% 44%$5.50 52% 53% 53% 53% 53% 53% 53%$6.00 62% 62% 62% 62% 63% 63% 63%$6.50 71% 71% 72% 72% 72% 72% 72%$7.00 85% 85% 85% 86% 86% 86% 86%


1 Chesapeake Energy 222 CNX Gas Co LLC 93 Antero Resources 84 Shell 85 EQT 76 Range Resources 7


Amaranth Bakken (US) Barnett Eagleford Fayetteville Haynesville Marcellus Marcellus

Exhibit 37. Marcellus Results by County and Operator

COMMON_OPER_NAME Data CLINTON (PA) WYOMING (PA) FAYETTE (PA) WESTMORELAND (PA) GREENE (PA) TIOGA (PA) LYCOMING (PA) WASHINGTON (PA) SUSQUEHANNA (PA) BRADFORD (PA) Grand Total

CHESAPEAKE ENERGY CORPORATION Sum of Last Reported Total Prod (Boe/d) 2,393 5 0 0 0 597 38,129 93,084 134,224


TALISMAN ENERGY USA INC. Sum of Last Reported Total Prod (Boe/d) 22,188 0 74,151 96,340


CABOT OIL & GAS CORPORATION Sum of Last Reported Total Prod (Boe/d) 87,533 87,533


RANGE RESOURCES CORPORATION Sum of Last Reported Total Prod (Boe/d) 0 3 0 778 17,081 64,741 0 83,784


ANADARKO PETROLEUM CORPORATION Sum of Last Reported Total Prod (Boe/d) 10,477 36,205 47,476


EQT PRODUCTION LLC Sum of Last Reported Total Prod (Boe/d) 32,137 146 1,967 37,824


RD SHELL Sum of Last Reported Total Prod (Boe/d) 23,343 3,809 1,191 28,344


NATIONAL FUEL GAS COMPANY Sum of Last Reported Total Prod (Boe/d) 18,981 0 20,297


CNX GAS COMPANY, LLC Sum of Last Reported Total Prod (Boe/d) 869 14,747 4,231 19,855


SOUTHWESTERN ENERGY COMPANY Sum of Last Reported Total Prod (Boe/d) 0 19,404 19,404


CHEVRON APPALACHIA LLC Sum of Last Reported Total Prod (Boe/d) 6,591 2,521 5,365 3,440 18,278


EXCO RESOURCES, INC. Sum of Last Reported Total Prod (Boe/d) 6,094 13,266


WPX ENERGY APPALACHIA LLC Sum of Last Reported Total Prod (Boe/d) 8,226 1,796 12,151


ENERGY CORP OF AMER Sum of Last Reported Total Prod (Boe/d) 10,919 11,214


PA GEN ENERGY CORP Sum of Last Reported Total Prod (Boe/d) 5,588 11,198


EXCO RESOURCES PA LLC Sum of Last Reported Total Prod (Boe/d) 7,534 0 11,154


CITRUS ENERGY CORPORATION Sum of Last Reported Total Prod (Boe/d) 10,245 10,245


XTO ENERGY, INC. Sum of Last Reported Total Prod (Boe/d) 262 0 1,590 7,969 10,195


CHIEF OIL & GAS LLC Sum of Last Reported Total Prod (Boe/d) 696 0 0 0 3,751 2,701 7,147


PHILLIPS EXPLORATION INC Sum of Last Reported Total Prod (Boe/d) 4,386 0 0 6,388





Amaranth Bakken (US) Barnett Eagleford Fayetteville Haynesville Marcellus Marcellus


174

Marcellus Play Profile Rigs Running Wells Drilled

0

50

100

150

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250

300

350

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

Rig

s R

unni

ng

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1,000

1,500

2,000

2,500

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

Wel

ls D

rille

d

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-

1,250

2,500

3,750

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15,000

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

Q2/19E

Q1/20E

Q4/20E

Mm

cfe/

d

-

208

417

625

833

1,042

1,250

1,458

1,667

1,875

2,083

2,292

2,500

Mbo

e/d

Liquids (Right)

-

1,250

2,500

3,750

5,000

6,250

7,500

8,750

10,000

11,250

12,500

13,750

15,000

Q1/08

Q4/08

Q3/09

Q2/10

Q1/11

Q4/11

Q3/12E

Q2/13E

Q1/14E

Q4/14E

Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

Q2/19E

Q1/20E

Q4/20E

Mm

cfe/

d

0

208

417

625

833

1,042

1,250

1,458

1,667

1,875

2,083

2,292

2,500

Mbo

e/d

Low Base High


0

100,000

200,000

300,000

400,000

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600,000

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

HighBaseLow

0

100,000

200,000

300,000

400,000

500,000

600,000

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

HighBaseLow


0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

00 03 06 09 12 15 18 21 24 27 30 33 36 39


MM

cfe/

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0

167

333

500

667

833

1,000

1,167

Boe

/d

Q1/08 Q2/08 Q3/08 Q4/08Q1/09 Q2/09 Q3/09 Q4/09Q1/10 Q2/10 Q3/10 Q4/10Q1/11 Q2/11 Q3/11 Q4/11

0

300

600

900

1200

1500

1800

0 400 800 1,200 1,600 2,000 2,400 2,800 3,200 3,600


Freq

uenc

y


Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Haynesville

Marcellus

Marc

ellu

s


175


Amaranth

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Mississippi Lime Exhibit 38. Mississippi Lime Map

Top 5 Producers1 Sandridge Exploration2 Chesapeaske Energy3 Eagle Energy4 Range Resources5 Primexx6 Other

Woodford

KANSAS

OKLAHOMA

Woods AlfalfaGrant Kay Osage

Woodward

Major

Garfield

Payne

Noble

Exhibit 39. Mississippi Lime Economics (IRRs)

Mississippi Lime – IRRs Mississippi Lime – Top Operators

ML $60.00 $70.00 $80.00 $90.00 $100.00 $110.00 $120.00$2.00 3% 8% 12% 17% 22% 27% 32%$2.50 4% 9% 14% 18% 23% 28% 33%$3.00 5% 10% 15% 19% 24% 29% 34%$3.50 6% 11% 16% 20% 26% 30% 36%$4.00 7% 12% 17% 21% 27% 32% 37%$4.50 8% 13% 18% 22% 28% 33% 38%$5.00 9% 14% 19% 23% 29% 34% 40%$5.50 10% 15% 20% 25% 30% 36% 41%$6.00 11% 16% 21% 26% 32% 37% 42%$6.50 12% 17% 23% 27% 33% 38% 44%$7.00 14% 18% 24% 28% 34% 39% 45%


1 Sandridge 252 Chesapeake Energy 203 Devon Energy 74 Chaparral USA Energy 45 Shell 46 Longfellow 3


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Exhibit 40. Mississippi Lime Results by County and Operator

COMMON_OPER_NAME Data WOODWARD (OK) NOBLE (OK) GARFIELD (OK) PAYNE (OK) MAJOR (OK) OSAGE (OK) KAY (OK) GRANT (OK) ALFALFA (OK) WOODS (OK) Grand Total

SANDRIDGE ENERGY, INC. Sum of Last Reported Total Prod (Boe/d) 9 33 28 615 3,053 287 4,025


CHESAPEAKE ENERGY CORPORAT Sum of Last Reported Total Prod (Boe/d) 20 46 619 2,538 3,223


EAGLE ENERGY PRODUCTION LLC Sum of Last Reported Total Prod (Boe/d) 310 351 661

Average of Peak Well Rate (Boe/d) 1,852 318 1,034

RANGE RESOURCES CORPORATIONSum of Last Reported Total Prod (Boe/d) 113 5 521 639


PRIMEXX OPERATING CORPORATIOSum of Last Reported Total Prod (Boe/d) 410 410


GOOD VAUGHN OIL COMPANY LLC Sum of Last Reported Total Prod (Boe/d) 353 353


REDLAND RESOURCES, INC. Sum of Last Reported Total Prod (Boe/d) 237 237


UNION VALLEY PETROLEUM CORPOSum of Last Reported Total Prod (Boe/d) 219 219


JACK EXPLORATION, INC. Sum of Last Reported Total Prod (Boe/d) 202 202


CALYX ENERGY LLC Sum of Last Reported Total Prod (Boe/d) 180 180

Average of Peak Well Rate (Boe/d) 86 86Total Sum of Last Reported Total Prod (Boe/d) 125 160 197 199 323 363 600 1,498 4,061 4,196 11,830Total Average of Peak Well Rate (Boe/d) 102 27 33 57 77 50 53 86 308 122 117


Mississippi Lime

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178

Mississippi Lime Play Profile Rigs Running Wells Drilled

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167

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333

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250

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

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HighBaseLow


- Data Not Representative -

- Data Not Representative -


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ime

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Permian (Horizontal) Exhibit 41. Permian (Horizontal) Map

Top 5 Producers1 Occidental Energy2 Kinder Morgan3 XTO Energy4 Chevron 5 Concho Resources6 Other

Eagleford

TEXAS

MEXICO

Barnett

WoodfordNEW MEXICOLea

Eddy

WardEctor

Andrews

Gaines

YoakumHockley

Scurry

Pecos

Exhibit 42. Permian (Horizontal) Economics (IRRs)

Permian (Horizontal) – IRRs Permian (Horizontal) – Top Operators

PermianHzDir $60.00 $70.00 $80.00 $90.00 $100.00 $110.00 $120.00$2.00 2% 6% 10% 15% 19% 24% 28%$2.50 2% 7% 11% 15% 20% 24% 29%$3.00 3% 7% 12% 16% 21% 25% 30%$3.50 3% 8% 12% 16% 21% 26% 30%$4.00 4% 8% 13% 17% 22% 26% 31%$4.50 5% 9% 14% 18% 23% 27% 32%$5.00 5% 10% 14% 18% 23% 28% 33%$5.50 6% 10% 15% 19% 24% 28% 33%$6.00 6% 11% 15% 19% 25% 29% 34%$6.50 7% 11% 16% 20% 25% 30% 35%$7.00 8% 12% 17% 21% 26% 30% 35%


1 Occidental 92 Apache 73 Chesapeake Energy 74 Devon Energy 75 Energen Resources 76 Petrohawk 6


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Exhibit 43. Permian (Horizontal) Results by County and Operator

COMMON_OPER_NAME Data LEA (NM) HOCKLEY (TX) ANDREWS (TX) ECTOR (TX) SCURRY (TX) GAINES (TX) WARD (TX) YOAKUM (TX) EDDY (NM) PECOS (TX) Grand Total

OCCIDENTAL ENERGY COMPANY,INC. Sum of Last Reported Total Prod (Boe/d) 302 24,228 10,266 11,116 0 9,383 1,272 62,498 5,175 1 170,502

Average of Peak Well Rate (Boe/d) 143 2,313 6,741 751 0 1,174 992 3,508 352 130 1,539

KINDER MORGAN INCORPORATED Sum of Last Reported Total Prod (Boe/d) 40,931 82,143 124,941

Average of Peak Well Rate (Boe/d) 4,302 2,931 3,320

XTO ENERGY, INC. Sum of Last Reported Total Prod (Boe/d) 297 15,501 7,168 5,927 2,367 4,863 871 443 47,130

Average of Peak Well Rate (Boe/d) 161 2,497 5,174 1,378 1,207 2,164 304 1,767 1,282

CHEVRON, U.S.A., INC. Sum of Last Reported Total Prod (Boe/d) 1,505 6,979 6,180 185 4,183 159 0 1,498 843 39,607

Average of Peak Well Rate (Boe/d) 154 1,199 1,892 438 1,004 185 0 129 1,303 645

CONCHO RESOURCES INC. Sum of Last Reported Total Prod (Boe/d) 9,042 183 0 86 22,925 37,498


APACHE CORPORATION Sum of Last Reported Total Prod (Boe/d) 902 3,591 3,401 5,225 69 175 243 3,604 266 513 31,574

Average of Peak Well Rate (Boe/d) 43 1,345 806 4,715 79 196 1,171 2,888 115 1,233 604

DEVON ENERGY CORPORATION Sum of Last Reported Total Prod (Boe/d) 1,274 92 431 2,717 0 212 3,576 722 9,690 0 26,893

Average of Peak Well Rate (Boe/d) 60 252 198 374 0 360 939 747 129 86 241

AMERADA HESS CORPORATION Sum of Last Reported Total Prod (Boe/d) 0 24,277 24,277

Average of Peak Well Rate (Boe/d) 0 19,898 14,213

CIMAREX ENERGY COMPANY Sum of Last Reported Total Prod (Boe/d) 8,307 17 4,012 8 6,323 30 23,250

Average of Peak Well Rate (Boe/d) 142 2,602 543 175 100 206 171

CHESAPEAKE ENERGY CORPORATION Sum of Last Reported Total Prod (Boe/d) 96 17 0 9,154 1,388 138 19,647

Average of Peak Well Rate (Boe/d) 146 72 20 676 137 1,500 309

PIONEER NATURAL RESOURCES COMPANY Sum of Last Reported Total Prod (Boe/d) 0 0 19,528

Average of Peak Well Rate (Boe/d) 1 63 1,361

EOG RESOURCES INCORPORATED Sum of Last Reported Total Prod (Boe/d) 3,086 199 274 531 2,952 0 18,772

Average of Peak Well Rate (Boe/d) 119 501 678 1,087 94 112 300

ENERGEN CORPORATION Sum of Last Reported Total Prod (Boe/d) 61 1,471 4,749 16,915


SANDRIDGE ENERGY, INC. Sum of Last Reported Total Prod (Boe/d) 55 729 2,331 245 10,600 16,835


ANADARKO PETROLEUM CORPORATION Sum of Last Reported Total Prod (Boe/d) 0 0 11,942 16,592


BOPCO, L.P. Sum of Last Reported Total Prod (Boe/d) 245 11,365 0 12,890

Average of Peak Well Rate (Boe/d) 1,118 326 0 451

CONOCOPHILLIPS COMPANY Sum of Last Reported Total Prod (Boe/d) 586 238 7,097 11 267 10,294

Average of Peak Well Rate (Boe/d) 111 629 1,311 304 1,801 580

WHITING PETROLEUM CORPORATION Sum of Last Reported Total Prod (Boe/d) 8 495 6,940 193 686 8,834

Average of Peak Well Rate (Boe/d) 170 707 6,099 2,118 387 1,095

YATES CO INTERNATIONAL (YATES FAMILY) Sum of Last Reported Total Prod (Boe/d) 940 6,458 7,721


MEWBOURNE HOLDINGS INC Sum of Last Reported Total Prod (Boe/d) 1,233 275 5,941 7,619



Total Average of Peak Well Rate (Boe/d) 114 1,396 1,429 775 2,335 1,109 781 2,321 152 798 495


Permian (Hz)

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Amaranth Permian (Hz)

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182

Permian (Horizontal) Play Profile Rigs Running Wells Drilled

0

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

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-36,000

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108,000

132,000

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180,000

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

HighBaseLow

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-12,000

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84,000

108,000

132,000

156,000

180,000

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

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0 292 584 876 1,168 1,460 1,752 2,044 2,336 2,628 2,920


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183

Permian (Vertical) Play Profile Rigs Running Wells Drilled

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

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

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Woodford Exhibit 44. Woodford Map

Top 5 Producers1 Devon Energy2 Newfield Exploration3 BP4 Petroquest Energy5 Antero Resources6 Other

Barnett

OKLAHOMA

Fayetteville

ARKANSASTEXAS

MISSOURI

Blaine

Dewey

Canadian

Caddo

Grady

CarterCoal

Atoka

Hughes

Pittsburg

Exhibit 45. Woodford Economics (IRRs)

Woodford – IRRs Woodford – Top Operators

Woodford $60.00 $70.00 $80.00 $90.00 $100.00 $110.00 $120.00$2.00 -13% -5% 2% 10% 17% 24% 32%$2.50 -11% -3% 4% 11% 19% 26% 34%$3.00 -9% -2% 6% 13% 21% 28% 36%$3.50 -7% 0% 8% 15% 23% 30% 38%$4.00 -5% 2% 10% 17% 25% 32% 40%$4.50 -4% 4% 11% 19% 26% 34% 42%$5.00 -2% 6% 13% 21% 28% 36% 44%$5.50 0% 8% 15% 22% 30% 38% 46%$6.00 2% 9% 17% 24% 32% 40% 47%$6.50 4% 11% 19% 26% 34% 42% 49%$7.00 6% 13% 21% 28% 36% 44% 51%


1 Devon Energy 122 XTO Energy 123 Cimarex Energy 64 Continental Resource 55 Chesapeake Energy 36 Eagle Rock Exploration 3


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Exhibit 46. Woodford Results by County and Operator

COMMON_OPER_NAME Data GRADY (OK) DEWEY (OK) CADDO (OK) CARTER (OK) ATOKA (OK) BLAINE (OK) HUGHES (OK) CANADIAN (OK) COAL (OK) PITTSBURG (OK) Grand Total

DEVON ENERGY CORPORATION Sum of Last Reported Total Prod (Boe/d) 619 1,616 4,958 3,740 8,404 5,905 73 25,315


NEWFIELD EXPLORATION COMPANY Sum of Last Reported Total Prod (Boe/d) 1,308 0 6,980 6,776 4,902 19,966


BP AMERICA PRODUCTION COMPANY Sum of Last Reported Total Prod (Boe/d) 0 145 4,737 3,808 9,976 18,666


PETROQUEST ENERGY, L.L.C. Sum of Last Reported Total Prod (Boe/d) 12,637 12,637


ANTERO RESOURCES CORPORATION Sum of Last Reported Total Prod (Boe/d) 0 950 267 816 6,357 8,390


CIMAREX ENERGY COMPANY Sum of Last Reported Total Prod (Boe/d) 0 225 95 89 6,263 19 223 7,033


SM ENERGY COMPANY Sum of Last Reported Total Prod (Boe/d) 109 4,337 4,446


QEP ENERGY COMPANY Sum of Last Reported Total Prod (Boe/d) 878 3,303 4,210


PABLO ENERGY II, LLC Sum of Last Reported Total Prod (Boe/d) 375 2,940 3,315


CHESAPEAKE ENERGY CORPORATION Sum of Last Reported Total Prod (Boe/d) 63 1,115 269 527 2,679


CONTINENTAL RESOURCES, INC. Sum of Last Reported Total Prod (Boe/d) 411 539 520 147 1 0 1,618


KAISER-FRANCIS OIL COMPANY Sum of Last Reported Total Prod (Boe/d) 428 1,156 1,584

Average of Peak Well Rate (Boe/d) 900 1,349 963

CHEVRON, U.S.A., INC. Sum of Last Reported Total Prod (Boe/d) 824 0 0 824

Average of Peak Well Rate (Boe/d) 1,123 1 42 197

XTO ENERGY, INC. Sum of Last Reported Total Prod (Boe/d) 545 0 0 0 245 790


CORNERSTONE E & P COMPANY LP Sum of Last Reported Total Prod (Boe/d) 666 666


BNK PETROLEUM(US) INC Sum of Last Reported Total Prod (Boe/d) 149 541

Average of Peak Well Rate (Boe/d) 190 1,145

RANGE RESOURCES CORPORATION Sum of Last Reported Total Prod (Boe/d) 515


WESTERN OIL AND GAS DEVELOPMENT CORP Sum of Last Reported Total Prod (Boe/d) 21 450 471


SAMSON INVESTMENT COMPANY Sum of Last Reported Total Prod (Boe/d) 60 85 16 294 0 0 461


W C T OPERATING LLC Sum of Last Reported Total Prod (Boe/d) 337





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Amaranth Bakken (US) Barnett Woodford

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Woodford Play Profile Rigs Running Wells Drilled

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Q1/08

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Q3/09

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Q3/15E

Q2/16E

Q1/17E

Q4/17E

Q3/18E

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Liquids (Right)

-

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Low Base High


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

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

HighBaseLow


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00 03 06 09 12 15 18 21 24 27 30 33 36 39 42


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333

417

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583

Boe/

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50

100

150

200

250

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0 376 752 1,128 1,504 1,880 2,256 2,632 3,008


Freq

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Emerging Plays Exhibit 47. Eaglebine

Top Permit Holders1 Petromax2 Apache3 CML Exploration4 Woodbine Acquisitions5 Vess Oil Corp6 Encana Corp

Eagleford

Tuscaloosa

Haynesville

Barnett

TEXAS

LOUISIANA

Burleson

Brazos

Leon

Robertson

Madison

Grimes

Exhibit 48. Niobrara

Top 5 Permit Holders1 EOG Resources2 Noble Energy3 Chesapeake Energy4 Kerr-Mcgee Oil & Gas5 Bill Barrett Corp

Haynesville

TEXAS

MISSISSIPPI

LOUISIANA

West Feliciana

East Feliciana Saint Helena

Tanglpahoa

AmiteWilkinson

Mississippi Lime

COLORADO

NEBRASKA

KANSAS

WYOMING

SOUTH DAKOTA

Campbell

Johnson

Niobrara

Converse

Goshen

Platte

Laramie

Weld

Morgan

Larimer

Boulder

Source for Exhibits 47 and 48: GoogleEarth, HPDI and CIBC World Markets Inc.

Amaranth Bakken (US) Barnett Eagleford Emerging Plays Ho

rn

R

ive

r Montney VET

Exhibit 49. San Juan Basin

Top 5 Permit Holders1 McElvain Oil & Gas2 XTO Energy 3 Rosetta Resources4 Encana Corp5 Elm Ridge Exploration

TEXAS

NEW MEXICO

Mississippi Lime

COLORADO

San Juan

Rio Arriba

Sandoval

Exhibit 50. Tuscaloosa

Top 5 Permit Holders1 Devon Energy2 Goodrich Petroleum3 Encore Operating4 Encana5 Enduro Operating

Haynesville

TEXAS

MISSISSIPPI

LOUISIANA

West Feliciana


Tanglpahoa

AmiteWilkinson

Source for Exhibits 49 and 50: GoogleEarth, HPDI and CIBC World Markets Inc.


rn

R

ive

r Montney VET

Exhibit 51. Utica

Top 5 Permit Holders1 Chesapeake Energy2 HG Energy3 Swepi LP4 Anadarko Energy5 Norse Energy

Haynesville

TEXAS

MISSISSIPPI

LOUISIANA

West Feliciana


Tanglpahoa

AmiteWilkinson

Utica

Madison

ChenangoBroome

New York

Butler

Pennsylvania

Ohio

Lawrence

Beaver

Trumbull

Portage

Mahoning

Holmes

Columbiana

Jefferson

Morgan Monroe

Source: GoogleEarth, HPDI and CIBC World Markets Inc.


rn

R

ive

r Montney VET


191



192

Canadian Resource Plays


193


194

Amaranth - Area Map (Circa August 2012) Amaranth - Resource Potential


Amaranth - Area Production Growth

Note: Map updated as of May 2012. Source: GeoScout; Company reports; Geological Atlas of Western Canada; The Edge; Canadian Discovery Digest; CIBC World Markets Inc. Source: GeoScout; CIBC World Markets Inc.

Amaranth - Horizontal Well Operator Summary (Circa August 2012)

Note: Quoted production is a gross estimate from public databases which may vary from actual production rates. Source: GeoScout; CIBC World Markets Inc.

Amaranth - Schematic Cross Section Amaranth - Land Position by Operator

Source: The Edge; Canadian Discovery Digest; CIBC World Markets Inc.Notes 1) 1 section = 640 acres; 2) Denotes private company. Land positions are approximations based on company disclosure and public data, and do not adjust for prospectivity. Source: Company reports; GeoScout; CIBC World Markets Inc.

Amaranth Land Holders210

124 117

55 54

2211 9 8 2 1

0

50

100

150

200

250

Surg

e

Lega

cy

Penn

Wes

t

Tund

ra (2

)

EOG

CN

RL

Antle

r Riv

er(2

)

Whi

te N

orth

(2) AR

C

Petro

Bakk

en

Lodg

epol

e (2

)

Net

Sec

tions

(1)

Total# Operated # Licensed Op./Lic. Oil & Liquids Nat. Gas Nat. Gas Total Oil & Liquids Nat. Gas Total

Company Ticker Hz Wells Wells Wells (bbl/d) (mcf/d) (%) (boe/d) (bbl/d) (mcf/d) (boe/d)EOG Rsrcs Cda Inc EOG-NYSE 205 - 205 3,558 1 0% 3,558 17 0 17Penn West Petrl PWT 110 39 149 3,337 0 0% 3,337 30 0 30ARC Rsrcs Ltd ARX 23 1 24 710 0 0% 710 31 0 31Legacy O&G Inc LEG 45 6 51 591 0 0% 591 13 0 13Red Beds Rsrcs Ltd PRIVATE 14 5 19 493 0 0% 493 35 0 35Surge Enrg Inc SGY 5 - 5 240 0 0% 240 48 0 48Cdn Nat Rsrcs Lmtd CNQ 10 4 14 206 0 0% 206 21 0 21Petrobakken Enrg Ltd PBN 9 4 13 147 0 0% 147 16 0 16Legacy Oil & Gas Nd, Inc. LEG 3 - 3 108 4 1% 109 36 1 36Crescent Point Enrg Corp CPG 3 - 3 43 19 7% 46 14 6 15Westman Expl Ltd PRIVATE 3 - 3 44 0 0% 44 15 0 15Atikwa Rsrcs Inc ATK 2 - 2 39 0 0% 39 20 0 20618555 Sask Ltd PRIVATE 3 1 4 39 0 0% 39 13 0 13Renegade Petrls Ltd RPL 1 - 1 20 0 0% 20 20 0 20Harvest Oprtns Corp PRIVATE 1 - 1 2 0 0% 2 2 0 2

Average Production Per Hz WellGross Operated Hz Well Production

Amaranth

-

5

10

15

20

25

30

35

40

45

50

55

60

Q2/

08Q

3/08

Q4/

08Q

1/09

Q2/

09Q

3/09

Q4/

09Q

1/10

Q2/

10Q

3/10

Q4/

10Q

1/11

Q2/

11Q

3/11

Q4/

11Q

1/12

Q2/

12Q

3/12

Q4/

12Q

1/13

Q2/

13Q

3/13

Q4/

13Q

1/14

Q2/

14Q

3/14

Q4/

14Q

1/15

Q2/

15Q

3/15

Q4/

15

Tota

l Pro

duct

ion

(MB

oe/d

)

0

5

10

15

20

25

30

35

40

45

50

55

60


oe/d)

Pre 2008 2008 2009 2010 2011

2012 2013 2014 2015 Liquids

Actual Forecast

2%2%5%7%1%4%<1%

28%16%

<1%<1%2.5

15.0

20.0

10.0 10.0

7.5 6.0

5.0 4.3

2.5 4.0

15.015.0

25.0

20.0

0

5

10

15

20

25

Bakk

en(A

lber

ta)

Seal

Duv

erna

y

Car

dium

Tigh

tC

arbo

nate

s

Viki

ng

Bakk

en

(SE

Sask

.)Lo

wer

Shau

navo

n

Peki

sko

Amar

anth

Mon

tney

Oil

Bar

rels

of O

il (B

ln)


Recovered-to-Date

Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Am

ara

nth

Montney

VET


195

Amaranth - Generic Type Curves Amaranth - Type Curve Well Economics (Mid Cycle)

Amaranth - Variance of Results - All Time Amaranth - Variance of Results - 2011 to Present

Source: GeoScout; CIBC World Markets Inc. Source: GeoScout; CIBC World Markets Inc.

Amaranth - Distribution By Peak I.P. Rates Amaranth - Top Wells

Amaranth - YOY Actual Results – ALL PRODUCERS Amaranth - YOY Actual Results – GOODLANDS


Amaranth - YOY Actual Results – WASKADA Amaranth - YOY Actual Results – Western Area


Note: We will be watching actual results to either validate or disprove these type curves, and plan to make adjustments on an on-going basis as dictated by empirical data. Source: GeoScout; Company reports; CIBC World Markets Inc.

Notes: 1) Midcycle Economics include dry hole costs, and a 10% capital cost “gross up” for infrastructure spending. Land costs are considered “sunk costs”. Economics assume crown royalties. 2) P/I ratios calculated as per well NPV (@ 9%) divided by initial capital invested, and can be thought of as the discounted % return for per dollar invested. Source: Company reports and CIBC World Markets Inc.


Notes: Our “Peak I.P. rate” represents the maximum monthly producing-day rate in a well’s first 8 months of production (note that we exclude months with less than 10 days of production). Current rate is a "calendar day" rate (i.e. last month's cumulative volumes divided by 30.5 days). Source: GeoScout; CIBC World Markets Inc.

Distribution by Peak I.P. Rate HORIZONTAL Amaranth Wells

0

50

100

150

200

250

300

350

400

450

25

50

75

100

125

150

175

200

225

250

275

300

325

350

375

400

425

Well Count

Pe

ak

I.P

. R

ate

(B

oe

/d)


2009 (68 Wells)

2010 (208 Wells)

2011 (141 Wells)

Median

Mean (Average)

Top/Bottom Quartile

Amaranth HZ Wells - Type Curves

0

50

100

150

200

250

0 3 6 9 12 15 18 21 24 27 30Months on Production

Pro

d.

Ra

te (

bo

e/d

)

High Case: 225 Boe/d IP, 175 MBoe recovery

Mid Case: 125 Boe/d IP, 100 MBoe recovery

Low Case: 50 Boe/d IP, 50 MBoe recovery

ALL Amaranth Hz Wells Average Per Well Production

0

50

100

150

200

250

0 3 6 9 12 15 18 21 24Months on Production (normalized)

Pro

du

cti

on

Ra

te (

bo

e/d

) 2008 (13 Wells) 2009 (68 Wells)

2010 (208 Wells) 2011 (141 Wells)

WESTERN AREA - Amaranth Hz Wells Average Per Well Production

0

50

100

150

200

250

0 3 6 9 12 15 18 21 24

Months on Production (normalized)

Pro

du

cti

on

Ra

te (

bo

e/d

) 2007 (1 Wells) 2008 (10 Wells)

2009 (2 Wells) 2010 (35 Wells)

2011 (16 Wells)

… but recent results at Pierson (western area) signal an extension of the play.

WASKADA - Amaranth Hz Wells Average Per Well Production

0

50

100

150

200

250


Pro

du

cti

on

Ra

te (

bo

e/d

)

2007 (3 Wells) 2008 (3 Wells)

2009 (32 Wells) 2010 (120 Wells)

2011 (52 Wells)

Waskada continues to be a focal point of development for EOG & Penn West.

GOODLANDS - Amaranth Hz Wells Average Per Well Production

0

50

100

150

200

250


Pro

du

cti

on

Ra

te (

bo

e/d

) 2007 (3 Wells) 2008 (2 Wells)

2009 (34 Wells) 2010 (33 Wells)

2011 (25 Wells)

Variance to Mean - All TimeHORIZONTAL Amaranth Wells

430 430 401 377 299 229 147 113 84 68 37 19 14-100

-50

0

50

100

150

200

250

3 6 9 12 15 18 21 24 27 30 33 36

Months on Production (Normalized)

Pro

d. R

ate

(Bo

e/d

)

Mean (Average)

Top Quartile Average

Bottom Quartile Average

Variance to Mean - 2011 to PresentHORIZONTAL Amaranth Wells

141 141 113 91 67-100

-50

0

50

100

150

200

250

3 6 9 12 15 18 21 24 27 30 33 36Months on Production (Normalized)

Pro

d.

Ra

te (

Bo

e/d

)

Mean (Average)



# o f Wells

# o f Wells

Distribution Curve

0

30

60

90

120

150

0

15

0

30

0

(Boe/d)

Cou

nt

Date On Mths %Rank Operator Strike Area UWI (Well Location) Stream On Peak I.P. Current Gas Msrd. Vt.

1 EOG Waskada 16-05-001-24W1 2009/01 36 358 4 0% 1,648 8932 Penn West Waskada 14-36-001-26W1 2010/11 14 354 42 0% 1,684 9093 EOG Waskada 01-08-001-24W1 2008/07 42 343 2 0% 1,650 8954 EOG Waskada 05-15-001-25W1 2011/03 10 341 62 0% 1,759 9035 EOG Waskada 01-08-001-24W1 2009/09 28 323 5 0% 1,670 8966 Penn West Waskada 14-36-001-26W1 2010/10 15 320 26 0% 1,677 9097 EOG Waskada 02-08-001-24W1 2009/08 29 317 8 0% 1,681 9038 EOG Waskada 05-15-001-25W1 2011/04 9 306 108 0% 1,759 9059 EOG Waskada 07-08-001-24W1 2009/08 29 299 7 0% 1,686 903

10 EOG Waskada 14-05-001-24W1 2009/01 36 272 16 0% 1,646 89411 EOG Waskada 11-08-001-24W1 2010/08 17 271 31 0% 1,636 88512 EOG Waskada 05-27-001-25W1 2010/12 13 271 26 0% 1,702 89813 EOG Waskada 08-03-002-25W1 2010/10 15 270 36 0% 1,618 88214 Penn West Waskada 09-36-001-26W1 2010/09 16 268 84 0% 2,127 89415 EOG Waskada 07-15-001-25W1 2010/06 19 267 21 0% 1,678 89616 EOG Waskada 06-08-001-24W1 2011/02 11 265 31 0% 1,655 88917 EOG Waskada 08-03-002-25W1 2010/09 16 264 14 0% 1,638 87718 EOG Waskada 05-09-001-25W1 2011/02 11 263 43 0% 1,684 91019 Penn West Waskada 09-35-001-26W1 2011/02 11 260 11 0% 1,755 90420 EOG Waskada 05-34-001-25W1 2010/02 23 259 19 0% 1,670 891

All Producers (402) - Average 144 28 0% 1,748 912

Prod. (Boe/d) Depth (Meters)

Low Mid High

Midcycle1 Well Economics: Curve Curve Curve NPV (B-Tax) (C$,mlns) $0.6 $3.0 $5.6 NPV (A-Tax) (C$,mlns) $0.3 $2.0 $4.0 IRR (A-tax) (%) 15% 74% 271% P/I Ratio2 (A-tax) 0.2x 1.4x 2.6x Payback Period (yrs) 5.2 1.5 0.6

Low Mid High NPV9 Breakeven ($US/bbl) $70.00 $41.00 $30.50

2012 2013 2014Well Cost (C$,mln): $1.5MM 1st yr Decline Rate: 65% WTI (US$/bbl) $90.00 $87.50 $85.00Op Costs (incl.trans): $10.00/Boe 2nd yr Decline Rate: 25% FX ($US/$Cdn) $0.99 $0.98 $0.98Discount Rate: 9% Success Rate: 90% Nat Gas (C$/mcf) $2.39 $3.43 $4.08

Amaranth Type Curve Economics NPV/well Sensitivity (+/- 20%)

CIBC Base Commodity Price AssumptionAssumptions

$1.0 $0.5 $0.0 $0.5 $1.0

Royalties

Operating Cost

Capital Cost

Productivity

Commodity Prices

(C$,mlns)

Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Am

ara

nth

Montney

VET

Amaranth Bakken (US) Barnett Eagleford Fayetteville Amaranth Montney V

ET


197



198

Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Haynesville

Bakken

(A

B)

VET


199

Alberta Bakken - Drilling / Licensing Activity - Data Available As Of MAY 25, 2012; Production Data Current To April 30, 2012 At Update


Alberta Bakken - Key Play Parameter vs. Other Tight Oil Plays


Bakken Cardium L. Shaunavon Carbonates Viking(SE Sask) (Central AB) (Central AB) (Central AB) (SE Sask)

Gross OOIP (Bln Barrels) 5.0 Bln 10.0 Bln 4.3 Bln 7.5 Bln 6.0 BlnOOIP/section (MMBoe) 5 MMBoe/sec 5-10 MMBoe/sec 5-10 MMBoe/sec 5-20 Mmboe/sec 5-10 MMBoe/secRecovered to date (%) 1.0% 16.0% <1.0% 28.0% <1.0%Est. Ult. Recovery Rate (%): 30-40% 25-35% 10% 50-60% 16%Depth (metres) 1,600 m 1,200 - 2,000 m 1,350 m 2,650 m 700 mCapital Costs/well DCT ($MM) $1.5-2.0 MM $2.0-3.0 MM $1.5-2.0 MM $2.0-4.0 MM $0.8-1.2 MM

Total "AB. BAKKEN" Package

EXSHAW (Bakken) BIG VALLEY BANFF

Rock TypeShale, Limestone, & Dolomite Package Shale Limestone Limestone Silty Sandstone

Broad Marine Sandstone Oolitic Limestone

Limestone (Reef Platform/Edges) Silty Sandstone

Porosity (%) 2-12% 4 - 8% 2-12% 4 - 8% 10% 12% 15-18% 5-6% 23%Permeability (millidarcies) 0.1 - +20 mD 0.1 - 2 mD 0.1 - +20 mD 0.1 - 10 mD 0.1 - 2.0 mD 0.5 - 10 mD 0.5-1.0 mD 0.5 - 3.0 mD 1 - +50 mDNet Pay (metres) 10 - +35 m 4.5 - 11 m 0 - 15 m 5 - 10 m 5 m 5 - 12 m 5 - 10 m 5 m 3 - 10 mOil Quality (API) 32 - 38 API 36 API 32.5 API 32 - 38 API 42 API 40 API 23 API 43 API 38 API

2,000 - 2,800 m$3.0-4.0 MM

(Southern Alberta)Alberta Bakken

15.0-25.0 Bln12-15 MMBoe/sec

<1.0%?

Reported# Stike Reported Hz/Vt Date Date On Date Rig Date On Mths Oil Gas Water %

Wells Operator Symbol Area Well Location Formation Msrd. Vt. Well Licensed Spudded Released Stream On (Bbl) (Mcf) (Bbl) Water1 Antelope PRIVATE Stdoff 05-30-007-25W4 Stettler 2,825 2,825 V 9/7/2011 9/17/2011 11/15/20112 Argosy GSY Pearce 04-16-009-24W4 Wabamun V 1/16/20123 Argosy GSY Pearce 01-21-009-24W4 Wabamun 3,765 2,386 H 12/6/2011 12/13/2011 1/18/2012 03/14/2012 3 1,934 1,1754 Argosy GSY Granum 03-31-010-25W4 Wabamun 2,536 2,528 V 9/24/2010 9/29/2010 10/19/2010 02/26/2011 16 5,497 10,034 732 12%5 Argosy GSY Granum 13-35-010-26W4 Wabamun 3,956 2,601 H 12/21/2010 3/15/2011 4/24/2011 08/12/2011 10 10,894 15,7496 Argosy GSY Granum 01-24-011-26W4 Wabamun 3,456 2,289 H 1/14/2011 1/21/2011 3/12/2011 06/07/2011 12 3,664 4,135 52 1%7 Copper PRIVATE Reagan 01-06-001-19W4 Stettler 1,495 V 1/4/2011 1/25/2011 2/12/20118 Copper PRIVATE Reagan 13-01-001-20W4 Stettler 1,540 1,540 V 12/9/2010 12/28/2010 1/17/20119 Copper PRIVATE Reagan 01-23-001-20W4 Bakken 1,548 1,548 V 11/26/2010 12/4/2010 12/23/2010

10 Copper PRIVATE Reagan 14-23-001-20W4 Bakken V 11/26/201011 Crescent Point CPG Sunburst 03-08-001-18W4 Wabamun 2,896 1,420 H 9/23/2010 10/3/2010 10/29/2010 01/01/2011 17 905 224 1,286 59%12 Crescent Point CPG Del Bonita 14-07-001-21W4 Wabamun 3,167 1,949 H 7/9/2010 7/24/2010 8/25/2010 11/01/2010 19 1,617 1,484 1,634 50%13 Crescent Point CPG Reagan 15-01-002-20W4 Wabamun 3,020 1,590 H 11/5/2010 11/11/2010 12/2/2010 01/01/2011 17 912 916 3,797 81%14 Crescent Point CPG Branch 13-11-002-20W4 Wabamun 2,969 1,548 H 2/2/2012 2/10/2012 3/8/201215 Crescent Point CPG Reagan 01-09-002-21W4 Wabamun 3,436 1,813 H 9/20/2011 10/17/2011 11/14/2011 12/01/2011 6 5,314 7,613 6,293 54%16 Crescent Point CPG Del Bonita 14-23-002-21W4 Bakken 3,209 1,674 H 8/30/2011 9/22/2011 10/16/2011 11/01/2011 7 8,443 10,322 4,173 33%17 Crescent Point CPG Reagan 13-24-002-21W4 Wabamun 3,114 H 3/1/2012 3/13/201218 Crescent Point CPG Warner 16-10-004-19W4 Wabamun 1,655 1,654 V 1/11/2012 2/1/2012 2/9/201219 Crescent Point CPG Blood 01-05-007-21W4 Wabamun H 3/7/201120 Crescent Point CPG Barons 01-15-012-24W4 Wabamun 2,161 2,161 V 10/29/2010 12/7/2010 12/22/201021 Crescent Point CPG Barons 16-35-012-24W4 Wabamun 3,413 2,086 H 11/18/2010 12/5/2010 1/6/2011 07/01/2011 11 2,235 465 3,805 63%22 Crocotta CTA Stirling 03-10-007-19W4 Big_Val 2,623 1,452 H 11/2/2011 11/6/2011 11/30/201123 Crocotta CTA Stirling 14-10-007-19W4 Stettler 1,481 1,481 V 9/1/2011 9/30/2011 10/18/201124 Deethree DTX Reagan 07-03-002-20W4 Stettler 1,902 1,545 H 12/3/2010 12/6/2010 2/11/201125 Deethree DTX Reagan 12-03-002-20W4 Stettler 2,961 1,553 H 12/3/2010 12/6/2010 2/11/2011 08/16/2011 10 12,893 37,858 947 7%26 Deethree DTX Reagan 16-03-002-20W4 Bakken 2,629 1,533 H 6/16/2011 7/8/2011 8/4/2011 09/13/2011 9 4,709 14,513 1,841 28%27 Deethree DTX Ferguson 03-19-003-16W4 Bakken H 4/18/201228 Deethree DTX Ferguson 08-19-003-16W4 Bakken H 4/18/2012 4/25/201229 Deethree DTX Ferguson 16-19-003-16W4 Bakken 3,038 1,281 H 3/22/2012 3/30/2012 4/19/201230 Deethree DTX Ferguson 05-22-003-17W4 Bakken 2,860 1,280 H 2/24/2012 3/1/2012 3/22/2012 03/25/2012 3 4,878 4 848 15%31 Deethree DTX Ferguson 13-22-003-17W4 Bakken 3,749 1,286 H 3/15/2012 3/24/2012 4/14/2012 04/20/2012 232 Deethree DTX Ferguson 07-25-003-17W4 Big_Val 2,380 1,272 H 10/12/2011 1/3/2012 2/4/2012 02/08/2012 4 14,484 4,252 1,914 12%33 Deethree DTX Ferguson 11-31-003-17W4 Stettler 2,134 1,364 H 3/11/2011 5/7/2011 6/5/201134 Deethree DTX Ferguson 04-32-003-17W4 Livngstn 1,065 1,065 V 4/29/2009 11/12/2009 11/15/200935 Deethree DTX Ferguson 11-12-003-18W4 Big_Val H 5/15/201236 Deethree DTX Coaldale 01-36-008-20W4 Stettler V 10/25/201137 Legacy LEG Springco 02-36-003-23W4 Stettler 3,503 2,140 V 3/11/2011 3/22/2011 5/17/2011 10/22/2011 8 1,751 2,165 1,994 53%38 Murphy MUR Reagan 16-04-001-20W4 Wabamun 2,720 1,568 H 1/26/2011 3/7/2011 4/8/2011 05/01/2011 13 6,847 64,095 586 8%39 Murphy MUR Reagan 08-16-001-20W4 Wabamun 2,601 1,573 H 4/6/2011 5/6/2011 5/24/201140 Murphy MUR Bonita 08-21-001-22W4 Wabamun H 3/25/201141 Murphy MUR Reagan 14-02-002-21W4 Wabamun 2,776 1,756 H 1/21/2011 1/29/2011 3/5/2011 04/01/2011 14 2,504 8,646 378 13%42 Murphy MUR Reagan 14-11-002-21W4 Wabamun H 2/17/201143 Murphy MUR Jensen 06-10-003-21W4 Wabamun 3,471 1,796 H 6/8/2011 6/26/2011 7/20/2011 09/28/2011 9 3,223 13,488 762 19%44 Murphy MUR Jensen 14-24-003-21W4 Wabamun V 6/16/201145 Murphy MUR Ninsto 09-29-004-25W4 Wabamun 4,307 2,855 H 6/16/2011 8/30/2011 10/21/2011 12/01/2011 6 20,333 31,238 19,269 49%46 Murphy MUR Blood 02-18-005-23W4 Wabamun H 1/27/201247 Murphy MUR Blood 07-10-005-24W4 Wabamun V 11/25/201148 Murphy MUR Blood 14-21-005-24W4 Wabamun V 1/27/201249 Murphy MUR Blood 01-35-005-24W4 Wabamun 3,432 2,371 H 6/29/2011 7/28/2011 8/27/201150 Murphy MUR Ninsto 09-07-005-25W4 Wabamun 4,351 2,875 H 11/23/2011 2/18/2012 4/2/201251 Murphy MUR Blood 06-32-006-23W4 Wabamun H 3/1/201252 Murphy MUR Blood 08-09-006-24W4 Wabamun V 12/1/201153 Murphy MUR Blood 13-36-006-24W4 Wabamun H 2/29/201254 Nexen NXY Keho 01-06-011-24W4 Wabamun 2,398 2,283 V 2/26/2011 3/18/2011 5/1/201155 Nexen NXY Keho 12-06-011-24W4 Wabamun 3,631 2,292 H 2/26/2011 3/18/2011 5/1/2011 07/24/2011 11 5,703 2,95056 Nexen NXY Keho 11-28-011-24W4 Wabamun 3,523 2,256 H 12/20/2010 1/17/2011 3/11/2011 05/23/2011 13 2,922 1,459 145 5%57 Nexen NXY Clares 01-12-012-25W4 Wabamun 3,721 2,382 H 3/31/2011 5/21/2011 7/16/2011 01/11/2012 5 1,466 1,47358 Shell RDS.A Del Bonita 10-20-001-22W4 Big_Val 3,801 2,196 H 10/21/2010 11/22/2010 1/30/2011 03/01/2011 15 10,648 23,60359 Shell RDS.A Del Bonita 14-25-001-22W4 Wabamun V 6/29/201160 Shell RDS.A Del Bonita 06-33-001-22W4 Exshaw V 12/19/201161 Shell RDS.A Del Bonita 05-23-001-23W4 Exshaw V 12/22/201162 Shell RDS.A Del Bonita 13-23-001-23W4 Wabamun H 2/24/201263 Shell RDS.A Del Bonita 02-28-001-23W4 Big_Val 3,563 H 11/17/2010 11/26/201164 Shell RDS.A Del Bonita 13-14-001-24W4 Big_Val 4,341 2,628 H 11/23/2010 5/11/2011 7/15/2011 01/01/2012 5 539 31665 Shell RDS.A Del Bonita 14-32-001-24W4 Wabamun V 8/23/201166 Shell RDS.A Del Bonita 14-04-002-22W4 Wabamun V 6/10/201167 Shell RDS.A Del Bonita 04-13-002-22W4 Big_Val 3,806 2,063 H 11/2/2010 2/8/2011 3/27/2011 06/01/2011 12 10,629 10,51768 Shell RDS.A Woolfd 16-02-002-24W4 Wabamun V 6/10/201169 Shell RDS.A Aetna 16-24-002-25W4 Exshaw 2,771 2,771 V 8/5/2010 8/17/2010 9/8/201070 Timberrock PRIVATE Clares 06-36-013-25W4 Banff 2,223 2,223 V 6/23/2011 6/26/2011 7/20/2011 12/22/2011 6 940 66771 Torc PRIVATE Pearce 03-08-009-24W4 Stettler 3,800 H 3/26/2012 4/11/201272 Torc PRIVATE Pearce 02-17-009-24W4 Big_Val 3,463 2,246 H 3/17/2011 3/29/2011 5/8/2011 11/01/2011 7 28,254 13,16573 Torc PRIVATE Pearce 03-13-009-25W4 Big_Val 3,839 2,384 V 12/29/2011 1/10/2012 2/15/2012 05/17/2012 174 Torc PRIVATE Amelia 03-26-009-27W4 Big_Val 4,514 2,982 H 10/11/2011 10/19/2011 1/1/201275 Torc PRIVATE Keho 14-10-010-22W4 Stettler H 5/8/201276 Torc PRIVATE Penny 16-02-010-24W4 Banff_L 3,379 2,011 V 11/14/2011 11/21/2011 12/23/201177 Torc PRIVATE Amelia 04-22-010-26W4 Big_Val 3,731 2,665 H 4/27/2011 5/15/2011 7/5/2011 08/01/2011 10 6,066 2,31878 Torc PRIVATE Amelia 01-29-010-27W4 Big_Val 4,712 3,045 V 11/30/2011 2/17/2012 4/8/2012

Depth (M)Cumulative Production

Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Haynesville

Bakken

(AB

) V

ET


200

Bakken - Area Map (Circa August, 2012) Bakken - Resource Potential


Bakken - Area Production Growth

Note: Map updated at May 2012. Source: Gvmnt. of Sask.; N. Dakota Geological Survey; Canadian Discovery Digest; GeoScout; Geological Atlas of Western Canada;CIBC World Markets Inc. Source: GeoScout; CIBC World Markets Inc.

Bakken - Horizontal Well Operator Summary (Circa August, 2012)


Bakken - Schematic Cross Section Bakken - Land Position by Operator

Source: North Dakota Geological Survey; Canadian Discovery Digest; CIBC World Markets Inc.Notes 1) 1 section = 640 acres; 2) Crescent Point's acreage includes only 90 net sections of Ryland's acreage 3) Denotes private company. Land positions are approximations based on company disclosure and public data, and do not adjust for prospectivity. Source: Company reports; GeoScout; CIBC World Markets Inc.

Bakken Land Holders1,000

430328

219 200 172100 97 90 86 82 77 68 53 45 35 31

0

200

400

600

800

1,000

1,200

Cre

scen

t Poi

nt (2

)

Petro

Bakk

en

Hus

ky

Ener

plus

Cen

ovus

EOG

Lega

cy

Pain

ted

Pony

Tund

ra (3

)

NAL

Mol

opo

KNO

C (3

)

Spar

tan

Mag

nus

(3)

CN

RL

ARC

TriO

il

Net

Sec

tions

(1)

Total# Operated # Licensed Op./Lic. Oil & Liquids Nat. Gas Total Nat. Gas Oil & Liquids Nat. Gas Total

Company Ticker Hz Wells Wells Wells (bbl/d) (mcf/d) (boe/d) (%) (bbl/d) (mcf/d) (boe/d)Crescent Point Enrg Corp CPG 1,098 303 1,401 41,397 33,210 46,932 12% 38 30 43Petrobakken Enrg Ltd PBN 747 277 1024 16,998 13,512 19,250 12% 23 18 26Legacy O&G Inc LEG 149 33 182 4,592 2,470 5,003 8% 31 17 34Husky Oil Oprtns Ltd HSE 12 10 22 1,407 1,443 1,647 15% 117 120 137Painted Pony Petrl Ltd PPY.A 72 17 89 1,151 1,587 1,416 19% 16 22 20Taqa North Ltd TAQA 30 8 38 1,025 947 1,183 13% 34 32 39Cenovus Enrg Inc CVE 16 16 32 931 838 1,071 13% 58 52 67Questerre Enrg Corp QEC 44 19 63 846 0 846 0% 19 0 19Tundra O&G Prtnshp PRIVATE 25 19 44 664 11 666 0% 27 0 27Penn West Petrl Ltd PWT 16 0 16 496 46 504 2% 31 3 31Rife Rsrcs Ltd PRIVATE 10 7 17 343 271 388 12% 34 27 39Highrock Enrg Ltd PRIVATE 9 2 11 335 81 348 4% 37 9 39Fairborne Enrg Ltd FEL 14 1 15 291 0 291 0% 21 0 21Midale Petrls Ltd PRIVATE 10 1 11 236 185 267 12% 24 18 27Openfield Enrg Ltd PRIVATE 5 0 5 171 257 214 20% 34 51 43Renegade Petrls Ltd RPL 11 8 19 181 187 212 15% 16 17 19Cdn Nat Rsrcs Lmtd CNQ 14 1 15 193 10 195 1% 14 1 14Aldon Oils Ltd PRIVATE 14 0 14 194 1 194 0% 14 0 14Arruga Rsrcs Ltd PRIVATE 6 0 6 184 12 186 1% 31 2 31Torquay Oil Corp TOC 7 2 9 93 180 123 24% 13 26 18


Bakken

-

20

40

60

80

100

120

140

160

180

200

Q2/

08Q

3/08

Q4/

08Q

1/09

Q2/

09Q

3/09

Q4/

09Q

1/10

Q2/

10Q

3/10

Q4/

10Q

1/11

Q2/

11Q

3/11

Q4/

11Q

1/12

Q2/

12Q

3/12

Q4/

12Q

1/13

Q2/

13Q

3/13

Q4/

13Q

1/14

Q2/

14Q

3/14

Q4/

14Q

1/15

Q2/

15Q

3/15

Q4/

15

Tota

l Pro

duct

ion

(MB

oe/d

)

0

20

40

60

80

100

120

140

160

180

200


oe/d)

Pre 2008 2008 2009 2010 2011

2012 2013 2014 2015 Liquids

Actual Forecast

2%2%5%7%1%4%<1%

28%16%

<1%<1%2.5

15.0

20.0

10.0 10.0

7.5 6.0

5.0 4.3

2.5 4.0

15.015.0

25.0

20.0

0

5

10

15

20

25

Bakk

en(A

lber

ta)

Seal

Duv

erna

y

Car

dium

Tigh

tC

arbo

nate

s

Viki

ng

Bakk

en

(SE

Sask

.)Lo

wer

Shau

navo

n

Peki

sko

Amar

anth

Mon

tney

Oil

Bar

rels

of O

il (B

ln)


Recovered-to-Date

Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Haynesville

Marcellus

Bakken

(S

K)


201

Bakken - Generic Type Curves Bakken - Type Curve Well Economics (Mid Cycle)

Bakken - Variance of Results - All Time Bakken - Variance of Results - Since 2011


Bakken - Distribution By Peak I.P. Rates Bakken - Top Wells





Bakken HZ Wells - Type Curves

0

50

100

150

200

250

300

0 3 6 9 12 15 18 21 24 27 30


Pro

du

cti

on

Rat

e (

bo

e/d

)




Variance to Mean - All TIMEHORIZONTAL Bakken Wells

2355 2301 2146 2064 1919 1754 1608 1485 1355 1211 1074 984 876

-100

-50

0

50

100

150

200

250

300

3 6 9 12 15 18 21 24 27 30 33 36


Pro

du

ctio

n R

ate

(Bo

e/d

) Mean (Average)



Distribution by Peak I.P. Rate HORIZONTAL Bakken Wells

0

100

200

300

400

500

600

700

100

200

300

400

500

600

700

800

900

100

0

110

0

120

0

130

0

140

0

150

0

160

0

170

0

180

0

190

0

200

0

210

0

220

0Well Count

Pea

k I.

P.

Rat

e (B

oe/

d)


2009 (424 Wells)

2010 (493 Wells)

2011 (361 Wells)

Median

Mean (Average)

Top/Bottom Quartile

Variance to Mean - 2011 to PresentHORIZONTAL Bakken Wells

361 311 189 145-100

-50

0

50

100

150

200

250

300

3 6 9 12 15 18 21 24 27 30 33 36


Pro

du

ctio

n R

ate

(Bo

e/d

)Mean (Average)



# of

Wells

# of

Wells

Distribution Curve

0

100

200

300

400

500

600

700

0

10

0

20

0

30

0

40

0

50

0

60

0

(Boe/d)

Cou

nt


1 Cenovus Weyburn/Estevan 13-35-001-07W2/00 2011/02 11 1,211 293 0% 3,948 2,0442 Legacy Weyburn/Estevan 16-15-001-06W2/00 2011/01 12 651 122 0% 3,469 N/A3 Petrobakken Weyburn/Estevan 13-07-008-06W2/00 2008/11 38 618 39 2% 2,967 N/A4 Petrobakken Weyburn/Estevan 14-13-008-08W2/00 2009/06 31 535 61 11% 2,261 N/A5 Petrobakken Weyburn/Estevan 09-26-008-10W2/00 2009/01 36 526 49 0% 2,241 N/A6 Crescent Point Weyburn/Estevan 01-14-009-07W2/00 2010/06 19 520 104 8% 2,951 N/A7 Petrobakken Weyburn/Estevan 06-16-008-06W2/00 2009/01 36 509 25 11% 2,218 N/A8 Crescent Point Weyburn/Estevan 12-18-008-09W2/00 2007/10 51 494 20 0% 2,981 1,5979 Petrobakken Weyburn/Estevan 01-35-008-10W2/00 2009/03 34 487 26 4% 3,087 N/A10 Crescent Point Weyburn/Estevan 12-09-008-10W2/00 2009/03 34 463 19 7% 3,110 N/A11 Petrobakken Weyburn/Estevan 04-24-008-07W2/00 2008/02 47 462 89 14% 2,986 1,51612 Legacy Weyburn/Estevan 05-36-001-07W2/00 2010/07 18 454 49 11% 3,575 N/A13 Crescent Point Weyburn/Estevan 13-28-008-09W2/00 2009/07 30 453 19 8% 3,085 N/A14 Crescent Point Weyburn/Estevan 04-10-008-08W2/00 2007/11 50 452 23 0% 3,064 1,58515 Crescent Point Weyburn/Estevan 02-12-008-08W2/00 2010/12 13 448 159 8% 3,085 N/A16 Petrobakken Weyburn/Estevan 04-14-008-07W2/00 2010/04 21 445 21 12% 3,018 N/A17 Crescent Point Weyburn/Estevan 01-12-007-11W2/00 2008/07 42 443 39 6% 3,173 N/A18 Petrobakken Weyburn/Estevan 01-04-010-07W2/00 2008/10 39 440 20 0% 2,736 N/A19 Petrobakken Weyburn/Estevan 05-33-007-09W2/00 2007/11 50 439 56 5% 3,150 1,62920 Husky Weyburn/Estevan 12-36-001-13W2/00 2011/01 12 422 215 9% 3,571 N/A21 Petrobakken Weyburn/Estevan 01-36-007-11W2/00 2008/04 45 421 31 5% 3,166 1,64422 Petrobakken Weyburn/Estevan 10-23-008-06W2/00 2009/08 29 420 14 8% 2,186 N/A23 Legacy Weyburn/Estevan 04-36-001-07W2/00 2010/09 16 417 67 5% 3,481 N/A24 Petrobakken Weyburn/Estevan 02-30-009-09W2/00 2010/10 15 413 128 1% 2,990 N/A25 Penn West Weyburn/Estevan 04-03-009-09W2/00 2009/03 34 413 75 5% 3,044 N/A26 Crescent Point Weyburn/Estevan 13-26-008-08W2/00 2007/08 53 408 7 1% 3,031 1,54127 Husky Weyburn/Estevan 04-27-001-13W2/00 2010/08 17 408 98 8% 3,811 2,27228 Petrobakken Weyburn/Estevan 12-36-008-07W2/00 2007/12 49 395 43 0% 2,991 1,48329 Petrobakken Weyburn/Estevan 03-35-007-11W2/00 2009/12 25 394 26 11% 2,365 N/A30 Petrobakken Weyburn/Estevan 13-13-008-07W2/00 2009/09 28 394 139 14% 3,022 1,52231 Petrobakken Weyburn/Estevan 03-35-008-10W2/00 2008/08 41 392 41 0% 3,077 N/A32 Petrobakken Weyburn/Estevan 03-24-007-11W2/00 2007/09 52 392 33 0% 3,164 1,67833 Petrobakken Weyburn/Estevan 03-17-008-07W2/00 2008/09 40 392 8 0% 2,925 N/A34 Crescent Point Weyburn/Estevan 01-29-008-07W2/00 2010/08 17 391 145 7% 2,919 N/A35 Petrobakken Weyburn/Estevan 03-34-008-10W2/00 2007/12 49 390 17 0% 3,102 1,55336 Petrobakken Weyburn/Estevan 05-25-008-07W2/00 2008/06 43 388 84 0% 2,279 N/A37 Petrobakken Weyburn/Estevan 02-05-009-08W2/00 2009/02 35 388 16 11% 2,295 N/A38 Crescent Point Weyburn/Estevan 03-01-009-09W2/00 2007/09 52 384 14 0% 2,908 1,53939 Crescent Point Weyburn/Estevan 15-31-008-08W2/00 2010/02 23 382 83 8% 3,044 N/A40 Petrobakken Weyburn/Estevan 16-06-008-05W2/00 2011/03 10 378 84 14% 2,883 N/A

All Producers (2255) - Average 152 35 5% 2,883 1,559


Low Mid HighMidcycle1 Well Economics: Curve Curve Curve NPV (B-Tax) (C$,mlns) $0.9 $3.9 $6.5 NPV (A-Tax) (C$,mlns) $0.5 $2.7 $4.6 IRR (A-tax) (%) 16% 59% 169% P/I Ratio2 (A-tax) 0.2x 1.3x 2.3x Payback Period (yrs) 4.8 1.8 0.8


2012 2013 2014Well Cost (C$,mln): $2MM 1st yr Decline Rate: 65% WTI (US$/bbl) $90.00 $87.50 $85.00Op Costs (incl.trans): $9.00/Boe 2nd yr Decline Rate: 25% FX ($US/$Cdn) $0.99 $0.98 $0.98Discount Rate: 9% Success Rate: 90% Nat Gas (C$/mcf) $2.39 $3.43 $4.08

Assumptions

CIBC Base Commodity Price Assumption

Bakken Type Curve Economics NPV/well Sensitivity (+/- 20%)

$1.5 $1.0 $0.5 $0.0 $0.5 $1.0 $1.5

Operating Cost

Royalties

Capital Cost

Productivity

Commodity Prices

(C$,mlns)

Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Haynesville

Marcellus

Bakken

(SK

)


202

Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Haynesville

Marcellus

Bakken

(S

K)


203

Bakken - YOY Actual Results – VIEWFIELD CORE Bakken - YOY Actual Results – VIEWFIELD TIER 2

Source: GeoScout; Company reports. Source: GeoScout; Company reports.

Bakken - YOY Actual Results – FLAT LAKE Bakken - YOY Actual Results – TAYLORTON/PINTO


Bakken - YOY Actual Results – WATERFLOOD Pilot #1 Bakken - YOY Actual Results – WATERFLOOD Pilot #2






VIEWFIELD CORE - Bakken Hz Wells Average Per Well Production

0

50

100

150

200

250

300


Pro

du

cti

on

Ra

te (

Bo

e/d

) 2007 (231 Wells)

2008 (515 Wells)

2009 (342 Wells)

2010 (354 Wells)

2011 (237 Wells)

Our mid-case type curve is largely derisked in the core area.

FLAT LAKE - Bakken Hz Wells Average Per Well Production

0

50

100

150

200

250

300

350


Pro

du

ctio

n R

ate

(B

oe

/d)

2007 (1 Wells)

2008 (5 Wells)

2009 (3 Wells)

2010 (15 Wells)

2011 (10 Wells)

Although still early days, the latest results at Flat Lake have shown material improvement.

VIEWFIELD TIER 2 - Bakken Hz Wells Average Per Well Production

0

50

100

150

200

250

300


Pro

du

cti

on

Ra

te

(Bo

e/d

)

2007 (13 Wells)

2008 (94 Wells)

2009 (49 Wells)

2010 (62 Wells)

2011 (37 Wells)

Results in the halo of the main pool have shown modest improvement in 2011.

TAYLORTON/PINTO - Bakken Hz Wells Average Per Well Production

0

50

100

150

200

250

300


Pro

du

ctio

n R

ate

(B

oe

/d)

2007 (1 Wells)

2008 (16 Wells)

2009 (17 Wells)

2010 (32 Wells)

2011 (38 Wells)

Results at Taylorton have also improved.

Combined Production - 4 HZ Wells Offsetting Injector

0102030405060708090

100

2007

-01

2007

-05

2007

-09

2008

-01

2008

-05

2008

-09

2009

-01

2009

-05

2009

-09

2010

-01

2010

-05

2010

-09

2011

-01

2011

-05

2011

-09

Wat

er C

ut

(%)

0100200300400500600700

Pro

duct

ion

(Boe

/d)

Percent: WTR Cut Production (Boe/d)

Waterflood Response

Injection started

Weather Impact

2nd two HZs recompleted

First two HZs recompleted


0102030405060708090

100

2009

-01

2009

-03

2009

-05

2009

-07

2009

-09

2009

-11

2010

-01

2010

-03

2010

-05

2010

-07

2010

-09

2010

-11

2011

-01

2011

-03

2011

-05

2011

-07

2011

-09

Wat

er C

ut

(%)

050100150200250300350400450500

Pro

du

ctio

n (

Bo

e/d

)

Percent: WTR CutProduction (Boe/d)


Waterflood Response

Production appears to be recovering from flooding

Combined Production - 4 HZ Wells Offsetting Injectors

0102030405060708090

100

2009

-10

2009

-12

2010

-02

2010

-04

2010

-06

2010

-08

2010

-10

2010

-12

2011

-02

2011

-04

2011

-06

2011

-08

Wat

er

Cu

t (%

)

100

200

300

400

500

600

Pro

du

ctio

n (

Bo

e/d

)

Water Cut (%) Production (Boe/d)

We may be seeing the first signs of production response from CPG's 4th pilot.

Injection started


0102030405060708090

100

2011

-01

2011

-03

2011

-05

2011

-07

2011

-09

2011

-11

2012

-01

2012

-03

2012

-05

2012

-07

2012

-09

2012

-11

Wa

ter

Cu

t (%

)

100300500700900110013001500

Pro

du

ctio

n (

Bo

e/d

)Water Cut (%) Production (Boe/d)

Injection started

Still early days on 6th pilot.


0102030405060708090

100

2010

-01

2010

-03

2010

-05

2010

-07

2010

-09

2010

-11

2011

-01

2011

-03

2011

-05

2011

-07

2011

-09

Wat

er C

ut

(%)

0

500

1,000

1,500

2,000

2,500

Pro

du

ctio

n (

Bo

e/d

)


Weather Impact

Injection started

3rd pilot beginning to show response to water injection


0102030405060708090

100

2011

-01

2011

-03

2011

-05

2011

-07

2011

-09

2011

-11

2012

-01

2012

-03

2012

-05

2012

-07

2012

-09

2012

-11

Wat

er C

ut

(%)

0100200300400500600700800

Pro

du

ctio

n (

Bo

e/d

)


Injection started

Still early days on 5th pilot, but we may already be seeing production response.

Injection started

Pilot #2 - Combined Production - 4 HZ Wells Offsetting Injector

0

50

100

150

200

250

300

350

400

450

50020

09-0

1

2009

-03

2009

-05

2009

-07

2009

-09

2009

-11

2010

-01

2010

-03

2010

-05

2010

-07

2010

-09

2010

-11

2011

-01

2011

-03

2011

-05

2011

-07

2011

-09

2011

-11

2012

-01

2012

-03

2012

-05

Pro

duct

ion (B

oe/

d)

0

10

20

30

40

50

60

70

80

90

100

Wat

er C

ut (%

)

Production (Boe/d) Percent: WTR Cut

Injection Started


0

100

200

300

400

500

600

700

2007-0

1

2007-0

4

2007-0

7

2007-1

0

2008-0

1

2008-0

4

2008-0

7

2008-1

0

2009-0

1

2009-0

4

2009-0

7

2009-1

0

2010-0

1

2010-0

4

2010-0

7

2010-1

0

2011-0

1

2011-0

4

2011-0

7

2011-1

0

2012-0

1

2012-0

4

Pro

duct

ion (B

oe/

d)

0

10

20

30

40

50

60

70

80

90

100

Wate

r C

ut (%

)


Injection Started

2nd two HZs recompleted



0

500

1000

1500

2000

2500

2010-

01

2010-

03

2010-

05

2010-

07

2010-

09

2010-

11

2011-

01

2011-

03

2011-

05

2011-

07

2011-

09

2011-

11

2012-

01

2012-

03

2012-

05

Pro

duct

ion (B

oe/d

)

0

10

20

30

40

50

60

70

80

90

100

Wat

er C

ut (%

)

Production (Boe/d) Percent: WTR CutInjection Started


0

100

200

300

400

500

600

2009

-01

2009

-03

2009

-05

2009

-07

2009

-09

2009

-11

2010

-01

2010

-03

2010

-05

2010

-07

2010

-09

2010

-11

2011

-01

2011

-03

2011

-05

2011

-07

2011

-09

2011

-11

2012

-01

2012

-03

2012

-05

Pro

duction (B

oe/

d)

0

10

20

30

40

50

60

70

80

90

100

Wate

r C

ut (%

)


Injection Started


0

100

200

300

400

500

600

700

800

2011-

01

2011-

02

2011-

03

2011-

04

2011-

05

2011-

06

2011-

07

2011-

08

2011-

09

2011-

10

2011-

11

2011-

12

2012-

01

2012-

02

2012-

03

2012-

04

2012-

05

2012-

06

2012-

07

2012-

08

2012-

09

2012-

10

2012-

11

Pro

duct

ion (B

oe/

d)

0

10

20

30

40

50

60

70

80

90

100

Wat

er C

ut (%

)


Injection Started


0

200

400

600

800

1000

1200

1400

1600

2011

-01

2011

-02

2011

-03

2011

-04

2011

-05

2011

-06

2011

-07

2011

-08

2011

-09

2011

-10

2011

-11

2011

-12

2012

-01

2012

-02

2012

-03

2012

-04

2012

-05

2012

-06

2012

-07

2012

-08

2012

-09

2012

-10

2012

-11

Pro

duct

ion (B

oe/

d)

0

10

20

30

40

50

60

70

80

90

100

Wat

er

Cut (%

)


Injection Started

Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Haynesville

Marcellus

Bakken

(SK

)


204

Tight Carbonates - Area Map (Circa August, 2012) Tight Carbonates - Resource Potential


Tight Carbonates - Area Production Growth

Note: Map updated as of May 2012. Source: GeoScout; Company reports; Geological Atlas of Western Canada; The Edge; Canadian Discovery Digest; Sherwin; CIBC World Markets Inc. Source: GeoScout; CIBC World Markets Inc.

Tight Carbonates - Horizontal Well Operator Summary (Circa August, 2012)


Tight Carbonates - Schematic Cross Section Tight Carbonates - Land Position by Operator

Source: Company reports; The Edge; Canadian Discovery Digest; CIBC World Markets Inc.1) 1 section = 640 acres; 2) Denotes private company; 3) Denotes CIBC/Geoscout Estimate. Note: Land positions include acreage accessible via farm-in agreements. Source: Company reports; GeoScout; CIBC World Markets Inc.

Tight Carbonate Land Holders545

266208

150108 100 100 100

72 64 64 63 45 23 14 30 29 23 15

0

100

200

300

400

500

600

Pen

n W

est

Pen

grow

th

Co

ral H

ill (

2)

Arc

an

Apa

che

(3)

KN

OC

/Har

vest

(2)(

3)

Dev

on

(3)

Pin

ecre

st (

3)

AR

C

Lone

Pin

e (2

)

Fo

rest

Oil

Pac

e

Sec

ond

Wa

ve

Bay

tex

Wild

Str

eam

Dol

omite

(2

)

Pac

e

Bay

tex

Wild

Str

eam

Net

Sec

tio

ns

(1)

Total# Operated # Licensed Op./Lic. Oil & Liquids Nat. Gas Nat. Gas Nat. Gas Total Oil & Liquids Nat. Gas Total

Company Ticker Hz Wells Wells Wells (bbl/d) (boe/d) (mcf/d) (%) (boe/d) (bbl/d) (mcf/d) (boe/d)Penn West Petrl Ltd PWT 48 36 84 4,727 326 1,954 6% 5,052 98 41 105Coral Hill Enrg Ltd PRIVATE 17 12 29 3319 745 4471 18% 4,064 195 263 239Pengrowth Enrg Corp PGF 43 15 58 3,461 410 2,457 11% 3,871 80 57 90Arcan Rsrcs Ltd ARN 41 18 59 3,403 262 1,573 7% 3,665 83 38 89Pinecrest Enrg Inc PRY 29 8 37 2,731 62 370 2% 2,793 94 13 96Lone Pine Rsrcs Cda Lt LPR 63 8 71 2,549 131 787 5% 2,681 40 12 43Second Wave Petrl Ltd SCS 17 7 24 2,313 327 1,959 12% 2,639 136 115 155Apache Cda Ltd APA-NYSE 20 4 24 1392 107 640 7% 1,499 70 32 75Harvest Oprtns Corp PRIVATE 44 11 55 1,280 14 82 1% 1,294 29 2 29Devon Cda Corp DVN-NYSE 11 - 11 746 70 420 9% 816 68 38 74Mancal Enrg Inc PRIVATE 3 - 3 689 10 62 0 699 230 21 233Surge Enrg Inc SGY 6 1 7 627 1 7 0 628 104 1 105Avenex Enrg Corp AVF 4 - 4 90 39 236 30% 130 23 59 32Barrick Enrg Inc PRIVATE 2 - 2 69 26 155 27% 95 34 77 47Baytex Enrg Ltd BTE 3 4 7 88 2 10 2% 89 29 3 30Dolomite Enrg Inc PRIVATE 3 3 6 84 1 7 1% 85 28 2 28Guide Exploration GO 2 - 2 36 30 180 46% 66 18 90 33Crescent Point Enrg Co CPG 4 4 8 45 4 22 8% 48 11 5 12ARC Rsrcs Ltd ARX 3 - 3 35 12 74 26% 48 12 25 16Athabasca Oil Sands Co ATH 1 - 1 0 31 186 100% 31 0 186 31


Carbonates

-

25

50

75

100

125

150

175

Q2/

08Q

3/08

Q4/

08Q

1/09

Q2/

09Q

3/09

Q4/

09Q

1/10

Q2/

10Q

3/10

Q4/

10Q

1/11

Q2/

11Q

3/11

Q4/

11Q

1/12

Q2/

12Q

3/12

Q4/

12Q

1/13

Q2/

13Q

3/13

Q4/

13Q

1/14

Q2/

14Q

3/14

Q4/

14Q

1/15

Q2/

15Q

3/15

Q4/

15

Tota

l Pro

duct

ion

(MB

oe/d

)

0

25

50

75

100

125

150

175


oe/d)

Pre 2008 2008 2009 2010 2011

2012 2013 2014 2015 Liquids

Actual Forecast

<1% <1%16%

28%

<1%4% 1% 7% 5% 2% 2%

4.0

2.5

4.3 5.0 6.0

7.5

10.010.0

20.0

15.0

2.5

20.0

25.0

15.0 15.0

0

5

10

15

20

25

Bakk

en(A

lber

ta)

Seal

Duv

erna

y

Car

dium

Tigh

tC

arbo

nate

s

Viki

ng

Bakk

en

(SE

Sask

.)Lo

wer

Shau

navo

n

Peki

sko

Amar

anth

Mon

tney

Oil

Bar

rels

of O

il (B

ln)


Recovered-to-Date

Carb

on

ate

s

Bakken

Card

ium

C

ard

ium

Gas

Gla

uco

nite

Ho

rn R

iver

Montney

VET


205

Tight Carbonates - SWAN HILLS Type Curves Tight Carbonates - SWAN HILLS Type Curve Well Economics (Mid Cycle)

Tight Carbonates - SLAVE POINT Type Curves Tight Carbonates - SLAVE POINT Type Curve Well Economics (Mid Cycle)

Tight Carbonates - Variance of Results - All Time Tight Carbonates - Variance of Results - 2011 to Present


Tight Carbonates - Distribution By Peak I.P. Rates Tight Carbonates - Top Wells

Tight Carbonates - YOY Actual Results - Swan Hills Trend Tight Carbonates - YOY Actual Results - Slave Point Trend








SWAN HILLS HZ Wells - Type Curves

0

100

200

300

400

500

600

700


Pro

du

cti

on

Ra

te (

bo

e/d

)




SLAVE POINT HZ Wells - Type Curves

0

50

100

150

200

250

300

350

400

450


Pro

du

cti

on

Ra

te (

bo

e/d

)




Variance to Mean - All TimeHORIZONTAL Tight Carbonates Wells

14 1314225872406 360 280 207 169 107 81-200

-100

0

100

200

300

400

500


Pro

d. R

ate

(Bo

e/d

) Mean (Average)



Variance to Mean - 2011 to Present

HORIZONTAL Tight Carbonates Wells

241 241 179 106 68 26

-200

-100

0

100

200

300

400

500

3 6 9 12 15 18 21 24 27 30 33 36


Pro

du

ctio

n R

ate

(B

oe

/d)

Mean (Average)



# o f Wells

# o f Wells

SWAN HILLS Hz Wells Average Per Well Production

0

100

200

300

400


Pro

d.

Ra

te (

bo

e/d

)

2008 (3 Wells)

2009 (11 Wells)

2010 (46 Wells)

2011 (112 Wells)

2012 (57 Wells)

Increasing data set of strong results derisking Swan Hills Trend.

SLAVE POINT - Tight Carbonates Hz Wells Average Per Well Production

0

100

200

300

400


Pro

d.

Ra

te (

bo

e/d

)

2008 (6 Wells)

2009 (7 Wells)

2010 (34 Wells)

2011 (130 Wells)

2012 (44 Wells)

Results also improving in the northern Slave Point carbonates trend, where 1st year decline rates appear lower.


1 Second Judy Creek 13-25-063-10W5 2011/10 7 2,769 313 20% 4,107 2,5422 Second Judy Creek 13-20-063-09W5 2012/03 2 1,984 1,984 34% 4,317 2,4943 Coral Hill Swan Hills South 12-20-064-09W5 2011/01 16 1,948 220 16% 3,696 2,5004 Coral Hill Virginia Hills 12-20-064-13W5 2011/07 10 1,846 647 15% 4,135 2,8915 Second Judy Creek 13-35-063-10W5 2011/12 5 1,471 334 4% 4,191 2,6366 Second Judy Creek 03-36-063-10W5 2011/12 5 1,450 352 18% 4,236 2,6277 Coral Hill Swan Hills South 05-36-064-10W5 2011/06 11 1,386 241 20% 4,014 2,4238 Second Swan Hills South 13-01-064-10W5 2012/02 3 1,262 130 14% 4,011 2,5259 Arcan Virginia Hills 13-32-064-13W5 2012/03 2 1,066 1,066 8% 4,506 2,85710 Second Judy Creek 15-36-063-10W5 2011/04 13 932 229 17% 4,006 2,54911 Pengrowth Judy Creek 13-12-063-12W5 2011/01 16 850 267 11% 4,146 2,64212 Arcan Swan Hills 09-29-068-08W5 2010/03 26 799 98 3% 3,491 2,31213 Arcan Swan Hills 04-02-068-09W5 2010/12 17 782 116 0% 3,065 2,38714 Apache Swan Hills 07-30-069-09W5 2010/04 25 767 149 5% 2,855 2,19715 Devon Swan Hills 15-07-067-09W5 2011/11 6 748 231 7% 4,121 2,61516 Arcan Swan Hills 13-15-068-08W5 2011/09 8 738 296 6% 3,629 2,35517 Coral Hill Virginia Hills 04-33-064-13W5 2011/11 6 728 508 18% 4,366 2,83418 Arcan Ethel 01-04-068-08W5 2011/06 11 727 179 5% 3,320 2,30119 Coral Hill Swan Hills South 04-02-065-10W5 2011/08 9 673 169 22% 4,011 2,45420 Second Judy Creek 16-24-063-10W5 2012/01 4 656 207 16% 4,243 2,56021 Pengrowth Judy Creek 12-33-063-09W5 2012/03 2 614 614 2% 3,929 2,43222 Pengrowth Judy Creek 01-04-064-10W5 2011/08 9 605 282 11% 3,941 2,55523 Coral Virginia Hills 05-27-066-13W5 2011/04 13 593 246 8% 4,584 2,92924 Arcan Ethel 10-27-067-08W5 2010/05 24 592 60 0% 3,647 2,30325 Arcan Ethel 13-26-067-08W5 2011/06 11 571 155 2% 4,006 2,304



Distribution by Peak 30-Day I.P. Rate HORIZONTAL Tight Carbonates Wells

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

10 20 30 40 50 60 70 80 90 100

110

120

130

140

150

160

170

180

190

200

210

220

230

240

250

260

270

280

290

300

310

320

330

340

350

360

370

380

390

400

Well Count

Pea

k I.P

. Rat

e (B

oe/

d)


Distribution Curve

0

20

40

60

80

100

120

140

0

200

400

600

800

(Boe/d)

Cou

ntLow Mid High

Midcycle1 Well Economics: Curve Curve Curve NPV (B-Tax) (C$,mlns) - $3.8 $8.2 NPV (A-Tax) (C$,mlns) - $2.2 $5.4 IRR (A-tax) (%) - 24% 78% P/I Ratio2 (A-tax) - 0.4x 1.0x Payback Period (yrs) - 3.6 1.5

Low Mid High NPV9 Breakeven ($US/bbl) - $58.50 $47.50


SWAN HILLS Type Curve Economics NPV/well Sensitivity (+/- 20%)


$2.0 $1.5 $1.0 $0.5 $0.0 $0.5 $1.0 $1.5 $2.0 $2.5

Operating Cost

Royalties

Capital Cost

Productivity

Commodity Prices

(C$,mlns)

Low Mid High




SLAVE POINT Type Curve Economics NPV/well Sensitivity (+/- 20%)


$1.5 $1.0 $0.5 $0.0 $0.5 $1.0 $1.5 $2.0

Operating Cost

Royalties

Capital Cost

Productivity

Commodity Prices

(C$,mlns)

Carb

on

ate

s B

akken

Card

ium

C

ard

ium

Gas

Gla

uco

nite

Ho

rn R

iver

Montney

VET


206

Carb

on

ate

s

Bakken

Card

ium

C

ard

ium

Gas

Gla

uco

nite

Ho

rn R

iver

Montney

VET


207

Tight Carbonates - Generic Type Curves Tight Carbonates - YOY Actual Results - ALL PRODUCERS

Tight Carbonates - YOY Actual Results - SWAN HILLS Tight Carbonates - YOY Actual Results - SAWN LAKE / RED EARTH / EVI


Tight Carbonates - YOY Actual Results - UTIKUMA LAKE / NIPISI Tight Carbonates - YOY Actual Results - DAWSON / PUSKWASKAU


Note: We will be watching actual results to either validate or disprove these type curves, and plan to make adjustments on an on-going basis as dictated by empirical data. Source: GeoScout; Company reports; CIBC World Markets Inc. Source: GeoScout; CIBC World Markets Inc.

Tight Carbonates Hz Wells Average Per Well Production

0

100

200

300

400


Pro

d. R

ate

(bo

e/d

)

2008 (8 Wells) 2009 (12 Wells)

2010 (81 Wells) 2011 (241 Wells)

2012 (64 Wells)

Tight Carbonates HZ Wells - Type Curves

0

100

200

300

400

500

600

700


Pro

d. R

ate

(Bo

e/d

)




SAWN LAKE / RED EARTH / EVI Hz Wells Average Per Well Production

0

100

200

300

400


Pro

d. R

ate

(bo

e/d

)

2008 (6 Wells) 2009 (7 Wells)2010 (33 Wells) 2011 (122 Wells)2012 (41 Wells)

Results also improving in the northern Slave Point carbonates trend, where 1st year decline rates appear lower.

SWAN HILLS Hz Wells Average Per Well Production

0

100

200

300

400


Pro

d. R

ate

(bo

e/d

)


Increasing data set of strong results derisking Swan Hills Trend.

UTIKUMA LAKE / NIPISI Hz Wells Average Per Well Production

0

100

200

300

400

0 3 6 9 12 15 18 21 24


Pro

d. R

ate

(bo

e/d

)

2010 (1 Wells) 2011 (7 Wells)

2012 (3 Wells)

DAWSON / PUSKWASKAU Hz Wells Average Per Well Production

0

100

200

300

400


Pro

d. R

ate

(bo

e/d

)

2009 (1 Wells) 2011 (3 Wells)

Carb

on

ate

s B

akken

Card

ium

C

ard

ium

Gas

Gla

uco

nite

Ho

rn R

iver

Montney

VET

Carbonates

Bak

ken

Card

ium

Card

ium

G

as

Gla

uco

ni

te H

or

n

Riv

er Montney V

ET


210

Cardium Oil - Area Map (Circa August, 2012) Cardium Oil - Resource Potential


Cardium Oil - Area Production Growth


Cardium Oil - Horizontal Well Operator Summary (Circa August, 2012)


Cardium Oil - Schematic Cross Section Cardium Oil - Land Position by Operator

Source: CIBC World Markets Inc.Notes 1) 1 section = 640 acres; 2) Denotes private company. Land positions are approximations based on company disclosure and public data, and do not adjust for prospectivity. Source: Company reports; GeoScout; CIBC World Markets Inc.

Cardium Land Holders

300

265

219

209

204

195

149

132

124

120

118

110

102

100

91 81 80 75 71 67 60 57 52 51 50 49 48 47 40 38 27 25 20 17 13

0

50

100

150

200

250

300

350

400

450

500

Penn

Wes

t

Bona

vist

a

Petro

Bakk

en

Peng

row

th

Angl

e

Con

ocoP

hillip

s

NAL

Verm

ilion

ARC

Whi

teca

p

Vero

Bont

erra

Bella

trix

Fairb

orne

Sino

pec

NuV

ista

Ande

rson

Talis

man

Exxo

n/Im

peria

l

Com

pton

Para

mou

nt

Sunc

or

TriO

il

TAQ

A N

orth

Spar

tan

Cro

cotta

Apac

he

Dev

on

Ener

plus

Perp

etua

l

KNO

C(2

)

Cre

w

Hus

ky BP

Del

phi

Equa

l

Net

Sec

tions

(1)

1039

Total# Operated # Licensed Op./Lic. Oil & Liquids Nat. Gas Nat. Gas Nat. Gas Total Oil & Liquids Nat. Gas Nat. Gas Total

Company Ticker Hz Wells Wells Wells (bbl/d) (boe/d) (mcf/d) (%) (boe/d) (bbl/d) (boe/d) (mcf/d) (boe/d)Petrobakken Enrg Ltd PBN 179 23 202 12,067 2,268 13,609 16% 14,335 67 13 76 80Penn West Petrl Ltd PWT 146 61 207 5,579 3,616 21,698 39% 9,195 38 25 149 63Vermilion Rsrcs Ltd VET 59 13 72 4,814 1,180 7,081 20% 5,994 82 20 120 102Bellatrix Expl Ltd BXE 49 10 59 2,886 1,843 11,055 39% 4,728 59 38 226 96Whitecap Rsrcs Inc WCP 75 6 81 2,873 1,597 9,579 36% 4,470 38 21 128 60NAL Rsrcs Lmtd NAE 64 12 76 3,078 1,362 8,173 31% 4,440 48 21 128 69ARC Rsrcs Ltd ARX 58 24 82 2,902 817 4,904 22% 3,720 50 14 85 64Sinopec Daylight Enrg Ltd PRIVATE 67 19 86 2,536 628 3,767 20% 3,164 38 9 56 47Bonterra Enrg Corp BNE 49 4 53 1,873 1,046 6,275 36% 2,919 38 21 128 60Midway Enrg Ltd MEL 51 6 57 1,639 1,070 6,421 40% 2,709 32 21 126 53Anderson Enrg Ltd AXL 65 10 75 1,841 739 4,433 29% 2,580 28 11 68 40Taqa North Ltd TAQA-ADX 22 17 39 1,126 1,302 7,810 54% 2,428 51 59 355 110Devon Cda Corp DVN-NYSE 10 8 18 423 1,479 8,877 78% 1,903 42 148 888 190Skywest Enrg Corp SKW 17 2 19 640 1,249 7,493 66% 1,889 38 73 441 111Baccalieu Enrg Inc PRIVATE 20 17 37 866 696 4,177 45% 1,562 43 35 209 78Spartan Oil Corp STO 13 7 20 1,285 249 1,493 16% 1,534 99 19 115 118Vero Enrg Inc VRO 30 3 33 1,001 490 2,941 33% 1,491 33 16 98 50Bonavista Enrg Corp BNP 21 9 30 834 494 2,966 37% 1,328 40 24 141 63ConocoPhillips Cda Corp COP 15 12 27 653 630 3,780 49% 1,283 44 42 252 86Angle Enrg Inc NGL 12 2 14 381 900 5,400 70% 1,281 32 75 450 107


Cardium

-

50

100

150

200

250

300

350

400

450

Q2/

08Q

3/08

Q4/

08Q

1/09

Q2/

09Q

3/09

Q4/

09Q

1/10

Q2/

10Q

3/10

Q4/

10Q

1/11

Q2/

11Q

3/11

Q4/

11Q

1/12

Q2/

12Q

3/12

Q4/

12Q

1/13

Q2/

13Q

3/13

Q4/

13Q

1/14

Q2/

14Q

3/14

Q4/

14Q

1/15

Q2/

15Q

3/15

Q4/

15

Tota

l Pro

duct

ion

(MB

oe/d

)

0

50

100

150

200

250

300

350

400

450


oe/d)

Pre 2008 2008 2009 2010 2011

2012 2013 2014 2015 Liquids

Actual Forecast

<1% <1%16%

28%

<1%4% 1% 7% 5% 2% 2%

4.0

2.5

4.3 5.0 6.0

7.5

10.010.0

20.0

15.0

2.5

20.0

25.0

15.0 15.0

0

5

10

15

20

25

Bakk

en(A

lber

ta)

Seal

Duv

erna

y

Car

dium

Tigh

tC

arbo

nate

s

Viki

ng

Bakk

en

(SE

Sask

.)Lo

wer

Shau

navo

n

Peki

sko

Amar

anth

Mon

tney

Oil

Bar

rels

of O

il (B

ln)


Recovered-to-Date

Amaranth

Card

ium

Card

ium

Card

ium

G

as

Gla

uco

nite

Ho

rn R

iver

Montney

VET


211

Cardium Oil - Generic Type Curves Cardium Oil - Type Curve Well Economics (Mid Cycle)

Cardium Oil - YOY Actual Results – All Producers Cardium Oil - Variance of Results - All Time


Cardium Oil - Distribution By Peak I.P. Rates Cardium Oil - Top Wells





Distribution by Peak I.P. Rate HORIZONTAL Cardium Oil Wells

0

100

200

300

400

500

600

700

800

900

1000

1100

1200

50

100

150

200

250

300

350

400

450

500

550

600

650

700

750

800

850

900

950

1000

1050

1100

1150

1200

1250

1300

Well Count

Pea

k I.P

. Rat

e (

Bo

e/d

)


2009 (46 Wells)

2010 (405 Wells)

2011 (737 Wells)

2012 (156 Wells)

Median

Mean (Average)

Top/Bottom Quartile

Variance to Mean - All TimeHORIZONTAL Cardium Wells

1235 1035 804 714 496 331 198 146 57 25 11 81347-100

-50

0

50

100

150

200

250

300

350

400


Pro

du

ctio

n R

ate

(Bo

e/d

)Mean (Average)



Average well performance now exceeding our mid-case type curve.

Cardium Hz Wells - Type Curves

0

50

100

150

200

250

300

350

400

0 3 6 9 12 15 18 21 24 27 30


Pro

du

ctio

n R

ate

(Bo

e/d

)




ALL Cardium Hz Wells Average Per Well Production

0

50

100

150

200

250

300

350

400


Pro

du

ctio

n R

ate

(bo

e/d

)

2008 (2 Wells) 2009 (46 Wells)

2010 (405 Wells) 2011 (737 Wells)

2012 (156 Wells)

# of Wells


1 ARC Pembina 13-33-048-06W5 2012/02 3 2,099 225 18% 3,619 1,3882 Tamarack Pembina 04-35-046-06W5 2011/10 7 1,797 188 88% 3,451 1,5063 Sinopec Pembina 16-28-050-06W5 2010/03 26 1,184 83 2% 2,571 1,2464 Bellatrix Willesden Green 13-30-042-08W5 2010/11 18 1,071 77 19% 3,484 1,9915 Bellatrix Pembina 15-26-045-11W5 2012/03 2 1,030 1,030 21% 3,479 2,0256 Solara Pembina 13-09-045-05W5 2010/09 20 1,004 65 23% 2,921 1,6597 Bellatrix Willesden Green 12-30-042-08W5 2010/12 17 942 58 19% 3,506 2,0028 Skywest Willesden Green 16-15-043-09W5 2012/01 4 898 396 21% 3,461 2,0509 Bellatrix Willesden Green 05-19-042-08W5 2010/11 18 829 108 48% 3,186 2,00410 NAL Lochend 16-19-027-03W5 2011/10 7 813 386 34% 3,841 2,30911 Bellatrix Pembina 04-01-045-11W5 2012/03 2 754 754 44% 3,564 2,05612 Bellatrix Willesden Green 11-20-042-08W5 2011/11 6 753 251 23% 3,638 1,98213 Midway Caroline 04-21-034-04W5 2010/12 17 753 49 21% 3,502 2,05714 Spartan Pembina 12-19-048-04W5 2012/03 2 748 748 7% 2,846 1,31615 Penn West Willesden Green 12-13-043-09W5 2010/07 22 741 155 27% 3,706 2,02016 Vero Edson 15-25-054-18W5 2011/12 5 734 486 53% 3,294 1,80517 Exoro Ferrier 03-02-040-08W5 2011/10 7 731 109 27% 3,707 2,13218 Bellatrix Willesden Green 04-19-042-08W5 2011/07 10 728 96 28% 3,249 2,00619 Bellatrix Willesden Green 05-30-042-08W5 2010/10 19 721 116 13% 3,581 2,00120 Angle Ferrier 03-26-038-08W5 2011/12 5 706 420 78% 3,124 2,29221 Anterra Pembina 01-17-045-05W5 2011/01 16 706 73 20% 3,131 1,64722 Bonavista Willesden Green 01-03-042-08W5 2011/07 10 706 162 38% 3,340 1,93923 ConocoPhillipFir 13-06-059-21W5 2011/04 13 693 333 25% 3,796 1,94224 Sinopec Pembina 13-21-050-06W5 2010/09 20 679 1 5% 2,819 1,25225 Angle Ferrier 15-27-038-08W5 2011/07 10 672 209 64% 3,607 2,30326 Bellatrix Willesden Green 03-20-042-08W5 2011/12 5 658 305 29% 3,185 2,02127 ConocoPhillipPlacid 13-32-059-23W5 2011/04 13 657 222 23% 3,709 1,97528 Bellatrix Willesden Green 12-20-042-08W5 2011/02 15 652 111 19% 3,333 1,99629 Bellatrix Brazeau River 04-02-045-11W5 2012/02 3 650 650 44% 3,606 2,07230 Angle Ferrier 08-22-038-08W5 2010/07 22 645 95 66% 3,608 2,31931 ConocoPhillipPlacid 14-32-059-23W5 2011/04 13 644 162 34% 3,200 1,97132 Hyperion Garrington 09-27-033-03W5 2011/09 8 644 71 11% 3,382 1,89433 Vero Edson 01-24-054-18W5 2012/03 2 642 642 37% 3,221 1,82734 Midway Garrington 15-24-035-04W5 2010/09 20 636 50 23% 3,453 1,89535 Penn West Willesden Green 04-17-042-08W5 2012/03 2 630 630 37% 3,194 2,043



Distribution Curve

050

100150200250300350400

0

15

0

30

0

45

0

60

0

(Boe/d)

Cou

nt

Low Mid HighMidcycle1 Well Economics Curve Curve Curve NPV (B-Tax) (C$,mlns) $0.4 $3.3 $6.4 NPV (A-Tax) (C$,mlns) $0.0 $2.1 $4.4 IRR (A-tax) (%) 9% 36% 93% P/I Ratio2 (A-tax) 0.0x 0.7x 1.5x Payback Period (yrs) 6.6 2.4 1.2


2012 2013 2014Well Cost (C$,mln): $3MM 1st yr Decline Rate: 65% WTI (US$/bbl) $90.00 $87.50 $85.00Op Costs (incl.trans): $9.00/Boe 2nd yr Decline Rate: 25% FX ($US/$Cdn) $0.99 $0.98 $0.98Discount Rate: 9% Success Rate: 90% Nat Gas (C$/mcf) $2.39 $3.43 $4.08

Cardium Type Curve Economics NPV/well Sensitivity (+/- 20%)


Assumptions

$1.5 $1.0 $0.5 $0.0 $0.5 $1.0 $1.5

Operating Cost

Royalties

Capital Cost

Productivity

Commodity Prices

(C$,mlns)

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Cardium Oil - Sub-Area Map (Circa August, 2012)

Source: GeoScout; Company reports; Geological Altas of Western Canada; The Edge; Canadian Discovery Digest; CIBC World Markets Inc.

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Cardium Oil - YOY Actual Results – ALL PRODUCERS Cardium Oil - YOY Actual Results – PEMBINA CORE


Cardium Oil - YOY Actual Results – NW PEMBINA/PINE CREEK Cardium Oil - YOY Actual Results – BRAZEAU / W. PEMBINA


Cardium Oil - YOY Actual Results – NORTHEAST PEMBINA Cardium Oil - YOY Actual Results – EAST PEMBINA


Cardium Oil - YOY Actual Results – WILLESDEN GREEN / FERRIER Cardium Oil - YOY Actual Results – GARRINGTON SOUTH


ALL PRODUCERS - Cardium Hz Wells Average Per Well Production

0

50

100

150

200

250

300

350


Pro

du

ctio

n R

ate

(Bo

e/d

)


While well performance has varied by sub-area, overall average well results in the Cardium

GARRINGTON SOUTH - Cardium Hz Wells Average Per Well Production

0

50

100

150

200

250

300

350

0 3 6 9 12 15 18 21 24


Pro

du

ctio

n R

ate

(Bo

e/d

)


Well performance in the Greater Garrington area has been the most consistent to date in the Cardium.

NW PEMBINA/PINE CREEK - Cardium Hz Wells Average Per Well Production

0

50

100

150

200

250

300

350


Pro

du

ctio

n R

ate

(Bo

e/d

)

2009 (6 Wells) 2010 (20 Wells)

2011 (53 Wells) 2012 (8 Wells)

BRAZEAU / W. PEMBINA - Cardium Hz Wells Average Per Well Production

0

50

100

150

200

250

300

350

0 3 6 9 12 15 18 21 24


Pro

du

ctio

n R

ate

(Bo

e/d

)

2009 (2 Wells) 2010 (96 Wells)

2011 (200 Wells) 2011 (64 Wells)

We believe the West Pembina / Brazeau area to be one of the most prospective areas of the Cardium - showing the strongest rates in the play after 8-9 months on production.

PEMBINA CORE - Cardium Hz Wells Average Per Well Production

0

50

100

150

200

250

300

350

0 3 6 9 12 15 18 21 24


Pro

du

ctio

n R

ate

(Bo

e/d

)


Strong 2011 results in the Pembina Core area (particularly at Minnehik/Buck Lake) have challenged negative preconceptions of the core legacy area.

PEMBINA EAST - Cardium Hz Wells Average Per Well Production

0

50

100

150

200

250

300

350

0 3 6 9 12 15 18 21 24


Pro

du

ctio

n R

ate

(Bo

e/d

) 2009 (9 Wells) 2010 (59 Wells)

2011 (49 Wells) 2012 (21 Wells)

On average, 2010 wells underperformed 2009 wells in East Pembina, while the most recent wells in 2011 have shown improvement.

PEMBINA NORTHEAST - Cardium Hz Wells Average Per Well Production

0

50

100

150

200

250

300

350


Pro

du

ctio

n R

ate

(Bo

e/d

) 2009 (1 Wells) 2010 (19 Wells)

2011 (28 Wells) 2012 (8 Wells)

After a promising start in 2010 (supported by successful conglomerate wells at Tomahawk) follow up wells have, on average, been less impressive to the northeast.

WILLESDEN GREEN / FERRIER - Cardium Hz Wells Average Per Well Production

0

50

100

150

200

250

300

350

0 3 6 9 12 15 18 21 24


Pro

du

ctio

n R

ate

(bo

e/d

) 2010 (34 Wells) 2011 (89 Wells)2012 (34 Wells)

Exceptional results at Willesden Green continue to lead the pack in the play.

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Deep Basin - Area Map (Circa August, 2012)

Deep Basin - Operator Summary (Circa August, 2012)

Source: GeoScout and CIBC World Markets Inc.

Note: Map updated as of May 2012. Source: GeoScout, Sherwin Geoedges, Canadian Discovery Digest, The Edge, Geological Atlas of Western Canada, Core Laboratories, Company reports, CIBC World Markets

Total# Operated # Licensed Op./Lic. Oil Cnds. Oil & Liquids Nat. Gas Nat. Gas Total Oil & Liquids Nat. Gas Total

Company Ticker Hz Wells Wells Wells (bbl/d) (boe/d) (bbl/d) (mcf/d) (%) (mcfe/d) (bbl/d) (mcf/d) (mcfe/d)ConocoPhillips Cda Oprtns COP-NYSE 617 156 773 260 358 618 263,908 99% 267,617 1 428 434EnCana Corp ECA 434 321 755 4 76 79 262,337 100% 262,814 0 604 606Peyto Expl&Dvlp Corp PEY 193 40 233 0 10 10 143,595 100% 143,653 0 744 744Cdn Nat Rsrcs Lmtd CNQ 453 403 856 3010 28 3,038 93,025 84% 111,253 7 205 246Bonavista Enrg Corp BNP 209 40 249 203 66 269 100,124 98% 101,737 1 479 487Shell Cda Lmtd RDS.A 166 62 228 22 48 71 90,158 100% 90,581 0 543 546Apache Cda Ltd APA-NYSE 135 40 175 18 18 36 86,001 100% 86,215 0 637 639Husky Oil Oprtns Ltd HSE 377 241 618 3928 25 3,953 56,209 70% 79,927 10 149 212Paramount Rsrcs Ltd POU 59 24 83 0 30 30 79,606 100% 79,788 1 1,349 1,352Devon Cda Corp DVN-NYSE 121 26 147 9 26 35 65,609 100% 65,822 0 542 544Tourmaline Oil Corp TOU 86 17 103 0 19 19 60,985 100% 61,102 0 709 710Fairborne Enrg Ltd FEL 62 18 80 3 4 7 49,534 100% 49,577 0 799 800Sinopec Daylight Enrg Ltd SNP-NYSE 59 47 106 1 109 110 47,844 99% 48,501 2 811 822Taqa North Ltd TAQA 95 59 154 6 55 61 45,822 99% 46,187 1 482 486Celtic Expl Ltd CLT 78 5 83 3 83 86 45,249 99% 45,764 1 580 587Talisman Enrg Inc TLM 124 180 304 0 20 20 45,461 100% 45,580 0 367 368Angle Enrg Inc NGL 61 12 73 13 19 32 36,968 99% 37,158 1 606 609Perpetual Enrg Operatin PMT 193 16 209 1 9 9 34,299 100% 34,355 0 178 178Velvet Enrg Ltd PRIVATE 46 7 53 15 29 44 33,525 1 33,791 1 729 735Harvest Oprtns Corp PRIVATE 52 18 70 53 21 74 29,416 99% 29,859 1 566 574Nuvista Enrg Ltd NVA 45 13 58 0 7 7 24,344 1 24,386 0 541 542NAL Rsrcs Lmtd NAE 56 30 86 20 49 69 23,800 98% 24,214 1 425 432

Average Production Per WellGross Operated Well Production

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Deep Basin - Generic Type Curves - VERTICAL WELLS Deep Basin - Type Curve Well Economics - VERTICAL WELLS (Mid Cycle)

Deep Basin - Generic Type Curves - HORIZONTAL WELLS Deep Basin - Type Curve Well Economics - HORIZONTAL WELLS (Mid Cycle)

Deep Basin - Variance of Results - 2008 to Present - VERTICAL WELLS Deep Basin - Variance of Results - 2008 to Present - HORIZONTAL WELLS


Deep Basin - Distribution By Peak I.P. Rates - Since 2008 Deep Basin - Top Wells (Cardium to Cadomin)

Deep Basin - YOY Actual Results – VERTICAL WELLS (Cardium to Cadomin) Deep Basin - YOY Actual Results – HORIZONTAL WELLS (Cardium to Cadomin)








Variance to Mean - All Producers (2007 to Present)VERTICAL Deep Basin Wells (Cardium to Cadomin)

2980 2794 2596 2482 2294 2107 1877 1585 1432 1356-2,000

-1,000

0

1,000

2,000

3,000

4,000

5,000

3 6 9 12 15 18 21 24 27 30 33 36


Pro

du

ctio

n R

ate

(Mcf

e/d

)

Mean (Average)



Variance to Mean - All Producers (2007 to Present)HORIZONTAL Deep Basin Wells (Cardium to Cadomin)

1077 1025 894 757 683 558 449 370 317 249 203 177 159-3,000

-2,000

-1,000

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000


Pro

du

ctio

n R

ate

(Mcf

e/d

)Mean (Average)



# o f Wells

ALL VT PRODUCERS - Deep Basin Vt Wells Average Per Well Production

0

500

1,000

1,500

2,000

2,500


Pro

du

cti

on

Ra

te (

Mc

fe/d

)


ALL HZ PRODUCERS - Deep Basin Hz Wells Average Per Well Production

0

1,000

2,000

3,000

4,000

5,000


Pro

du

cti

on

Ra

te (

Mc

fe/d

)

2008 (146 Wells) 2009 (122 Wells)

2010 (277 Wells) 2011 (459 Wells)

2012 (134 Wells)

Deep Basin Hz Wells - Type Curves

0

2,000

4,000

6,000

8,000

10,000

12,000


Pro

du

cti

on

Rat

e (

Mc

fe/d

)

High Case: 8,000 Mcfe/d IP, 6 Bcf recovery

Mid Case: 4,000 Mcfe/d IP, 4 Bcf recovery

Low Case: 2,000 Mcfe/d IP, 2 Bcf recovery

Deep Basin Vt Wells - Type Curves

0

1,000

2,000

3,000

4,000

5,000


Pro

du

cti

on

Ra

te (

Mc

fe/d

)


Mid Case: 1,500 Mcfe/d IP, 1.5 Bcf recovery


# o f Wells

Reported Multi-Formation Date On Mths % Zone Hz/Vt

Rank Operator Strike Area @ TD UWI (Well Location) Stream On Peak I.P. Current Liquids Msrd. Vt. Prod? Well1 Transcda Edson Kvik_Ss 06-20-054-19W5 2011/01 16 38,585 39,140 9% 3,567 2,466 HZ2 Lone Chinook Ridge Kfalher;Kcadom 14-36-063-13W6 2009/04 37 19,773 4,605 N/A 3,701 3,543 Y3 Devon Narraway Kdunvegan;Kca 07-04-063-11W6 2008/04 49 19,604 6,155 N/A 3,335 3,299 Y4 Devon Wapiti Kfalher 10-14-065-09W6 2009/02 39 18,609 1,346 N/A 3,393 3,393 Y5 EnCana Kakwa Kcard_Ss 11-08-062-06W6 2012/01 4 15,129 10,066 N/A 3,590 3,4096 Transcda Edson Kvik_Ss 12-08-054-19W5 2011/02 15 14,569 8,135 9% 3,114 2,5037 Tourmaline Cabin Creek Kcadomin 09-08-055-02W6 2011/08 9 14,027 4,970 N/A 4,001 3,890 Y8 EnCana Kakwa Kfalher 08-27-061-05W6 2010/06 23 13,842 2,130 19% 4,276 3,004 Y HZ9 Peyto Sundance Knotikwn 11-29-054-22W5 2010/10 19 13,740 2,021 20% 4,597 2,716 Y10 EnCana Kakwa Kfalher 11-22-061-05W6 2011/07 10 13,709 4,867 19% 4,652 3,027 Y11 EnCana Deep Basin Kcadomin a-014-A 093-P-08 2008/08 45 13,080 871 N/A 4,597 2,392 HZ12 Harvest Kakwa Kfalher 01-26-061-06W6 2011/04 13 13,050 4,053 N/A 4,337 2,921 HZ13 Shell Chinook Ridge Kcadomin;Jnik 02-28-065-13W6 2008/02 51 12,978 1,911 N/A 3,694 3,588 Y14 EnCana Kakwa Kfalher 15-29-061-05W6 2010/06 23 12,844 3,031 19% 4,666 3,031 Y15 EnCana Kakwa Kfalher 06-33-061-05W6 2010/06 23 12,663 2,439 19% 4,238 3,008 Y16 Husky Lynx Kcadotte 07-28-060-09W6 2008/03 50 12,658 833 1% 3,967 3,004 Y HZ17 Tourmaline Basing Kshftbury;Kma 08-04-050-21W5 2010/04 25 12,493 764 11% 3,707 3,697 Y18 Pace Wapiti Kcadomin 02-31-068-12W6 2010/03 26 12,453 782 N/A 3,521 2,704 Y HZ19 EnCana Resthaven Kfalher 13-26-059-02W6 2010/03 26 12,357 2,619 10% 4,401 3,182 Y HZ20 EnCana Deep Basin Kcadomin b-100-H 093-P-01 2008/05 48 12,270 346 N/A 4,694 2,678 HZ21 Cdn Forest Bigstone Kcadotte 02-11-061-22W5 2009/04 37 12,191 71 9% 2,448 2,44822 EnCana Resthaven Kwilrich 06-24-059-02W6 2011/04 13 11,950 6,537 10% 5,032 3,180 Y23 Bellatrix Ferrier Kmannvl 04-11-044-10W5 2011/03 14 11,907 2,092 N/A 3,848 2,472 Y HZ24 EnCana Kakwa Kfalher 02-27-061-05W6 2010/11 18 11,813 1,757 19% 4,139 3,032 Y HZ25 Sinopec Obed Kcard_Ss;Kma 13-25-053-23W5 2009/04 37 11,791 4,167 9% 3,264 3,236 Y26 Trilogy Kaybob South Kbluesky;Kgeth 05-35-059-20W5 2012/02 3 11,743 7,057 N/A 3,955 2,452 Y27 Paramount Kakwa Kfalher 13-08-064-04W6 2010/10 19 11,640 6,018 N/A 4,050 2,359 Y HZ28 Celtic Kaybob South Kbluesky 01-09-059-18W5 2009/06 35 11,387 629 17% 3,671 2,304 Y HZ29 Apache Deep Basin Kcadomin d-087-J 093-P-01 2010/12 17 11,339 1,443 N/A 4,481 N/A HZ30 Progress Elmworth Kbluesky;Kgeth 04-09-069-07W6 2009/12 29 11,257 2,116 N/A 2,541 2,512 Y

All Producers (4090) - Average 1,935 656 15% 2,867 2,485

Prod. (Mcfe/d) Depth (Meters)Distribution by Peak 30-Day I.P. RateHZ + VT Deep Basin Wells

0

3,000

6,000

9,000

12,000

15,000

200

400

600

800

1000

1200

1400

1600

1800

2000

2200

2400

2600

2800

3000

3200

3400

3600

3800

Well Count

Peak I.P

. R

ate

(B

oe/d

)

2008 (1437 Wells)2009 (700 Wells)2010 (886 Wells)2011 (671 Wells)MedianMean (Average)Top/Bottom Quartile

Distribution Curve

050

100150200250300350400450500

0.0

1.0

2.0

3.0

4.0

(Mcfe/d/d)

Coun

t

Low Mid HighMidcycle1 Well Economics: Curve Curve Curve NPV (B-Tax) (C$,mlns) - $1.1 $3.6 NPV (A-Tax) (C$,mlns) - $0.5 $2.4 IRR (A-tax) (%) - 21% 70% P/I Ratio2 (A-tax) - 0.3x 1.2x Payback Period (yrs) - 3.1 1.8

Low Mid High NPV9 Breakeven ($C/Mcf) - $2.75 $1.85

2012 2013 2014Well Cost (C$,mln): $2MM 1st yr Decline Rate: 37% WTI (US$/bbl) $90.00 $87.50 $85.00Op Costs (incl.trans): $6.00/Boe Liquids Content: 30Bbl/Mmcf FX ($US/$Cdn) $0.99 $0.98 $0.98Discount Rate: 9% Success Rate: 90% Nat Gas (C$/mcf) $2.39 $3.43 $4.08

NPV/well Sensitivity (+/- 20%)

Assumptions


Deep Basin VT Type Curve Economics

$1.0 $0.5 $0.0 $0.5 $1.0

Royalties

Operating Cost

Productivity

Capital Cost

Commodity Prices

(C$,mlns)




Deep Basin HZ Type Curve Economics NPV/well Sensitivity (+/- 20%)

Assumptions

CIBC Base Commodity Price Assumption$2.0 $1.0 $0.0 $1.0 $2.0

Royalties

Operating Cost

Capital Cost

Productivity

Commodity Prices

(C$,mlns)

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216

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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217

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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Duvernay - Area Map (Circa August, 2012) Duvernay - Liquids and Gas Resource Potential .


Duvernay - Area Production Growth

Note: Map updated as of June 2012. Source: GeoScout; Company reports; Geological Atlas of Western Canada; The Edge; Canadian Discovery Digest; CIBC World Markets Inc. Source: GeoScout; CIBC World Markets Inc.

Duvernay - Economics


Duvernay - Schematic Cross Section Duvernay Play - Land Position by Operator


Notes 1) 1 section = 640 acres; 2) Denotes private company. Land positions are approximations based on company disclosure and public data, and do not adjust for prospectivity. (3) Due to licensing data we believe Shell has acquired 42.6 sections from PetroBakken; however, we believe Shell likely has much more land. Source: Company reports; GeoScout; CIBC World Markets Inc.

Duvernay Hz Wells - Type Curves

0

2,000

4,000

6,000

8,000

10,000

12,000


Pro

du

cti

on

Ra

te (

Mcf

e/d

)

High Case: 10,000 Mcfe/d IP, 8 Bcfe recovery

Mid Case: 7,500 Mcfe/d IP, 7 Bcfe recovery

Low Case: 4,500 Mcfe/d IP, 5 Bcfe recovery

We note that our Duvernay well economics are very sensitive to liquids content. If we increase our assumption for liquids to 250 Bbl/mmcf (from 175 Bbl/mmcf currently) the breakeven gas price drops to $1.65/mcf, and the play's profitability index (P/I ratio) increases to 1.27x.

250

256569

164200218239250250

300

500

15 50

100

200

300

400

500

600

Hor

n R

iver

Col

orad

oSh

ale

Mon

tney

Duv

erna

y

Dee

p Ba

sin

CBM

Mnv

l

CBM

HSC

Cor

dova

Doi

g

Utic

a Sh

ale

Car

dium

Gas

Nik

anna

ssin

Not

ikew

in

Gla

ucon

ite

Orig

inal

GIP

(Tcf

)



Duvernay Land Holders

625 623563

400

313

225 195 172 156 156 145 141 125 123 113 86 86 79 79 73 70 59 58 43 43 31 23 18 12

1000

?

0

100

200

300

400

500

600

700

800

900

1,000

Ath

abas

ca

Enc

ana

CN

RL

Tal

ism

an

Bon

avis

ta

Che

vron

Tril

ogy

Sin

opec

Cel

tic

Pen

n W

est

Gui

de

Pet

roba

kken

Con

oco

Phi

llips

TA

QA

Nor

th

Long

view

Ene

rplu

s

Ter

ra

Hus

ky

Del

phi

Son

de

Ang

le

Chi

nook

Birc

hclif

f

Ver

o

Bel

latr

ix

Wes

tfire

Con

nach

er

Cre

w

Yoh

o

Ceq

uenc

e

She

ll (3

)

Net

Sec

tio

ns

(1)


Low Mid High NPV9 Breakeven ($C/Mcf) $3.00 $2.25 $1.90

2012 2013 2014Well Cost (C$,mln): $12MM 1st yr Decline Rate: 70% WTI (US$/bbl) $90.00 $87.50 $85.00Op Costs (incl.trans): $8.50/Boe Liquids Content: 175Bbls/Mmcf FX ($US/$Cdn) $0.9900 $0.9800 $0.9800Discount Rate: 9% Success Rate: 90% Nat Gas (C$/mcf) $2.39 $3.43 $4.08

Duvernay Type Curve Economics NPV/well Sensitivity (+/- 20%)

Assumptions

CIBC Base Commodity Price Assumption$5.0 $3.0 $1.0 $1.0 $3.0 $5.0

Royalties

Operating Cost

Capital Cost

Productivity

Commodity Prices

(C$,mlns)

Duvernay

-

300

600

900

1,200

1,500

1,800

2,100

2,400

Q2/

08Q

3/08

Q4/

08Q

1/09

Q2/

09Q

3/09

Q4/

09Q

1/10

Q2/

10Q

3/10

Q4/

10Q

1/11

Q2/

11Q

3/11

Q4/

11Q

1/12

Q2/

12Q

3/12

Q4/

12Q

1/13

Q2/

13Q

3/13

Q4/

13Q

1/14

Q2/

14Q

3/14

Q4/

14Q

1/15

Q2/

15Q

3/15

Q4/

15

Tota

l Pro

duct

ion

(Mm

cfe/

d)

0

50

100

150

200

250

300

350

400


oe/d)

Pre 2008 2008 2009 2010 20112012 2013 2014 2015 Liquids

Actual Forecast

2%2%5%7%1%4%<1%28%16%<1%<1%

2.5

15.0

20.0

10.0 10.07.5 6.0 5.0 4.3

2.5 4.0

25.0

20.0

15.0 15.0

0

5

10

15

20

25

Bakk

en(A

lber

ta)

Seal

Duv

erna

y

Car

dium

Tigh

tC

arbo

nate

s

Viki

ng

Bakk

en

(SE

Sask

.)Lo

wer

Shau

navo

n

Peki

sko

Amar

anth

Mon

tney

Oil

Bar

rels

of O

il (B

ln)


Recovered-to-Date

Amaranth

Bakken (US)

Barnett

Du

vern

ay

Gla

uco

nite

Ho

rn R

iver

Montney

VET


219

Duvernay - All Known Well Results to Date: Data Available As Of June 05, 2012; Production Data Current To May 30, 2012 At Update .

Notes: Our “Peak I.P. rate” represents the maximum monthly producing-day rate in a well’s first 8 months of production (note that we exclude months with less than 10 days of production). Current rate is a "calendar day" rate (i.e. last month's cumulative volumes divided by 30.5 days). Mean liquids yield is calculated removing outliers (i.e. the highest value and the lowest value). Source: GeoScout; CIBC World Markets Inc.

Reported Calc'd Reported# Stike Reported Hz/Vt Date Date Rig Date On Mths Oil Cdn Gas Liquids Liquids

Wells Operator Area Well Location Formation Msrd. Vt. Well Spudded Released Stream On (Bbl) (Bbl) (MMcf) (Bbl/MMcf) (Bbl/MMcf)1 Athabasca Kaybob 07-18-064-17W5 Duvernay 4,203 2,780 V Jan-12 Feb-12 Mar-12 3 6,119 10.5 583 325 (oil)2 Celtic Chickdee 05-20-060-17W5 Duvernay 3,027 3,018 V Mar-11 Mar-11 Jun-11 12 18 0.4 453 Celtic (TET/YO) Chickdee 15-33-060-20W5 Duvernay 5,081 3,313 H Jun-10 Aug-10 Apr-11 14 761 292.8 3 75 (cond.)4 Celtic (TET/YO) Kaybobs 13-36-060-20W5 Duvernay 5,158 3,404 V Oct-11 Dec-11 Dec-11 6 2,102 115.3 18 80 (cond.)5 ConocoPhillips Willgr 11-16-044-07W5 Majeaulk 4,559 3,102 H Jul-11 Oct-11 Nov-11 7 1,536 92.1 226 EnCana Saxon 16-05-062-24W5 Duvernay 5,187 3,824 H Nov-11 Dec-11 Mar-12 3 4,026 20.5 196 200 (cond.)7 EnCana Saxon 11-08-062-24W5 Bvrhl_Lk 3,906 3,906 V Nov-10 Dec-10 Aug-11 10 1,632 2.3 710 300 (cond.)8 Shell Kaybob 09-34-062-17W5 Duvernay 2,975 2,975 V Sep-11 Oct-11 Feb-12 4 550 0.3 1,8339 Talisman Fir 01-18-060-20W5 Duvernay 4,673 3,441 H Sep-11 Nov-11 Jan-12 5 63 209.3 0

10 Trilogy (CLT/YO) Kaybobs 03-13-060-20W5 Duvernay 4,867 3,302 H Jan-11 Feb-11 Apr-11 14 45,049 537.8 84 80 (cond.)11 Yoho (CLT) Kaybobs 14-16-062-21W5 Cook_Lk 3,308 V Dec-10 Jan-11 Jul-11 11 745 7.1 10512 Yoho (CLT) Kaybobs 13-22-062-21W5 Duvernay 4,862 3,292 H Nov-11 Dec-11 Jan-12 5 1,098 n.m. 109 (cond.)13 Alta Kaybobs 06-18-062-19W5 Duvernay 3,179 3,179 V Jan-12 Feb-1214 Angle Edson 04-36-052-17W5 Bvrhl_Lk 3,570 3,570 V Jul-11 Aug-1115 Antelope Pembina 10-17-045-06W5 Cook_Lk 3,100 3,100 V Sep-11 Oct-1116 Athabasca Grizzly 01-24-061-23W5 Bvhl_Lkb 3,761 3,720 V Nov-11 Dec-1117 Athabasca Saxon 10-09-062-23W5 Bvhl_Lkb 3,646 3,646 V Oct-10 Nov-1018 Athabasca Grizzly 04-02-062-23W5 Bvhl_Lkb 3,701 V Oct-11 Dec-1119 Athabasca Grizzly 11-10-062-23W5 Duvernay 3,722 H Feb-1220 Bellatrix Ferrier 08-24-044-10W5 Duvernay 4,671 3,456 H Feb-12 Mar-12 ~021 Blaze Brazr 04-04-048-13W5 Nisku 3,471 3,453 V Oct-11 Dec-1122 Bonavista Willgr 16-33-042-06W5 Bvhl_Lkb 3,286 3,286 V Oct-11 Nov-11 7523 Celtic Kaybobs 13-25-059-19W5 Swan_Hl 3,281 3,281 V Aug-10 Sep-1024 Celtic Kaybobs 13-09-060-19W5 Duvernay H Apr-1225 Celtic Kaybobs 15-31-060-19W5 Duvernay H Apr-1226 Celtic Kaybobs 04-11-060-20W5 Duvernay 4,353 3,313 V Jan-12 Mar-1227 Celtic Kaybobs 14-15-061-21W5 Bvhl_Lkb 3,479 3,479 V Jan-11 Feb-1128 Chevron Foxck 06-22-062-18W5 Bvrhl_Lk 3,077 3,077 V Feb-12 Mar-1229 ConocoPhillips Pembina 07-11-045-07W5 Majeaulk 3,077 3,066 V Oct-11 Dec-1130 EnCana Wilsonck 13-17-043-04W5 Bvhl_Lkb 4,237 2,900 V Dec-11 Feb-12 190 (cond.)31 EnCana Willgr 13-05-043-06W5 Bvhl_Lkb 3,921 V Oct-11 Dec-11 120 (cond.)32 EnCana Ferrier 12-04-042-08W5 Bvhl_Lkb H Mar-1233 EnCana 7-17-63-23 06-09-063-23W5 Bvrhl_Lk 5,577 3,457 H Dec-11 Mar-1234 Husky Kaybobs 01-01-060-18W5 Duvernay 4,994 3,020 V Feb-1235 Husky Kaybobs 05-11-060-18W5 Bvrhl_Lk 3,128 3,128 V Aug-11 Aug-1136 Husky Kaybobs 08-25-060-18W5 Duvernay 3,147 3,147 V Mar-11 Apr-1137 Husky Kaybobs 11-25-060-18W5 Duvernay 4,401 3,058 H Oct-11 Nov-1138 Husky Riv 10-33-056-22W5 Swan_Hl 4,131 4,131 V May-10 Aug-1039 Mke Kaybobs 10-32-058-17W5 Nisku 3,101 2,955 V Dec-10 Jan-1140 Shell Kaybob 03-21-063-18W5 Duvernay 4,221 2,868 V Nov-11 Dec-1141 Shell Kaybobs 15-09-063-20W5 Duvernay H Apr-1242 Shell Kaybob 02-22-063-20W5 Duvernay 4,760 V Dec-1143 Talisman Ck 04-09-057-18W5 Duvernay 4,861 3,563 V Nov-11 Jan-12

44 Talisman Kaybobs 12-26-059-20W5 Duvernay V Feb-1245 Talisman Cecilia 12-12-057-22W5 Bvrhl_Lk 4,018 V Mar-00 Aug-0946 Taqa Foxck 14-10-061-18W5 Bvhl_Lkb 3,133 3,133 V Sep-11 Nov-1147 Trilogy Kaybobs 05-03-060-19W5 Duvernay 5,307 H Mar-12 Apr-1248 Trilogy Kaybob 09-18-064-19W5 Gilwd_B 3,134 3,132 V Mar-11 Apr-1149 Trilogy Ckn 04-03-064-21W5 Duvernay 4,138 H Mar-1250 Trilogy Kaybob 04-08-063-20W5 Rmontney 3,184 3,184 V Nov-11 Dec-1151 Westfire Kaybobs 03-32-061-19W5 Swan_Hl 3,284 3,281 V Aug-11 Sep-1152 Arriva Ferrier 01-06-038-07W5 Cook_Lk V53 Athabasca Grizzly 14-03-062-23W5 Duvernay V54 Athabasca Grizzly 04-12-062-23W5 Bvhl_Lkb V55 Athabasca Kaybob 04-18-064-17W5 Rmontney H56 Blaze Brazr 03-08-047-14W5 Nisku V57 Celtic Kaybobs 03-36-058-18W5 Bvhl_Lkb V58 Charger Pembina 15-25-045-08W5 Duvernay V59 Charger Pembina 12-02-046-08W5 Duvernay V60 Chevron Ck 08-06-056-18W5 Bvrhl_Lk V61 Chevron Kaybobs 01-36-061-22W5 Duvernay V62 EnCana Willgr 10-13-044-07W5 Bvhl_Lkb V63 EnCana Saxon 09-31-061-24W5 Duvernay V64 EnCana Saxon 08-05-062-24W5 Duvernay V65 EnCana Kaybobs 13-15-063-21W5 Duvernay V66 EnCana Wahigan 13-17-063-23W5 Bvhl_Lkb V67 EnCana Cecilia 11-34-057-23W5 Bvhl_Lkb V68 EnCana Saxon 01-16-061-24W5 Bvhl_Lkb V69 Husky Kaybobs 16-13-060-18W5 Duvernay H70 Shell Foxck 01-18-061-17W5 Duvernay V71 Shell Kaybob 11-30-063-19W5 Duvernay H72 Shell Kaybob 01-07-064-19W5 Bvhl_Lkb V73 Talisman Willgr 03-02-038-06W5 Duvernay H74 Talisman Willgr 11-03-041-05W5 Duvernay V75 Trilogy Kaybobs 13-05-060-19W5 Duvernay H76 Westfire Kaybobs 05-32-061-19W5 Swan_Hl V77 Westfire Kaybobs 02-23-062-20W5 Swan_Hl V78 Yoho Ferrier 16-24-038-07W5 Cook_Lk V

Mean Liquids Yield (Bbl/MMcf)1 123

Median Liquids Yield (Bbl/MMcf) 93

Drille

d and

/or

Tes

ted

Wel

lsLo

catio

ns

Cumulative Prod.

Pro

duci

ng W

ells

Depth (M)

Confidential TOTALProducing Drilled/Spud TOTAL Locations Drilled or

Company Ticker Wells Wells Drilled (Licensed) Licensed1 EnCana ECA 2 4 6 7 132 Celtic CLT 6 5 11 1 123 Trilogy TET 3 4 7 1 84 Athabasca ATH 1 4 5 3 85 Shell RDS.A-NYSE 1 3 4 3 76 Husky HSE 5 5 1 67 Yoho YO 5 5 1 68 Talisman TLM 1 3 4 2 69 Chevron CVX-NYSE 1 1 2 3

10 Westfire WFE 1 1 2 311 ConocoPhillips COP-NYSE 1 1 2 212 Blaze PRIVATE 1 1 1 213 Charger CHX 2 214 Alta Enrg Prtnr PRIVATE 1 1 115 Angle NGL 1 1 116 Antelope PRIVATE 1 1 117 Bellatrix BXE 1 1 118 Bonavista BNP 1 1 119 Mke MKE-ASX 1 1 120 Taqa North TAQA-ADX 1 1 121 Arriva PRIVATE 1 1

Total (gross) 12 39 51 27 78

Company Activity Summary

Amaranth

Bakken (US)

Barnett

Du

vern

ay

Gla

uco

nite

Ho

rn R

iver

Montney

VET

Amaranth Bakken (US) Barnett Duvernay

Gla

uco

ni

te H

or

n

Riv

er Montney V

ET


222

Glauconite - Area Map (Circa August, 2012) Glauconite - Resource Potential


Glauconite - Area Production Growth


Glauconite - Horizontal Well Operator Summary (Circa August, 2012)


Glauconite - Cross Section Glauconite - Land Position by Operator

Notes 1) 1 section = 640 acres; 2) Denotes private company. Land positions are approximations based on company disclosure and public data, and do not adjust for prospectivity. Source: Company reports; GeoScout; CIBC World Markets Inc.Source: The Edge; Canadian Discovery Digest; CIBC World Markets Inc.

515

500

300

250 250 239218

200

164

69 65

25

250

0

100

200

300

400

500

600

Hor

n R

iver

Col

orad

o Sh

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Mon

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Duv

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Cor

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Car

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Gas

Nik

anna

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Not

ikew

in

Gla

ucon

ite

Orig

inal

GIP

(Tcf

)



Glauconite Land Holders461

329

267241 219

106 86 82 81 70 61 60 60 56 56 52 47 44 41 40 31 29 29 28 28 26 25

0

100

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Con

ocoP

hillip

s

Angl

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Penn

Wes

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Bona

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Hus

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Dev

on

Apac

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)

Net

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(1)

Total

# Operated # Licensed Op./Lic. Oil & Liquids Nat. Gas Nat. Gas Total Oil & Liquids Nat. Gas Total

Company Ticker Hz Wells Wells Wells (bbl/d) (mcf/d) (%) (mcfe/d) (bbl/d) (mcf/d) (mcfe/d)

Bonavista Enrg Corp BNP 102 14 116 177 69,568 98% 70,629 2 682 692Quatro Rsrcs Inc PRIVATE 23 8 31 178 18,083 94% 19,153 8 786 833Taqa North Ltd TAQA-ASX 9 17 26 59 11,909 97% 12,261 7 1,323 1,362Penn West Petrl Ltd PWT 10 4 14 59 11,819 97% 12,172 6 1,182 1,217Apache Cda Ltd APA-NYSE 12 6 18 5 11,230 100% 11,261 0 936 938Omers Enrg Inc PRIVATE 11 3 14 143 9,007 91% 9,866 13 819 897Cdn Nat Rsrcs Lmtd CNQ 11 0 11 63 9,400 96% 9,777 6 855 889ConocoPhillips Cda Corp COP-NYSE 4 8 12 110 4,504 87% 5,163 27 1,126 1,291Devon Nec Corp DVN-NYSE 1 0 1 0 4,337 100% 4,337 0 4,337 4,337Nordegg Rsrcs Inc PRIVATE 8 0 8 18 3,506 97% 3,612 2 438 451Waldron Enrg Corp WDN 2 0 2 18 3,455 97% 3,562 9 1,727 1,781Ravenwood Enrg Corp PRIVATE 2 3 5 220 1,938 60% 3,256 110 969 1,628Birchill Expl Corp PRIVATE 2 2 4 0 3,123 100% 3,123 0 1,561 1,561Yangarra Rsrcs Corp YAN 6 5 11 110 2,162 77% 2,823 18 360 471Harvest Oprtns Corp PRIVATE 3 3 6 0 2,231 100% 2,231 0 744 744


Glauconite

-

50

100

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200

250

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350

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450

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Q2/

08Q

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Q4/

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1/09

Q2/

09Q

3/09

Q4/

09Q

1/10

Q2/

10Q

3/10

Q4/

10Q

1/11

Q2/

11Q

3/11

Q4/

11Q

1/12

Q2/

12Q

3/12

Q4/

12Q

1/13

Q2/

13Q

3/13

Q4/

13Q

1/14

Q2/

14Q

3/14

Q4/

14Q

1/15

Q2/

15Q

3/15

Q4/

15

Tota

l Pro

duct

ion

(MM

cfe/

d)

0

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20

30

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70

80

90

100

110

120

130

140

Liquids Production (Mboe/d)

Pre 2008 2008 2009 2010 20112012 2013 2014 2015 Liquids

Actual Forecast

Amaranth

Bakken (US)

Barnett

Du

vern

ay

Gla

uco

nit

e

Ho

rn R

iver

Montney

VET


223

Glauconite - Generic Type Curves Glauconite - Type Curve Well Economics (Mid Cycle)

Glauconite - Variance of Results - All Time Glauconite - Variance of Results - 2011 to Present


Glauconite - Distribution By Peak I.P. Rates Glauconite - Top Wells


Glauconite - YOY Actual Results – ALL PRODUCERS


Glauconite - YOY Actual Results – BONAVISTA





Variance to Mean - All TimeHORIZONTAL Glauconite Wells

243 224 180 153 119 93 74 60 43 36 29 28-3,000

-2,000

-1,000

0

1,000

2,000

3,000

4,000

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6,000

3 6 9 12 15 18 21 24 27 30 33 36


Pro

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Rat

e (M

cfe/

d)

Mean (Average)



Distribution by Peak I.P. Rate HORIZONTAL Glauconite Wells

0

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Well Count

Pe

ak I.

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ate

(M

cfe

/d)


2009 (16 Wells)

2010 (65 Wells)

2011 (135 Wells)

Median

Mean (Average)

Top/Bottom Quartile

Variance to Mean - 2011 to PresentHORIZONTAL Glauconite Wells

89 55 18131 122-3,000

-2,000

-1,000

0

1,000

2,000

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5,000

6,000

3 6 9 12 15 18 21 24 27 30 33 36


Pro

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cfe/

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Mean (Average)Top Quartile AverageBottom Quartile Average

Distribution Curve

0

25

50

75

100

125

0 2 3 5 6(Mcfe/d/d)

Cou

nt

Date On Mths %Rank Operator Strike Area Well Location Stream On Peak I.P. Current Liquids Msrd. Vt.

1 ConocoPhillipWillesden Green 16-08-045-09W5 2011/04 11 9,418 3,896 N/A 3,636 2,3002 ConocoPhillipWillesden Green 04-05-045-09W5 2011/02 13 6,439 1,925 N/A 3,557 2,3123 ConocoPhillipWillesden Green 01-05-045-09W5 2011/04 11 6,316 1,530 N/A 3,657 2,2984 Bonavista Willesden Green 01-29-041-05W5 2009/04 35 5,924 495 18% 4,165 2,3245 Bonavista Willesden Green 04-22-041-05W5 2009/08 31 5,921 697 N/A 3,731 2,2236 Exxonmobil Harmattan East 13-32-032-03W5 1996/07 188 5,811 1,371 18% 3,696 2,5367 Bonavista Wilson Creek 13-04-043-04W5 2011/05 10 5,533 2,383 17% 3,400 2,0668 Quatro Wilson Creek 16-10-043-04W5 2010/09 18 5,177 973 17% 3,461 2,0559 CNRL Westerose South14-22-044-02W5 2010/12 15 5,119 1,987 2% 3,264 1,85410 Bonavista Westerose South01-21-044-02W5 2010/09 18 4,896 1,319 2% 3,258 1,83811 Quatro Wilson Creek 02-10-043-04W5 2010/12 15 4,832 1,237 17% 3,410 2,06012 Nuvista Pembina 04-36-045-09W5 2011/04 11 4,682 2,019 N/A 3,871 2,16313 Quatro Wilson Creek 13-20-042-03W5 2010/04 23 4,675 776 16% 3,451 2,06314 Bonavista Willesden Green 01-27-041-05W5 2009/09 30 4,670 522 N/A 3,684 2,19515 CNRL Westerose South04-16-044-02W5 2011/01 14 4,658 1,370 N/A 3,301 1,88816 Quatro Wilson Creek 04-11-043-04W5 2011/06 9 4,635 1,735 17% 3,411 2,09817 Bonavista Wilson Creek 14-15-042-04W5 2008/09 42 4,618 647 17% 3,590 2,06318 Taqa Willesden Green 04-03-041-06W5 2011/12 3 4,571 4,571 N/A 3,772 2,37719 Bonavista Wilson Creek 04-15-042-04W5 2010/02 25 4,558 591 17% 3,519 2,07820 Tournament Wilson Creek 01-28-042-04W5 2010/10 17 4,464 1,132 17% 3,422 2,06521 Bonavista Westerose South11-01-045-03W5 1997/03 180 4,444 117 15% 2,692 1,86122 Bonavista Wilson Creek 16-05-043-04W5 2011/05 10 4,440 1,325 17% 3,555 2,07223 Bonavista Willesden Green 04-35-040-06W5 2011/10 5 4,434 2,011 N/A 3,716 2,36724 Bonavista Willesden Green 01-30-041-05W5 2008/09 42 4,425 456 18% 3,426 2,33125 Bonavista Westerose South04-25-044-03W5 2010/05 22 4,329 839 2% 3,361 1,93026 Bonavista Wilson Creek 13-01-043-04W5 2010/07 20 4,315 783 17% 3,515 2,06227 Quatro Wilson Creek 14-10-043-04W5 2011/10 5 4,200 2,887 17% 3,481 2,07428 Omers Wilson Creek 15-02-043-04W5 2010/07 20 4,199 1,303 17% 3,432 2,06429 Bonavista Wilson Creek 01-31-042-04W5 2010/11 16 4,176 1,020 17% 3,541 2,07830 Waldron Westerose South01-28-044-03W5 2011/11 4 4,150 3,386 2% 3,356 1,88831 Bonavista Gilby 01-21-041-04W5 2011/05 10 4,139 1,280 N/A 3,538 2,12532 Bonavista Wilson Creek 03-18-042-04W5 2011/10 5 4,116 2,365 17% 3,427 2,12733 Penn West Westerose South01-05-044-03W5 2011/08 7 4,071 1,788 2% 3,302 1,91634 Bonavista Gilby 16-05-042-04W5 2009/12 27 4,036 666 N/A 3,575 2,12935 Bonavista Willesden Green 04-17-041-05W5 2011/07 8 4,036 1,045 N/A 3,779 2,32036 Quatro Wilson Creek 02-09-043-04W5 2011/09 6 4,017 2,465 N/A 2,900 2,05637 Bonavista Wilson Creek 13-33-042-03W5 2009/12 27 4,009 396 15% 3,303 2,00238 Bonavista Willesden Green 01-17-041-05W5 2010/09 18 3,978 897 N/A 3,801 2,27939 Bonavista Willesden Green 15-21-041-05W5 2009/10 29 3,971 602 N/A 3,663 2,25740 Bonavista Willesden Green 16-05-041-06W5 2011/10 5 3,943 1,861 N/A 3,862 2,43941 Bonavista Wilson Creek 02-28-042-03W5 2009/12 27 3,922 543 16% 3,660 1,99742 Petrobakken Westpem 03-22-050-13W5 2010/03 24 3,905 429 13% 3,384 2,21443 Quatro Wilson Creek 16-19-042-03W5 2010/11 16 3,900 873 N/A 3,476 2,06644 Scollard Pembina 13-30-046-01W5 2011/02 13 3,832 705 N/A 3,010 1,70945 Penn West Gilby 16-22-042-03W5 2011/07 8 3,815 1,509 N/A 3,471 1,98046 Apache Willesden Green 03-03-042-05W5 2011/01 14 3,748 1,353 18% 3,615 2,21947 Vero Brazeau River 10-10-048-12W5 2009/01 38 3,638 0 N/A 3,143 2,29548 Bonavista Willesden Green 15-33-041-05W5 2009/05 34 3,611 505 18% 3,447 2,22549 Bonavista Westerose South16-17-044-02W5 2010/04 23 3,608 622 2% 3,420 1,93150 Bonavista Willesden Green 04-16-041-05W5 2011/06 9 3,606 1,047 N/A 3,741 2,27851 Bonavista Wilson Creek 13-35-041-04W5 2011/06 9 3,593 1,711 17% 3,481 2,09852 ConocoPhillipBrazeau River 08-03-048-12W5 2011/01 14 3,567 2,236 N/A 3,369 2,30153 Bonavista Willesden Green 05-33-041-05W5 2009/04 35 3,492 548 18% 3,204 2,22854 Bonavista Gilby 13-09-042-04W5 2011/07 8 3,472 1,634 N/A 3,556 2,10355 Bonavista Gilby 04-33-041-04W5 2009/12 27 3,456 552 N/A 3,639 2,12756 Omers Wilson Creek 16-34-042-04W5 2010/09 18 3,446 1,065 17% 3,301 2,07657 Apache Gilby 14-08-042-04W5 2011/01 14 3,436 1,479 N/A 3,531 2,12158 Quatro Gilby 01-24-041-04W5 2010/06 21 3,415 801 N/A 3,418 2,08059 Bonavista Westerose South02-31-044-02W5 2011/06 9 3,370 1,450 2% 3,612 1,86760 ConocoPhillipGilby 01-27-041-04W5 2011/07 8 3,353 2,681 N/A 3,931 2,10561 Penn West Wilson Creek 16-32-042-03W5 2011/12 3 3,346 3,346 N/A 3,547 2,00862 Quatro Gilby 11-33-041-03W5 2010/03 24 3,323 435 N/A 2,794 2,09463 Birchill Strachan 03-24-038-09W5 2011/10 5 3,323 3,256 N/A 3,718 2,39464 Bonavista Wilson Creek 01-33-041-04W5 2011/05 10 3,311 1,161 17% 3,511 2,11865 Exxonmobil Harmattan East 07-06-033-03W5 1995/04 203 3,291 789 18% 3,581 2,54866 Bonavista Willesden Green 16-22-041-05W5 2011/11 4 3,267 2,075 N/A 3,703 2,27767 Birchill Strachan 02-24-038-09W5 2011/09 6 3,260 1,870 N/A 3,849 2,38968 CNRL Westerose South04-26-044-02W5 2011/11 4 3,255 2,731 2% 3,198 1,80569 Yangarra Willesden Green 06-03-041-07W5 2010/05 22 3,246 361 9% 3,268 2,49870 Bonavista Strachan 03-33-037-08W5 2011/08 7 3,228 1,681 N/A 4,316 2,92671 Taqa Wilson Creek 03-30-042-04W5 2011/04 11 3,204 978 17% 3,429 N/A72 Bonavista Wilson Creek 01-33-042-04W5 2010/09 18 3,175 538 17% 3,585 2,06373 Bonavista Willesden Green 04-06-041-05W5 2010/12 15 3,160 812 N/A 3,767 2,38974 Bonavista Willesden Green 14-34-041-05W5 2009/09 30 3,125 472 N/A 3,660 2,21675 Conserve Medicine River 09-11-039-03W5 2004/11 88 3,095 259 14% 2,526 2,052

All Producers (243) - Average 2,465 930 12% 3,428 2,130All Producers (243) - Median 2,266 701 17% 3,461 2,084

Prod. (Mcfe/d) Depth (M)

# of Wells

# of Wells

Glauconite Hz Wells - Type Curves

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0 3 6 9 12 15 18 21 24 27 30


Pro

d. R

ate

(Mcf

e/d

) High Case: 5,000 Mcfe/d IP, 4 Bcf recovery



High liquids content supporting economics of Glauconite play.

ALL PRODUCERS - GLAUCONITE Hz Wells Average Per Well Production

0

1000

2000

3000

4000

5000

6000

7000

8000


Pro

du

ctio

n R

ate

(Mcf

e/d

)

2008 (12 Wells)2009 (15 Wells)2010 (66 Wells)2011 (121 Wells)2012 (5 Wells)

2012 Wells

Recent wells drilled by Conoco at Willesden Green (off the Hoadley Trend) look to be the most productive Glauconite wells to-

BONAVISTA - GLAUCONITE Hz Wells Average Per Well Production

0

1000

2000

3000

4000

5000

6000

7000

8000


Pro

du

ctio

n R

ate

(Mcf

e/d

)


2012 Wells

Low Mid HighMidcycle1 Well Economics Curve Curve Curve NPV (B-Tax) (C$,mlns) - $3.4 $7.2 NPV (A-Tax) (C$,mlns) - $2.2 $5.0 IRR (A-tax) (%) 1% 25% 56% P/I Ratio2 (A-tax) - 0.7x 1.6x Payback Period (yrs) 10.2 3.4 1.8

Low Mid High NPV9 Breakeven ($C/Mcf) $4.75 $2.20 $1.50

2012 2013 2014Well Cost (C$,mln): $3.1MM 1st yr Decline Rate: 65% WTI (US$/bbl) $90.00 $87.50 $85.00Op Costs (incl.trans): $4.50/Boe Liquids Content: 70Bbls/Mmcf FX ($US/$Cdn) $0.99 $0.98 $0.98Discount Rate: 9% Success Rate: 90% Nat Gas (C$/mcf) $2.39 $3.43 $4.08

Glauconite Type Curve Economics NPV/well Sensitivity (+/- 20%)

Assumptions


Royalties

Operating Cost

Capital Cost

Productivity

Commodity Prices

(C$,mlns)

Amaranth

Bakken (US)

Barnett

Du

vern

ay

Gla

uco

nite

Ho

rn R

iver

Montney

VET


224

Horn River & Cordova Embayment - Area Map (Circa August 2012) Horn River/Cordova - Resource Potential


Horn River - Area Production Growth


Horn River - Horizontal Well Operator Summary (Circa August 2012) Horn River - Operational Summary

Note: Quoted production is a gross estimate from public databases which may vary from actual production rates. Source: GeoScout, CIBC World Markets Inc.

Horn River - Cross Section Horn River - Land Position By Operator


250

256569

164200

218239250250

300

500

15 5

0

100

200

300

400

500

600

Hor

n R

iver

Col

orad

o Sh

ale

Mon

tney

Duv

erna

y

Dee

p Ba

sin

CBM

Mnv

l

CBM

HSC

Cor

dova

Doi

g

Utic

a Sh

ale

Car

dium

Gas

Nik

anna

ssin

Not

ikew

in

Gla

ucon

ite

Orig

inal

GIP

(Tcf

)



Horn River Land Holders531

450

313266 245

203156 148 139 141 138 116 113

84

15

0

100

200

300

400

500

600

Exxo

n/Im

peria

l

EnC

ana

Apac

he

Dev

on

EOG

Qui

cksi

lver

Con

ocoP

hillip

s

Sunc

or

CN

RL

Nex

en

Stor

mR

esou

rces

Penn

Wes

t

Peng

row

th

Petro

bakk

en

Cre

w

Net

Sec

tions

(1)

Average Production Per Hz Well

# Operated# Licensed Oil & Liquids Nat. Gas Nat. Gas Total Oil & Liquids Nat. Gas Total

Company Ticker Hz Wells Wells (bbl/d) (mcf/d) (%) (mcfe/d) (bbl/d) (mcf/d) (mcfe/d)

EnCana Corp ECA 23 10 2 114,503 100% 114,515 0 4,978 4,979

Apache Cda Ltd APA-NYSE 12 1 1 34,552 100% 34,556 0 2,879 2,880

Nexen Inc NXY 8 2 0 28,696 100% 28,696 0 3,587 3,587

SMR O&G Ltd PRIVATE 3 1 0 12,528 100% 12,528 0 4,176 4,176

Quicksilver Rsrcs Cda Inc KWK-NYSE 2 - 0 10,392 100% 10,392 0 5,196 5,196

EOG Rsrcs Cda Inc EOG-NYSE 7 6 0 5,301 100% 5,301 0 757 757

Ramshorn Cda Invstmnt Ltd PRIVATE 2 - 0 4,947 100% 4,947 0 2,473 2,473

Devon Nec Corp DVN-NYSE 4 11 0 3,720 100% 3,720 0 930 930

Storm Gas Rsrcs Corp SRX 1 1 0 3,699 100% 3,699 0 3,699 3,699

Petrobank Enrg&Rsrcs PBG 1 - 0 514 100% 514 0 514 514

Gross Operated Hz Well Production

Horn River

-

150

300

450

600

750

900

1,050

1,200

1,350

1,500

Q2/

08Q

3/08

Q4/

08Q

1/09

Q2/

09Q

3/09

Q4/

09Q

1/10

Q2/

10Q

3/10

Q4/

10Q

1/11

Q2/

11Q

3/11

Q4/

11Q

1/12

Q2/

12Q

3/12

Q4/

12Q

1/13

Q2/

13Q

3/13

Q4/

13Q

1/14

Q2/

14Q

3/14

Q4/

14Q

1/15

Q2/

15Q

3/15

Q4/

15

Tota

l Pro

duct

ion

(Mm

cfe/

d)

0

25

50

75

100

125

150

175

200

225

250


oe/d)

Pre 2008 2008 2009 2010 20112012 2013 2014 2015 Liquids

Actual Forecast

Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Ho

rn R

iver

Montney

VET


225

Horn River - Generic Type Curves Horn River - Generic Per Well Economics (Mid Cycle)

Horn River - YOY Actual Results - All Producers Horn River - Variance of Results - All Time


Horn River - Distribution By Peak I.P. Rates Horn River - Top Wells


Horn River - Drilling Costs Horn River - Completion Costs

Source: CIBC World Markets Inc. Source: CIBC World Markets Inc.




Horn River Hz Wells - Type Curves

02,0004,0006,0008,000

10,00012,00014,00016,00018,00020,000


Pro

du

ctio

n R

ate

(Mcf

e/d

) High Case: 17,640 Mcfe/d IP, 17.64 Bcf recovery


Low Case: 7,560 Mcfe/d IP, 7.56 Bcf recovery

Variance to Mean - All ProducersHORIZONTAL Horn River Wells

313131414154 456163 18 162629

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

3 6 9 12 15 18 21 24 27 30 33 36


Pro

du

ctio

n R

ate

(Mc

fe/d

)

Mean (Average)



Distribution by Peak I.P. Rate HORIZONTAL Horn River Gas Wells

0

3,000

6,000

9,000

12,000

15,000

18,000

21,000

24,000

27,000

30,000

5 10 15 20 25 30 35 40 45 50 55 60

Well Count

Pea

k I.

P. R

ate

(M

cfe

/d) 2008 & Earlier (17 Wells)

2009 (13 Wells)

2010 (11 Wells)

2011 (21 Wells)

Median

Mean (Average)

Top/Bottom Quartile

Bottom Quartile

Distribution Curve

05

10152025

0.0

1.5

3.0

4.5

6.0

7.5

9.0

10

.5

(Mcfe/d/d)

Co

un

t

ALL Horn River Hz Wells Average Per Well Production

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000


Pro

d.

Rat

e (M

cfe/

d)


Drilling Costs Per Lateral Meter ($C)

$0

$700

$1,400

$2,100

$2,800

$3,500

2008 2009 2010F

-33%

-18%

Completion Costs Per Frac ($C MM)

$0.0

$0.2

$0.4

$0.6

$0.8

$1.0

$1.2

2008 2009 2010F

-34%

-54%

# of Wells

Date On Mths %Rank Operator Strike Area UWI (Well Location) Stream On Peak I.P. Current Liquids Msrd. Vt.

1 Nexen Horn River d-090-H 094-O-08 2011/10 4 15,076 5,506 0% 4,823 2,6162 EnCana Horn River c-024-D 094-O-09 2011/08 6 15,049 13,124 0% 6,006 2,8253 Nexen Horn River c-089-H 094-O-08 2011/10 4 14,109 3,920 0% 4,606 N/A4 EnCana Horn River c-033-D 094-O-09 2011/09 5 14,063 11,955 0% 6,004 2,8125 EnCana Horn River a-034-D 094-O-09 2011/09 5 13,858 8,854 0% 5,752 2,7596 EnCana Horn River b-050-J 094-O-08 2010/11 15 12,888 4,888 0% 5,228 2,6387 EOG Horn River d-010-K 094-O-15 2008/09 41 12,607 1,483 0% 4,451 3,0738 Quicksilver Horn River b-075-D 094-O-16 2010/11 15 12,346 5,279 0% 4,331 N/A9 EnCana Horn River d-031-K 094-O-08 2010/11 15 12,015 6,885 0% 5,407 2,641

10 Nexen Horn River b-098-H 094-O-08 2012/01 1 11,728 11,720 0% 4,861 2,59811 Apache Horn River c-057-L 094-O-08 2011/06 8 11,678 3,995 0% 5,363 2,69812 EnCana Horn River a-041-K 094-O-08 2010/11 15 11,606 4,917 0% 5,113 2,64613 Quicksilver Horn River b-018-D 094-O-16 2010/10 16 11,547 5,526 0% 4,298 2,76514 EnCana Horn River d-050-J 094-O-08 2010/09 17 11,158 4,800 0% 5,209 2,63615 Apache Horn River a-058-L 094-O-08 2011/06 8 10,921 4,946 0% 5,497 2,70216 SMR Horn River d-056-B 094-O-15 2011/12 2 10,441 10,441 0% 4,417 2,91217 EnCana Horn River a-041-K 094-O-08 2010/11 15 10,255 6,105 0% 5,241 2,65018 Apache Horn River d-048-L 094-O-08 2011/06 8 10,160 4,665 0% 5,641 2,82419 Apache Horn River a-067-L 094-O-08 2011/06 8 9,738 3,328 0% 5,305 N/A20 EnCana Horn River d-032-K 094-O-08 2010/11 15 9,573 6,464 0% 5,206 2,65721 EnCana Horn River a-058-J 094-O-08 2009/07 31 9,196 3,300 0% 4,375 N/A22 Apache Horn River b-066-L 094-O-08 2011/06 8 9,096 3,836 0% 5,226 2,81323 EnCana Horn River c-088-K 094-O-08 2011/04 10 8,999 3,838 0% 4,381 2,71524 Apache Horn River d-066-L 094-O-08 2011/05 9 8,913 5,115 0% 5,391 2,64725 Ramshorn Horn River a-044-B 094-O-15 2009/08 30 8,839 3,905 0% 3,888 2,737

All Producers (62) - Average 8,068 3,580 0% 4,637 2,738

Prod. (Mcfe/d) Depth (Meters)

Well Economics: Low Mid High NPV (B-Tax) (C$,mlns) - $5.3 $13.5 NPV (A-Tax) (C$,mlns) - $2.7 $8.9 IRR (A-tax) (%) - 13% 23% P/I Ratio (A-tax) - 0.2x 0.7x Payback Period (yrs) - 5.9 4.2


2012 2013 2014

Well Cost (C$,mln): $12.6MM 1st yr Decline Rate: 65% WTI (US$/bbl) $90.00 $87.50 $85.00

Op Costs (incl.trans): $5.27/Boe Liquids Content: 0Bbl/Mmcf FX ($US/$Cdn) $0.99 $0.98 $0.98Discount Rate: 9% Success Rate: 90% Nat Gas (C$/mcf) $2.39 $3.43 $4.08

Horn River Hz (18 stage) Well NPV/well Sensitivity (+/- 20%)

Assumptions


Royalties

Operating Cost

Capital Cost

Productivity

Commodity Prices

(C$,mlns)

Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Ho

rn R

iver

Montney

VET


226

Montney - Area Map (Circa August, 2012) Montney - Resource Potential


Montney - Area Production Growth


Montney - Horizontal Well Operator Summary (Circa August, 2012)


Montney - Schematic Cross Section Montney - Land Position by Operator


250

25

6569

164200

218239250250

300

500

15 5

0

100

200

300

400

500

600

Hor

n R

iver

Col

orad

o Sh

ale

Mon

tney

Duv

erna

y

Dee

p Ba

sin

CBM

Mnv

l

CBM

HSC

Cor

dova

Doi

g

Utic

a Sh

ale

Car

dium

Gas

Nik

anna

ssin

Not

ikew

in

Gla

ucon

ite

Orig

inal

GIP

(Tcf

)



Montney Land Holders1281

10831011

841

694 688

303 266 264201 195 195 190 180 152 144 133 80 78 70 67 55

0

200

400

600

800

1,000

1,200

1,400

Prog

ress

EnC

ana

CN

RL

Cel

tic

Gui

de

ARC

Talis

man

Con

ocoP

hillip

s

Birc

hclif

f

Cre

w

Mur

phy

Tour

mal

ine

Sino

pec

Shel

l

NuV

ista

Pain

ted

Pony

Terra

Adva

ntag

e

Para

mou

nt

Ceq

uenc

e

RM

P

Bona

vist

a

Net

Sec

tions

(1)


Company Ticker Hz Wells Wells Wells (bbl/d) (mcf/d) (%) (mcfe/d) (bbl/d) (mcf/d) (mcfe/d)EnCana Corp ECA 286 164 450 583 534,884 99% 538,381 2 1,870 1,882ARC Rsrcs Ltd ARX 117 37 154 317 325,511 99% 327,412 3 2,782 2,798Murphy Oil Comp Ltd MUR-NYSE 154 46 200 0 294,408 100% 294,408 0 1,912 1,912Shell Cda Lmtd RDS-NYSE 143 119 262 13 266,504 100% 266,581 0 1,864 1,864Talisman Enrg Inc TLM 79 149 228 50 152,225 100% 152,527 1 1,927 1,931Advantage O&G Ltd AAV 87 15 102 22 143,256 100% 143,387 0 1,647 1,648Birchcliff Enrg Ltd BIR 75 6 81 185 122,638 99% 123,750 2 1,635 1,650Cdn Nat Rsrcs Lmtd CNQ 60 46 106 73 108,176 100% 108,611 1 1,803 1,810Tourmaline Oil Corp TOU 37 14 51 224 100,182 99% 101,525 6 2,708 2,744Trilogy Rsrc Ltd TET 48 13 61 446 86,879 97% 89,553 9 1,810 1,866Celtic Expl Ltd CLT 81 4 85 399 73,957 97% 76,348 5 913 943Crew Enrg Inc CR 35 24 59 46 43,422 99% 43,696 1 1,241 1,248Huron Enrg Corp PRIVATE 20 13 33 177 30,827 97% 31,890 9 1,541 1,594Taqa North Ltd TAQA 21 9 30 145 28,973 97% 29,840 7 1,380 1,421Paramount Rsrcs Ltd PMT 23 21 44 237 26,347 95% 27,769 10 1,146 1,207Devon Cda Corp #N/A 10 6 16 182 21,980 95% 23,075 18 2,198 2,307Canbriam Enrg Inc PRIVATE 11 24 35 437 20,215 89% 22,835 40 1,838 2,076Guide Exploration GO 60 18 78 392 18,833 89% 21,186 7 314 353Pengrowth Corp PGF 13 7 20 0 17,612 100% 17,612 0 1,355 1,355Progress Enrg Ltd PRQ 3 68 71 74 9,359 95% 9,805 25 3,120 3,268Nuvista Enrg Ltd NVA 11 3 14 38 7,800 97% 8,029 3 709 730ConocoPhillips Cda Oprt #N/A 7 0 7 4 3,583 99% 3,605 1 512 515


Montney Gas

-

720

1,440

2,160

2,880

3,600

4,320

5,040

5,760

6,480

7,200

Q2/

08Q

3/08

Q4/

08Q

1/09

Q2/

09Q

3/09

Q4/

09Q

1/10

Q2/

10Q

3/10

Q4/

10Q

1/11

Q2/

11Q

3/11

Q4/

11Q

1/12

Q2/

12Q

3/12

Q4/

12Q

1/13

Q2/

13Q

3/13

Q4/

13Q

1/14

Q2/

14Q

3/14

Q4/

14Q

1/15

Q2/

15Q

3/15

Q4/

15

Tota

l Pro

duct

ion

(Mm

cfe/

d)

0

120

240

360

480

600

720

840

960

1,080

1,200


oe/d)

Pre 2008 2008 2009 2010 2011

2012 2013 2014 2015 Liquids

Actual Forecast

Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Haynesville

Mo

ntn

ey G

as

VET


227

Montney - Generic Type Curves Montney - DRY Type Curve Well Economics (Mid Cycle)

Montney - Variance of Results - All Time Montney - LIQUIDS RICH Type Curve Well Economics (Mid Cycle)


Montney - Variance of Results - 2010 to Present Montney - Top Wells


Montney - Distribution By Peak I.P. Rates



Notes: Our “Peak I.P. rate” represents the maximum monthly producing-day rate in a well’s first 8 months of production (note that we exclude months with less than 10 days of production). Current rate is a "calendar day" rate (i.e. last month's cumulative volumes divided by 30.5 days). Source: GeoScout; CIBC World Markets Inc.Source: GeoScout; CIBC World Markets Inc.


Montney Hz Wells - Type Curves

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0 3 6 9 12 15 18 21 24 27 30


Pro

du

ctio

n R

ate

(Mcf

e/d

)




Variance to Mean - All TimeHORIZONTAL Montney Wells

1406 1261 1144 1036 926 790 664 559 474 375 2991459-3,000

-2,000

-1,000

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000


Pro

d.

Rat

e (M

cfe/

d)


Variance to Mean - 2011 to PresentHORIZONTAL Montney Wells

573 519 382 271 172 81 0 0-3,000

-2,000

-1,000

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000


Pro

d.

Rat

e (M

cfe

/d)

Mean (Average)



# ofWells

# ofWells

Date On Mths %Rank Operator Strike Area UWI (Well Location) Stream On Peak I.P. Current Liquids Msrd. Vt.

1 Manitok Solomon 12-28-052-01W6 2005/10 76 18,514 1,453 N/A 3,489 2,8132 Talisman Findley 07-24-056-06W6 2007/11 51 18,278 3,421 N/A 4,391 3,5533 EnCana Kelly d-083-G 093-P-01 2010/07 19 14,442 3,441 N/A 4,953 3,4074 Trilogy Kaybob South 14-24-059-20W5 2011/04 10 13,211 1,582 N/A 4,130 2,5675 Trilogy Kaybob South 04-11-060-20W5 2010/04 22 12,490 1,038 N/A 4,018 2,3576 Talisman Northern Montney a-073-I 094-B-01 2010/10 16 12,334 2,023 N/A 4,576 4,5767 Talisman Northern Montney c-005-A 094-B-08 2011/12 2 12,087 5,265 N/A 4,806 N/A8 Talisman Findley 11-25-057-06W6 2008/03 47 11,978 976 N/A 5,121 3,9649 Artek Inga 10-02-088-23W6 2011/04 10 11,960 2,642 10% 3,102 1,774

10 Murphy Heritage b-084-A 093-P-09 2009/09 29 11,949 1,912 N/A 4,201 2,66611 Trilogy Kaybob South 01-19-059-19W5 2011/02 12 11,815 1,570 N/A 4,280 2,54512 Talisman Northern Montney c-065-I 094-B-01 2010/10 16 11,759 2,297 N/A 4,351 N/A13 EnCana Heritage a-001-G 093-P-09 2011/08 6 11,582 8,723 N/A 5,061 2,70214 Trilogy Kaybob South 04-35-059-20W5 2011/02 12 11,505 1,631 N/A 3,939 2,45515 EnCana Kelly d-038-J 093-P-01 2011/12 2 11,407 9,750 N/A 4,983 3,35316 Progress Northern Montney a-056-J 094-B-09 2010/12 14 11,059 3,488 N/A 3,646 2,11117 Shell Heritage 13-31-078-18W6 2011/09 5 10,932 5,725 N/A 4,121 2,45818 EnCana Kelly c-015-J 093-P-01 2011/04 10 10,931 9,357 N/A 5,197 3,40319 Trilogy Kaybob South 15-26-059-20W5 2009/11 27 10,689 493 N/A 4,441 2,53720 Tourmaline Heritage 13-26-080-16W6 2011/12 2 10,675 10,675 N/A 3,673 1,94621 Trilogy Kaybob South 14-23-059-20W5 2010/12 14 10,618 1,256 N/A 4,054 2,58022 Celtic Kaybob South 13-36-058-20W5 2010/09 17 10,606 1,143 N/A 3,841 2,41823 Trilogy Kaybob South 13-24-059-20W5 2009/12 26 10,311 545 N/A 4,141 2,56524 EnCana Heritage a-093-B 093-P-09 2009/05 33 10,310 1,758 N/A 4,513 2,70425 Shell Heritage 12-20-079-18W6 2008/11 39 10,302 1,708 N/A 4,651 N/A26 Trilogy Kaybob South 04-31-059-19W5 2011/01 13 10,280 1,589 N/A 4,176 2,40627 Trilogy Kaybob South 08-01-060-20W5 2011/05 9 10,224 1,660 N/A 4,123 2,41528 Celtic Kaybob South 15-27-060-18W5 2010/03 23 10,170 589 N/A 3,847 2,18929 Trilogy Kaybob South 01-01-060-20W5 2010/04 22 9,943 1,149 N/A 3,969 2,41830 EnCana Heritage 11-28-079-17W6 2010/11 15 9,790 3,729 N/A 4,312 N/A31 Advantage Glacier 14-14-076-13W6 2011/02 12 9,783 1,500 N/A 3,941 2,33032 NAL Fireweed a-085-I 094-A-12 2009/01 37 9,693 1,112 N/A 2,962 1,64233 Murphy Heritage a-032-A 093-P-09 2011/11 3 9,664 6,028 N/A 4,408 N/A34 Murphy Heritage b-077-A 093-P-09 2011/01 13 9,581 3,293 N/A 4,549 2,68535 Crew Heritage 12-33-081-19W6 2010/02 24 9,566 1,113 N/A 3,419 2,03536 Canbriam Northern Montney c-035-H 094-B-08 2011/08 6 9,561 8,132 N/A 3,964 2,21937 Sinopec Elmworth 07-29-068-08W6 2011/05 9 9,510 774 N/A 4,129 2,76338 Trilogy Kaybob South 01-36-059-20W5 2011/03 11 9,460 1,445 N/A 4,076 2,45139 Advantage Glacier 16-18-076-13W6 2009/11 27 9,428 2,003 N/A 4,513 2,47440 Murphy Heritage a-041-A 093-P-09 2011/11 3 9,412 4,341 N/A 4,559 2,66041 Trilogy Kaybob South 01-21-059-19W5 2011/06 8 9,412 1,472 N/A 4,077 2,41142 Talisman Northern Montney a-073-I 094-B-01 2010/10 16 9,389 2,313 N/A 4,351 N/A43 Talisman Northern Montney b-076-F 094-B-08 2011/01 13 9,366 2,833 N/A 4,251 N/A44 Crew Heritage 12-03-082-19W6 2011/04 10 9,356 3,485 N/A 3,586 2,02045 Murphy Heritage c-077-A 093-P-09 2011/04 10 9,329 2,133 N/A 4,487 2,65246 Talisman Northern Montney c-011-K 094-B-09 2011/08 6 9,326 5,828 N/A 4,464 2,30547 Talisman Northern Montney d-004-A 094-B-08 2012/01 1 9,272 9,261 N/A 4,621 2,51048 EnCana Heritage d-005-H 093-P-09 2007/04 58 9,251 762 N/A 4,330 2,44149 Trilogy Kaybob South 14-25-059-20W5 2010/01 25 9,249 1,172 N/A 4,463 2,52750 Shell Heritage 12-17-079-18W6 2011/01 13 9,211 4,667 N/A 4,524 2,36551 EnCana Heritage d-005-H 093-P-09 2010/02 24 9,091 3,268 N/A 4,243 2,45152 Trilogy Kaybob South 16-23-059-20W5 2009/10 28 9,056 1,061 N/A 4,117 2,57453 Trilogy Kaybob South 13-25-059-20W5 2009/11 27 8,992 494 N/A 4,416 2,52154 EnCana Heritage b-023-H 093-P-09 2006/12 62 8,982 1,207 N/A 3,841 3,84255 EnCana Heritage c-005-H 093-P-09 2007/03 59 8,981 1,063 N/A 3,923 2,44656 Shell Heritage 04-20-079-18W6 2010/12 14 8,924 4,714 N/A 4,715 2,32857 Murphy Heritage b-055-B 093-P-09 2011/05 9 8,916 2,800 N/A 4,241 2,83258 Trilogy Kaybob South 04-06-060-19W5 2011/03 11 8,887 1,466 N/A 4,100 2,32759 EnCana Heritage 03-24-079-17W6 2011/08 6 8,884 6,680 N/A 4,616 2,14860 Celtic Kaybob South 12-16-060-19W5 2007/07 55 8,866 257 N/A 3,257 2,293

All Producers (1346) - Average 4,284 1,707 8% 4,000 2,363


Distribution by Peak 30-Day I.P. Rate HORIZONTAL Montney Wells

0

3,000

6,000

9,000

12,000

15,000

50

100

150

200

250

300

350

400

450

500

550

600

650

700

750

800

850

900

950

1000

1050

1100

1150

1200

1250

1300

1350

1400

1450

Well Count

Peak I.P

. R

ate

(M

cfe

/d)


Distribution Curve

0306090

120150180210240270300

0 2 4 6 8 10 12 14 16

(Mcfe/d/d)

Count




Montney (Dry) Type Curve Economics NPV/well Sensitivity (+/- 20%)

Assumptions


Royalties

Operating Cost

Capital Cost

Productivity

Commodity Prices

(C$,mlns)



2012 2013 2014Well Cost (C$,mln): $6.5MM 1st yr Decline Rate: 65% WTI (US$/bbl) $90.00 $87.50 $85.00Op Costs (incl.trans): $8.00/Boe Liquids Content: 75Bbl/Mmcf FX ($US/$Cdn) $0.99 $0.98 $0.98Discount Rate: 9% Success Rate: 90% Nat Gas (C$/mcf) $2.39 $3.43 $4.08

Montney (Liquids Rich) Type Curve Econ. NPV/well Sensitivity (+/- 20%)

Assumptions


Royalties

Operating Cost

Capital Cost

Productivity

Commodity Prices

(C$,mlns)

Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Haynesville

Mo

ntn

ey G

as

VET


228

Montney - Sub-Area Map (Circa August, 2012)

Source: GeoScout; Company reports; Geological Atlas of Western Canada; The Edge; Canadian Discovery Digest; CIBC World Markets Inc.

Pouce CoupeSwan

Dawson

Groundbirch

Northeast Region

Kaybob

Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Haynesville

Mo

ntn

ey G

as

VET


229

Montney - Generic Type Curves Montney - YOY Actual Results – ALL PRODUCERS


Montney - YOY Actual Results – DAWSON Montney - YOY Actual Results – GROUNDBIRCH


Montney - YOY Actual Results – KAYBOB Montney - YOY Actual Results – POUCE COUPE


Montney - YOY Actual Results – SWAN Montney - YOY Actual Results – NORTHEAST REGION


NORTHEAST REGION - Montney Hz Wells Average Per Well Production

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0 3 6 9 12 15 18 21 24


Pro

du

ctio

n R

ate

(Mcf

e/d

)

2009 (12 Wells)2010 (55 Wells)2011 (82 Wells)2012 (28 Wells)

SWAN - Montney Hz Wells Average Per Well Production

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000


Pro

du

ctio

n R

ate

(Mcf

e/d

) 2007 (37 Wells)2008 (44 Wells)2009 (74 Wells)2010 (54 Wells)2011 (71 Wells)2012 (13 Wells)

KAYBOB - Montney Hz Wells Average Per Well Production

0

2,000

4,000

6,000

8,000


Pro

du

ctio

n R

ate

(Mcf

e/d

) 2008 (8 Wells)


DAWSON - Montney Hz Wells Average Per Well Production

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0 3 6 9 12 15 18 21 24


Pro

du

ctio

n R

ate

(Mcf

e/d

)

2007 (9 Wells)2008 (15 Wells)2009 (25 Wells)2010 (67 Wells)2011 (40 Wells)2012 (15 Wells)

Dawson wells have shallower declines (on average) because some operators (including ARC) are choosing to constrain initial production rates.

Lower drilling costs give an advantage to economics at Kaybob, AB.

Recent results at properties such as Town & Kobe have opened up a new prospective Montney fairway in northeast B.C.

Encana is the biggest operator at Swan, BC.

Montney Hz Wells - Type Curves

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0 3 6 9 12 15 18 21 24 27 30


Pro

du

ctio

n R

ate

(Mcf

e/d

)




ALL PRODUCERS - Montney Hz Wells Average Per Well Production

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000


Pro

du

ctio

n R

ate

(Mcf

e/d

)

2008 (115 Wells)

2009 (254 Wells)

2010 (415 Wells)

2011 (456 Wells)

2012 (124 Wells)

GROUNDBIRCH - Montney Hz Wells Average Per Well Production

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0 3 6 9 12 15 18 21 24


Pro

du

ctio

n R

ate

(Mcf

e/d

)

2008 (19 Wells)2009 (47 Wells)2010 (106 Wells)

2011 (115 Wells)2012 (26 Wells)

POUCE COUPE - Montney Hz Wells Average Per Well Production

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0 3 6 9 12 15 18 21 24


Pro

du

ctio

n R

ate

(Mcf

e/d

)

2007 (11 Wells)2008 (20 Wells)2009 (34 Wells)2010 (83 Wells)2011 (79 Wells)2012 (31 Wells)

Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Haynesville

Mo

ntn

ey G

as

VET


230

Montney Oil - Area Map (Circa August, 2012) Montney Oil - Resource Potential


Montney Oil - Area Production Growth


Montney Oil - Horizontal Well Operator Summary (Circa August, 2012)


Montney Oil - Schematic Cross Section Montney Oil - Land Position By Operater

Source: The Edge; Canadian Discovery Digest; CIBC World Markets Inc.

Notes: 1) 1 section = 640 acres; 2) Trilogy Montney Oil land position is a CIBC estimate and includes prospective land outside Trilogy’s first Kaybob pool. 3) Whitecap lands are GROSS and CIBC estimates 4) CIBC estimates. Source: Company reports; geoSCOUT; CIBC World Markets Inc.

Montney Oil Land Holders260

120100

58 45?

38~50~50

050

100150200250300

AR

C

Tril

ogy

(2)

Pac

e

Whi

teca

p(3

)

Bel

lam

ont

(4)

Gui

de (

4)

Bon

avis

ta

RM

P

NA

L

Ne

t S

ec

tio

ns

(1

)


Company Ticker Hz Wells Wells Wells (bbl/d) (boe/d) (mcf/d) (%) (boe/d) (bbl/d) (mcf/d) (boe/d)Trilogy Rsrc Ltd TET 23 27 50 9,455 2,449 14,692 21% 11,904 411 639 518ARC Rsrcs Ltd ARX 31 15 46 2,302 2,529 15,173 52% 4,830 74 489 156Galleon Enrg Inc GO 45 24 69 2,083 1,702 10,209 45% 3,785 46 227 84Cdn Nat Rsrcs Lmtd CNQ 19 17 36 2,049 1,570 9,423 43% 3,619 108 496 190Tourmaline Oil Corp TOU 1 2 3 3,072 0 0 0% 3,072 3,072 0 3,072RMP Enrg Inc RMP 16 17 33 1,852 1,034 6,205 0 2,886 116 388 180NAL Rsrcs Lmtd NAE 18 7 25 1,071 1,495 8,972 58% 2,566 59 498 143Whitecap Rsrcs Inc WCP 11 4 15 969 1,115 6,691 54% 2,084 88 608 189Pace O&G Ltd PCE 71 5 76 1,973 78 465 4% 2,051 28 7 29Barrick Enrg Inc PRIVATE 29 7 36 1,825 179 1,074 9% 2,004 63 37 69Bonavista Enrg Corp BNP 13 3 16 359 721 4,326 67% 1,080 28 333 83Athabasca Oil Sands Corp ATH 7 8 15 278 507 3,042 65% 785 40 435 112Seven Generations Enrg L PRIVATE 2 3 5 390 335 2,009 46% 725 195 1,005 362Devon Cda Corp DVN-NYSE 6 6 12 337 194 1,162 36% 531 56 194 88Deethree Expl Ltd DTX 1 1 2 50 274 1,647 85% 324 50 1,647 324


Montney Oil

-

25

50

75

100

125

150

175

200

Q2/

08Q

3/08

Q4/

08Q

1/09

Q2/

09Q

3/09

Q4/

09Q

1/10

Q2/

10Q

3/10

Q4/

10Q

1/11

Q2/

11Q

3/11

Q4/

11Q

1/12

Q2/

12Q

3/12

Q4/

12Q

1/13

Q2/

13Q

3/13

Q4/

13Q

1/14

Q2/

14Q

3/14

Q4/

14Q

1/15

Q2/

15Q

3/15

Q4/

15

Tota

l Pro

duct

ion

(MB

oe/d

)

0

25

50

75

100

125

150

175

200


oe/d)

Pre 2008 2008 2009 2010 2011

2012 2013 2014 2015 Liquids

Actual Forecast

<1% <1%16%

28%

<1%4% 1% 7% 5% 2% 2%

4.0

2.5

4.3 5.0

6.0

7.5

10.010.0

20.0

15.0

2.5

20.0

25.0

15.0 15.0

0

5

10

15

20

25

Bakk

en(A

lber

ta)

Seal

Duv

erna

y

Car

dium

Tigh

tC

arbo

nate

s

Viki

ng

Bakk

en

(SE

Sask

.)Lo

wer

Shau

navo

n

Peki

sko

Amar

anth

Mon

tney

Oil

Bar

rels

of O

il (B

ln)


Recovered-to-Date

Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Haynesville

Marcellus

Mo

ntn

ey O

il


231

Montney Oil - Generic Type Curves Montney Oil - BASE Type Curve Well Economics (Mid Cycle)

Montney Oil - Distribution By Peak I.P. Rates - Since 2007 Montney Oil - KAYBOB Type Curve Well Economics (Mid Cycle)


Montney Oil - Variance of Results - Since 2007 Montney Oil - Variance of Results - 2011 to Present


Montney Oil - YOY Actual Results – ALL PRODUCERS Montney Oil - Top Wells - Since 2007


Montney Oil - Actual Results BY AREA Since 2007 Montney Oil - Actual Results BY AREA Since 2007





Variance to Mean - Since 2007HORIZONTAL Montney Oil Wells

168190206235304359385 142 121 113 93 76 70-300

-200

-100

0

100

200

300

400

500

600

700

800

900

1,000

3 6 9 12 15 18 21 24 27 30 33 36


Pro

d.

Ra

te (

Bo

e/d

) Mean (Average)



Variance to Mean - 2011 to PresentHORIZONTAL Montney Oil Wells

152 130 55 31 13-200-100

0100200300400500600700800900

1,000

3 6 9 12 15 18 21 24 27 30 33 36


Pro

d.

Rat

e (

Bo

e/d

) Mean (Average)



Montney Oil HZ Wells - Type Curves

0100200300400500600700800900

1,0001,100

0 3 6 9 12 15 18 21 24 27 30


Pro

du

ctio

n R

ate

(bo

e/d

)




KAYBOB to VALHALLA - Montney Oil Hz Wells Average Per Well Production

0100200300400500600700800900

1000110012001300140015001600


Pro

du

ctio

n R

ate

(bo

e/d

)

Kaybob (8 Wells)

Waskahigan (6 Wells)

Ante Creek (27 Wells)

Valhalla (18 Wells)

With recent wells at Kaybob coming on production at over 2,000 Boe/d we believe there is upside to our type curves.

Distribution by Peak I.P. Rate HORIZONTAL Montney Oil Wells

0

250

500

750

1,000

1,250

1,500

1,750

2,000

2,250

2,500

10

20

30

40

50

60

70

80

90

10

01

10

12

01

30

14

01

50

16

01

70

18

01

90

20

02

10

22

02

30

24

02

50

26

02

70

28

02

90

30

03

10

32

03

30

34

03

50

36

03

70

38

0

Well Count

Pe

ak

I.P

. R

ate

(B

oe

/d)


Distribution Curve

0

50

100

150

0

20

0

40

0

60

0

80

0

(Boe/d)

Cou

nt

ALL Montney Oil Hz Wells Average Per Well Production

0

100

200

300

400

500

600

700

800

900

1000


Pro

d. R

ate

(b

oe/

d) 2008 (52 Wells) 2009 (26 Wells)

2010 (75 Wells) 2011 (137 Wells)2012 (63 Wells)

WORSLEY to GRAND PRAIRIE - Montney Oil Hz Wells Average Per Well Production

0

100

200

300

400

500

600

700

800

900

1000

0 3 6 9 12 15 18 21 24


Pro

du

ctio

n R

ate

(bo

e/d

)

Elmworth-Grand Prairie (8 Wells)

Sturgeon Lake (24 Wells)

Tangent-Girouxville (32 Wells)

Worsley/Dixonville (95 Wells)

# o fWells

# o fWells


1 Trilogy Kaybob 05-17-064-18W5 2011/08 6 2,867 446 15% 3,720 1,8352 Trilogy Kaybob 12-17-064-18W5 2011/08 6 1,957 1,235 7% 3,556 1,8413 Trilogy Kaybob 13-17-064-18W5 2011/09 5 1,727 700 18% 3,586 1,8364 Surge Valhalla 16-07-074-08W6 2011/09 5 1,620 851 50% 3,041 2,0305 Trilogy Kaybob 03-21-064-18W5 2011/02 12 1,608 459 13% 3,121 1,8246 Trilogy Kaybob 04-21-064-18W5 2011/11 3 1,520 940 16% 4,011 1,8247 Surge Valhalla 11-18-074-08W6 2011/07 7 1,502 445 30% 3,097 2,0348 Trilogy Kaybob 05-02-064-18W5 2011/09 5 1,398 870 10% 3,567 1,8439 Trilogy Kaybob 01-08-064-18W5 2012/01 1 1,332 1,332 15% 3,641 1,84610 Trilogy Kaybob 01-11-064-18W5 2011/10 4 1,315 167 7% 3,583 1,83711 Trilogy Kaybob 04-09-064-18W5 2011/11 3 1,284 1,018 12% 3,562 1,83912 Tourmaline Elmworth 06-31-069-09W6 2011/08 6 1,182 3,081 92% 4,375 2,74913 Trilogy Kaybob 02-08-064-18W5 2011/11 3 1,177 1,052 12% 3,546 1,84814 Whitecap Valhalla 11-26-075-09W6 2011/05 9 1,066 386 87% 3,348 2,19815 Surge Valhalla 13-19-074-08W6 2011/05 9 1,036 494 34% 3,119 2,01916 NAL Sturgeon Lake Sou 05-28-069-25W5 2009/12 26 1,033 183 30% 2,852 1,77417 Trilogy Kaybob 04-17-064-18W5 2011/11 3 1,005 494 10% 3,614 1,83718 Trilogy Kaybob 13-02-064-18W5 2011/05 9 997 119 10% 3,502 1,85519 Seven Karr 09-12-064-04W6 2011/07 7 973 551 48% 5,351 2,92920 CNRL Ante Creek North 16-03-067-24W5 2011/12 2 965 934 69% 3,169 1,879



Low Mid HighWell Economics: Curve Curve Curve NPV (B-Tax) (C$,mlns) $6.0 $13.3 $20.0 NPV (A-Tax) (C$,mlns) $3.9 $9.2 $13.9 IRR (A-tax) (%) 60% 368% 11376% P/I Ratio (A-tax) 0.9x 2.0x 3.1x Payback Period (yrs) 1.8 0.6 0.3



KAYBOB Type Curve Economics NPV/well Sensitivity (+/- 20%)


Assumptions

($4.0) ($2.0) $0.0 $2.0 $4.0

Operating Cost

Capital Cost

Royalties

Productivity

CommodityPrices

(C$,mlns)

Low Mid HighWell Economics: Curve Curve Curve NPV (B-Tax) (C$,mlns) $1.2 $4.3 $11.4 NPV (A-Tax) (C$,mlns) $0.4 $2.7 $7.9 IRR (A-tax) (%) 13% 30% 223% P/I Ratio (A-tax) 0.1x 0.6x 1.7x Payback Period (yrs) 4.3 3.2 0.8


2012 2013 2014Well Cost (C$,mln): $4.5MM 1st yr Decline Rate: 65% WTI (US$/bbl) $90.00 $87.50 $85.00Op Costs (incl.trans): $7.00/Boe 2nd yr Decline Rate: 25% F/X (US$/C$) $0.99 $0.98 $0.98Discount Rate: 9% Success Rate: 90% Nat Gas (C$/mcf) $2.39 $3.43 $4.08

BASE Type Curve Economics NPV/well Sensitivity (+/- 20%)


Assumptions

($2.5) ($1.5) ($0.5) $0.5 $1.5 $2.5

Operating Cost

Royalties

Capital Cost

Productivity

Commodity Prices

(C$,mlns)

Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Haynesville

Marcellus

Mo

ntn

ey O

il


232

Montney Oil - Sub-Area Map (Circa August, 2012)


Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Haynesville

Marcellus

Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Haynesville

Marcellus

Mo

ntn

ey O

il


233

Montney Oil - YOY Actual Results – KAYBOB Montney Oil - YOY Actual Results – WASKAHIGAN


Montney Oil - YOY Actual Results – ANTE CREEK Montney Oil - YOY Actual Results – VALHALLA


Montney Oil - YOY Actual Results – ELMWORTH-GRANDE PRAIRIE Montney Oil - YOY Actual Results – STURGEON LAKE


Montney Oil - YOY Actual Results – TANGENT-GIROUXVILLE Montney Oil - YOY Actual Results – WORSLEY/DIXONVILLE


STURGEON LAKE - Montney Oil Hz Wells Average Per Well Production

0

100

200

300

400

500

600

700

800

900

1000


Pro

du

ctio

n R

ate

(bo

e/d

) 2009 (6 Wells) 2010 (8 Wells)

2011 (6 Wells) 2012 (3 Wells)

ELMWORTH-GRANDE PRAIRIE - Montney Oil Hz Wells Average Per Well Production

0

100

200

300

400

500

600

700

800

900

1000


Pro

du

ctio

n R

ate

(bo

e/d

) 2010 (1 Wells) 2011 (2 Wells)

2012 (2 Wells)

VALHALLA - Montney Oil Hz Wells Average Per Well Production

0

100

200

300

400

500

600

700

800

900

1000


Pro

du

ctio

n R

ate

(bo

e/d

)

2009 (2 Wells) 2010 (17 Wells)

2011 (11 Wells) 2012 (5 Wells)

ANTE CREEK - Montney Oil Hz Wells Average Per Well Production

0

100

200

300

400

500

600

700

800

900

1000


Pro

du

ctio

n R

ate

(bo

e/d

)

2009 (7 Wells) 2010 (5 Wells)

2011 (22 Wells) 2012 (13 Wells)

WASKAHIGAN - Montney Oil Hz Wells Average Per Well Production

0

100

200

300

400

500

600

700

800

900

1000


Pro

du

ctio

n R

ate

(bo

e/d

)

2010 (2 Wells) 2011 (15 Wells)

2012 (11 Wells)

KAYBOB - Montney Oil Hz Wells Average Per Well Production

0

200

400

600

800

1000

1200

1400

0 3 6 9 12 15 18 21 24


Pro

du

ctio

n R

ate

(bo

e/d

)

2010 (1 Wells) 2011 (21 Wells)

2012 (16 Wells)

Recent HZ wells drilled by Whitecap at Valhalla may have opened up a new Montney Oil fairway.

We will be watching the Waskahigan area closely to establish repeatability and gain comfort in the stabilization levels of new horizontals.

Wells in the Elmworth/Grand Prairie area are highly productive, but more commonly produce liquids-rich gas rather than oil.

Increased processing capacity for associated gas should debottleneck Montney Oil development at Ante Creek in 2012.

Trilogy’s most recent well at Kaybob tested at close to 4,000 boe/d, and continued to produce at over 2,000 boe/d after over 30 days on production.

TANGENT-GIROUXVILLE - Montney Oil Hz Wells Average Per Well Production

0

100

200

300

400

500

600

700

800

900

1000


Pro

du

ctio

n R

ate

(bo

e/d

)

2010 (11 Wells) 2011 (28 Wells)

2012 (6 Wells)

WORSLEY/DIXONVILLE - Montney Oil Hz Wells Average Per Well Production

0

100

200

300

400

500

600

700

800

900

1000


Pro

du

ctio

n R

ate

(bo

e/d

)

2009 (5 Wells) 2010 (15 Wells)

2011 (10 Wells) 2012 (6 Wells)

Amaranth

Bakken (US)

Barnett

Eagleford

Fayetteville

Haynesville

Marcellus

Mo

ntn

ey O

il


234

Nikanassin - Area Map (Circa August, 2012) Nikanassin - Resource Potential


Nikanassin - Area Production Growth


Nikanassin - Operator Summary - Since 2007 (Circa August, 2012)


Nikanassin - Cross Section Nikanassin - Land Position by Operator

Source: The Edge; Canadian Discovery Digest; CIBC World Markets Inc.1) 1 section = 640 acres; 2) Denotes private company; 3) Denotes CIBC/Geoscout Estimate. Note: Land positions include acreage accessible via farm-in agreements. Source: Company reports; GeoScout; CIBC World Markets Inc.

250

25

6569

164

200218

239250250

300

500

15 5

0

100

200

300

400

500

600

Hor

n R

iver

Col

orad

o Sh

ale

Mon

tney

Duv

erna

y

Dee

p Ba

sin

CBM

Mnv

l

CBM

HSC

Cor

dova

Doi

g

Utic

a Sh

ale

Car

dium

Gas

Nik

anna

ssin

Not

ikew

in

Gla

ucon

ite

Orig

inal

GIP

(Tcf

)



Nikanassin Land Holders1100

800600 600

469 450300 300 250 228 200 148 144 100 70 70 61 60 60 40 36

0

200400

600800

1,0001,200

1,400

Co

no

co(3

)

En

can

a(3

)

CN

RL

(3)

De

von

(3)

Pro

gre

ss

Ap

ach

e(3

)

Birc

hcl

iff

Cel

tic(3

)

To

urm

alin

e(3

)

De

lph

i

Sh

ell(

3)

Pa

ram

ou

nt

Lon

e P

ine

Ta

lism

an

(3)

Hus

ky(3

)

Taq

a(3

)

Ad

van

tag

e(3

)

Pac

e

Om

ers(

2)(

3)

Tril

og

y(3

)

Sun

cor(

3)

Net

Sec

tio

ns

(1)


Company Ticker Wells Wells Wells (bbl/d) (mcf/d) (%) (mcfe/d) (bbl/d) (mcf/d) (boe/d)ConocoPhillips Cda Corp COP-NYSE 126 73 199 0 70,416 100% 70,417 0 559 93Devon Cda Corp DVN-NYSE 23 11 34 0 53,372 100% 53,372 0 2,321 387Talisman Enrg Inc TLM 10 17 27 0 43,065 100% 43,066 0 4,307 718Shell Cda Lmtd RDS-NYSE 29 9 38 1 28,816 100% 28,825 0 994 166Lone Pine Rsrcs Cda Ltd LPR 20 20 40 0 27,311 100% 27,311 0 1,366 228Tourmaline Oil Corp TOU 13 3 16 11 16,732 100% 16,796 1 1,287 215Progress Enrg Ltd PRQ 21 7 28 5 11,247 100% 11,277 0 536 90Apache Cda Ltd APA-NYSE 5 - 5 15 10,374 99% 10,466 3 2,075 349Delphi Enrg Corp DEE 12 12 24 38 5,929 96% 6,158 3 494 86Pace O&G Ltd PCE 8 1 9 0 5,069 100% 5,069 0 634 106EnCana Corp ECA 1 141 142 0 2,711 100% 2,711 0 2,711 452Cdn Nat Rsrcs Lmtd CNQ 6 35 41 2 2,667 100% 2,680 0 445 74Chinook Enrg Inc CKE 3 - 3 0 2,493 100% 2,493 0 831 138Husky Oil Oprtns Ltd HSE 2 1 3 2 2,210 100% 2,221 1 1,105 185EOG Rsrcs Cda Inc EOG-NYSE 3 - 3 2 2,025 100% 2,034 1 675 113Nuvista Enrg Ltd NVA 4 12 16 0 1,620 100% 1,620 0 405 68Artek Expl Ltd RTK 4 5 9 0 1,620 100% 1,620 0 405 67Paramount Rsrcs Ltd PMT 3 5 8 11 1,062 94% 1,128 4 354 63

Average Production Per WellGross Operated Well Production

Nikanassin

-

60

120

180

240

300

360

420

480

540

Q2/

08Q

3/08

Q4/

08Q

1/09

Q2/

09Q

3/09

Q4/

09Q

1/10

Q2/

10Q

3/10

Q4/

10Q

1/11

Q2/

11Q

3/11

Q4/

11Q

1/12

Q2/

12Q

3/12

Q4/

12Q

1/13

Q2/

13Q

3/13

Q4/

13Q

1/14

Q2/

14Q

3/14

Q4/

14Q

1/15

Q2/

15Q

3/15

Q4/

15

Tota

l Pro

duct

ion

(Mm

cfe/

d)0

10

20

30

40

50

60

70

80

90


oe/d)

Pre 2008 2008 2009 2010 20112012 2013 2014 2015 Liquids

Actual Forecast

Nik

an

ass

in

Bakken

Card

ium

C

ard

ium

Gas

Gla

uco

nite

Ho

rn R

iver

Montney

VET


235

Nikanassin - Generic Type Curves - VERTICAL WELLS Nikanassin - Type Curve Well Economics - VERTICAL WELLS (Mid Cycle)

Nikanassin - Generic Type Curves - HORIZONTAL WELLS Nikanassin - Type Curve Well Economics - HORIZONTAL WELLS (Mid Cycle)

Nikanassin - Variance of Results - 2007 to Present - VERTICAL WELLS Nikanassin - Variance of Results - 2007 to Present - HORIZONTAL WELLS


Nikanassin - Distribution By Peak I.P. Rates Nikanassin - Top Wells Since 2007

Nikanassin - YOY Actual Results – VERTICAL WELLS Nikanassin - YOY Actual Results – HORIZONTAL WELLS








ALL Nikanassin Vertical Wells Average Per Well Production

0

2000

4000

6000

8000

10000

0 3 6 9 12 15 18 21 24


Pro

d.

Rat

e (m

cfe/

d)

2008 (83 Wells) 2009 (70 Wells)

2010 (79 Wells) 2011 (45 Wells)

Nikanassin Vertical Wells - Type Curves

0

2,000

4,000

6,000

8,000

10,000


Pro

d. R

ate

(Mcf

e/d

)




ALL Nikanassin Horizontal Wells Average Per Well Production

0

2000

4000

6000

8000

10000


Pro

d. R

ate

(mcf

e/d

)

Pre 2008 (4 Wells) 2008 (3 Wells)2009 (6 Wells) 2010 (17 Wells)2011 (21 Wells)

Nikanassin Horizontal Wells - Type Curves

0

2,000

4,000

6,000

8,000

10,000


Pro

d. R

ate

(Mcf

e/d

)



Low Case: 2,500 Mcfe/d IP, 2.5 Bcf recovery

Distribution by Peak I.P. Rate VT + HZ Nikanassin Wells

0

3000

6000

9000

12000

15000

25 50 75 100 125 150 175 200 225 250 275 300 325 350 375 400 425 450Well Count

Pea

k I.

P.

Rat

e (M

cfe/

d)


2009 (66 Wells)

2010 (137 Wells)

2011 (72 Wells)

Median

Mean (Average)

Top/Bottom Quartile

Variance to Mean - 2007 to PresentHORIZONTAL Nikanassin Wells

45 42 29 25 19 15 13 11 11 9 75151-4,000

-2,000

0

2,000

4,000

6,000

8,000

10,000


Pro

d.

Rat

e (M

cfe/

d)

Mean (Average)



# o f Wells

Distribution Curve

020406080

100120140

0 5 10 15 20

(Mcfe/d)

Cou

nt

Variance to Mean - 2007 to PresentVERTICAL Nikanassin Wells

387 368 341 317 296 258 220 209 201 178 151404 397-6,000

-4,000

-2,000

0

2,000

4,000

6,000

8,000

10,000

3 6 9 12 15 18 21 24 27 30 33 36


Pro

d. R

ate

(Mcf

e/d

) Mean (Average)



# o f Wells

Despite lower productivity, economics for vertical wells challenge horizontals.

Date On Mths % Hz/VtRank Operator Strike Area UWI (Well Location) Stream On Peak I.P. Current Liquids Msrd. Vt. Well

1 Lone Chinook Ridge 14-36-063-13W6 2009/04 33 19,773 5,107 2% 3,701 3,543 V2 Devon Narraway 07-04-063-11W6 2008/04 45 19,604 6,611 9% 3,335 3,299 V3 Shell Chinook Ridge 04-29-065-13W6 2006/06 67 17,115 875 5% 4,676 3,293 H4 Talisman Ojay b-013-A 093-I-09 2010/03 22 13,789 8,203 N/A 3,426 N/A V5 Devon Ojay a-039-A 093-I-09 2008/05 44 13,194 8,838 0% 3,270 3,148 V6 Shell Chinook Ridge 02-28-065-13W6 2008/02 47 12,978 2,025 5% 3,694 3,588 V7 Pace Wapiti 02-31-068-12W6 2010/03 22 12,453 1,097 8% 3,521 2,704 H8 EnCana Resthaven 13-26-059-02W6 2010/03 22 12,357 3,609 10% 4,401 3,182 H9 EnCana Resthaven 06-24-059-02W6 2011/04 9 11,939 8,133 10% 5,032 3,180 V10 Paramount Kakwa 01-36-062-05W6 2010/06 19 10,915 4,198 19% 4,093 2,648 H11 ConocoPhillipHiding Creek c-048-G 093-I-16 2009/01 36 10,237 2,090 N/A 3,561 3,526 V12 Lone Chinook Ridge 12-27-063-13W6 2010/10 15 10,038 1,523 2% 3,943 3,750 V13 Lone Chinook Ridge 14-22-063-13W6 2011/02 11 9,942 2,764 2% 3,516 3,516 V14 Tourmaline Cabin Creek 09-08-055-02W6 2011/08 5 9,861 8,274 N/A 4,001 3,890 V15 ConocoPhillipHiding Creek a-059-G 093-I-16 2008/10 39 9,632 2,205 N/A 3,402 3,360 V16 Lone Chinook Ridge 15-26-063-13W6 2011/01 12 9,476 3,105 N/A 3,528 3,509 V17 EnCana Resthaven 01-03-060-02W6 2010/07 18 9,134 4,836 10% 4,420 3,198 H18 ConocoPhillipHiding Creek c-070-G 093-I-16 2008/03 46 8,764 1,727 N/A 3,554 3,512 V19 Shell Ojay a-055-J 093-I-09 2008/04 45 8,699 1,704 1% 3,494 3,470 V20 Shell Chinook Ridge 13-20-065-13W6 2009/03 34 8,441 1,100 5% 4,641 3,440 H21 Cdn Forest Ojay a-051-G 093-I-09 2010/11 14 8,422 2,550 N/A 3,371 3,368 V22 ConocoPhillipChinook Ridge 03-33-063-13W6 2007/03 58 8,344 635 2% 3,671 3,654 V23 Tourmaline Kakwa 16-13-062-06W6 2010/03 22 8,307 561 19% 3,285 3,285 V24 Shell Chinook Ridge 04-32-064-12W6 2008/11 38 8,281 1,702 5% 4,030 3,439 H25 Shell Ojay b-073-J 093-I-09 2009/03 34 8,241 1,700 1% 3,737 3,673 V

All Producers (455) - Average 2,687 862 10% 3,220 3,020


Low Mid High




Nikanassin VT Type Curve Economics NPV/well Sensitivity (+/- 20%)


($1.00) ($0.50) $0.00 $0.50 $1.00

Operating Cost

Royalties

Capital Cost

Productivity

Commodity Prices

(C$,mlns)

Low Mid High



2012 2013 2014Well Cost (C$,mln): $6.5MM 1st yr Decline Rate: 60% WTI (US$/bbl) $90.00 $87.50 $85.00Op Costs (incl.trans): $6.50/Boe Liquids Content: 14Bbl/Mmcf FX ($US/$Cdn) $0.99 $0.98 $0.98Discount Rate: 9% Success Rate: 90% Nat Gas (C$/mcf) $2.39 $3.43 $4.08

Nikanassin HZ Type Curve Economics NPV/well Sensitivity (+/- 20%)


($3.0) ($2.0) ($1.0) $0.0 $1.0 $2.0 $3.0

Operating Cost

Capital Cost

Royalties

Productivity

Commodity Prices

(C$,mlns)

Nik

an

assin

B

akken

Card

ium

C

ard

ium

Gas

Gla

uco

nite

Ho

rn R

iver

Montney

VET


236

Pekisko - Area Map (Circa August, 2012) Pekisko - Resource Potential


Pekisko - Area Production Growth

Source: GeoScout; Company reports; Geological Atlas of Western Canada; The Edge; Canadian Discovery Digest; CIBC World Markets Inc. Source: GeoScout; CIBC World Markets Inc.

Pekisko - Horizontal Well Operator Summary (Circa August, 2012)


Pekisko - Schematic Cross Section Pekisko - Land Position By Operator

Source: The Edge; Canadian Discovery Digest; CIBC World Markets Inc.1) 1 section = 640 acres; 2) Denotes private company; 3) Denotes CIBC/Geoscout Estimate. Note: Land positions include acreage accessible via farm-in agreements. Source: Company reports; GeoScout; CIBC World Markets Inc.

Pekisko Land Holders

200142 121 111 100 100 92 90

50 30

144 125

442

050

100150200250300350400450500

Cre

w

Con

ocoP

hilip

s(3)

Pen

grow

th(3

)

Se

cond

Wav

e

TA

QA

(3)

NA

L(3)

Pac

e

CN

RL

(3)

Hus

ky(3

)

Bon

avis

ta

EO

G(3

)

Cen

ovus

(3)

Tw

in B

utte

Net

Sec

tio

ns

(1)


Company Ticker Hz Wells Wells Wells (bbl/d) (boe/d) (mcf/d) (%) (boe/d) (bbl/d) (mcf/d) (boe/d)Crew Enrg Inc CR 109 29 138 4,204 1,612 9,669 28% 5,816 39 89 53Cenovus Enrg Inc CVE 13 2 15 1,001 176 1,053 15% 1,177 77 81 91Bonavista Enrg Corp BNP 2 - 2 77 669 4,014 90% 746 38 2,007 373Second Wave Petrl Ltd SCS 22 1 23 340 344 2,067 50% 685 15 94 31Husky Oil Oprtns Ltd HSE 12 1 13 134 227 1,365 63% 362 11 114 30Pace O&G Ltd PCE 12 3 15 252 77 461 23% 329 21 38 27Connacher O&G Lmtd CLL 6 1 7 139 100 601 42% 239 23 100 40NAL Rsrcs Lmtd NAE 3 - 3 124 113 679 48% 237 41 226 79Cdn Abraxas Petrl Corp PRIVATE 5 - 5 144 73 440 34% 218 29 88 44Pengrowth Enrg Corp PGF 2 - 2 135 75 448 36% 210 67 224 105All Points Enrg Ltd PRIVATE 3 10 13 89 55 328 38% 143 30 109 48ISH Enrg Ltd PRIVATE 2 6 8 125 0 0 0% 125 62 0 62Cdn Nat Rsrcs Lmtd CNQ 1 - 1 39 54 322 58% 93 39 322 93


Pekisko

-

5

10

15

20

25

30

35

40

45

50

Q2/

08Q

3/08

Q4/

08Q

1/09

Q2/

09Q

3/09

Q4/

09Q

1/10

Q2/

10Q

3/10

Q4/

10Q

1/11

Q2/

11Q

3/11

Q4/

11Q

1/12

Q2/

12Q

3/12

Q4/

12Q

1/13

Q2/

13Q

3/13

Q4/

13Q

1/14

Q2/

14Q

3/14

Q4/

14Q

1/15

Q2/

15Q

3/15

Q4/

15

Tota

l Pro

duct

ion

(MB

oe/d

)

0

5

10

15

20

25

30

35

40

45

50


oe/d)

Pre 2008 2008 2009 2010 2011

2012 2013 2014 2015 Liquids

Actual Forecast

<1% <1%16%

28%

<1%4% 1% 7% 5% 2% 2%

4.0

2.5

4.3 5.0 6.0

7.5

10.010.0

20.0

15.0

2.5

20.0

25.0

15.0 15.0

0

5

10

15

20

25

Bakk

en(A

lber

ta)

Seal

Duv

erna

y

Car

dium

Tigh

tC

arbo

nate

s

Viki

ng

Bakk

en

(SE

Sask

.)Lo

wer

Shau

navo

n

Peki

sko

Amar

anth

Mon

tney

Oil

Bar

rels

of O

il (B

ln)


Recovered-to-Date

Amaranth

Pekis

ko

Card

ium

Card

ium

G

as

Gla

uco

nite

Ho

rn R

iver

Montney

VET


237

Pekisko - Generic Type Curves Pekisko - Type Curve Well Economics (Mid Cycle)

Pekisko - Variance of Results - All Time Pekisko - Variance of Results - 2011 to Present


Pekisko - Distribution By Peak I.P. Rates Pekisko - YOY Actual Results – ALL PRODUCERS

Pekisko - Actual Results - All Producers By Area Pekisko - Top Wells


Pekisko - Actual Results - PRINCESS






ALL Pekisko Hz Wells Average Per Well Production

0

100

200

300

400

500

600

700


Pro

d. R

ate

(Bo

e/d

)

Sylvan Lake (7 Wells)

Princess (116 Wells)

Judy Creek (20 Wells)

Northern (14 Wells)

To date, the Princess area has shown significantly better productivity than the Judy Creek or Northern areas. "Gassier" Pekisko wells at Sylvan Lake have recently shown promise, however.

Pekisko HZ Wells - Type Curves

0

100

200

300

400

500

0 3 6 9 12 15 18 21 24 27 30


Pro

du

ctio

n R

ate

(bo

e/d

)




Variance to Mean - All TimeHORIZONTAL Pekisko Wells

162534476687113139177188-300

-200

-100

0

100

200

300

400

500

3 6 9 12 15 18 21 24 27 30 33 36


Pro

du

cti

on

Rat

e (B

oe/

d)

Mean (Average)



Distribution by Peak I.P. Rate HORIZONTAL Pekisko Wells

0100200300400500600700800900

1,000

10 20 30 40 50 60 70 80 90 100

110

120

130

140

150

160

170

180

Well Count

Pe

ak I.

P.

Ra

te (

Bo

e/d

) 2008 & Earlier (6 Wells)

2009 (19 Wells)

2010 (65 Wells)

2011 (98 Wells)

Median

Mean (Average)

Top/Bottom Quartile

Distribution Curve

0

20

40

60

80

0

150

300

450

600

(Boe/d)

Co

unt

Variance to Mean - 2011 to PresentHORIZONTAL Pekisko Wells

102 98 59 34 18-300

-200

-100

0

100

200

300

400

500

3 6 9 12 15 18 21 24 27 30 33 36


Pro

du

cti

on

Rat

e (B

oe/

d)

Mean (Average)



PRINCESS - Pekisko Hz Wells Average Per Well Production

0

100

200

300

400

500


Pro

du

ctio

n R

ate

(bo

e/d

)

2008 (3 Wells)

2009 (11 Wells)

2010 (46 Wells)

2011 (46 Wells)In 2011, however, performance at Princess has lagged compared to previous years.

# o fWells

# o fWells


1 Crew Bantry 11-06-018-11W4 2010/12 14 1,028 193 11% 1,580 9932 Crew Princess 10-07-019-11W4 2009/10 28 947 149 15% 1,890 1,0043 Bonavista Prevo 12-07-039-01W5 2010/01 25 945 683 88% 3,199 2,0434 Crew Alderson 12-06-018-11W4 2011/10 4 820 764 8% 1,944 9925 Crew Princess 16-12-019-12W4 2009/11 27 766 132 37% 1,763 1,0166 Crew Bantry 08-02-018-12W4 2010/01 25 634 62 4% 1,959 9977 Crew Bantry 15-01-018-12W4 2010/08 18 561 41 7% 1,529 9898 Crew Princess 01-11-019-11W4 2011/07 7 557 1,589 79% 1,919 9959 Crew Bantry 15-05-017-11W4 2011/03 11 546 68 8% 1,777 98510 Crew Bantry 09-36-017-12W4 2010/12 14 506 195 18% 1,898 99311 Cenovus Countess 13-25-019-15W4 2011/02 12 488 191 11% 1,977 1,00912 Crew Bantry 05-05-017-11W4 2010/10 16 461 90 5% 1,887 98313 Crew Bantry 11-06-018-11W4 2011/08 6 449 78 24% 1,713 1,00514 Crew Bantry 09-01-018-12W4 2009/09 29 444 89 5% 1,609 98815 Crew Alderson 01-32-017-11W4 2010/10 16 442 35 4% 1,796 99416 Crew Bantry 08-08-017-11W4 2008/10 40 426 33 5% 2,198 98217 Crew Bantry 07-18-017-11W4 2010/08 18 411 12 2% 2,026 98118 Husky Bantry 01-03-019-14W4 2009/09 29 409 45 15% 1,707 1,02519 Crew Alderson 02-01-018-12W4 2011/11 3 384 384 13% 1,823 99320 Crew Princess 15-12-019-11W4 2011/11 3 378 11,339 21% 1,621 1,00021 Crew Princess 06-05-019-11W4 2010/12 14 377 34 27% 1,795 1,00722 Crew Princess 12-06-019-11W4 2010/11 15 374 96 38% 2,289 1,00223 Crew Princess 04-36-018-11W4 2011/02 12 374 17 8% 1,253 98924 Husky Bantry 15-03-019-14W4 2010/03 23 368 15 25% 1,415 1,02325 Crew Princess 12-02-019-11W4 2011/08 6 366 128 84% 1,869 1,00326 Crew Alderson 11-30-017-11W4 2010/02 24 347 56 11% 1,934 98627 Crew Princess 09-15-019-12W4 2010/05 21 331 26 23% 2,063 1,02628 All Hussar 08-31-026-21W4 2011/03 11 308 118 30% 2,724 1,48629 NAL Sylvan Lake 07-08-037-03W5 2010/10 16 308 138 58% 3,227 2,34630 Hemisphere Jenner 10-14-021-09W4 2010/11 15 294 106 9% 2,002 98131 Crew Bantry 15-06-017-11W4 2010/11 15 290 12 8% 1,966 99432 Crew Alderson 02-32-017-11W4 2009/08 30 288 4 4% 1,814 1,00333 Crew Bantry 15-02-018-12W4 2011/10 4 284 54 24% 2,098 99534 Crew Princess 12-31-018-10W4 2010/11 15 275 67 19% 1,980 98435 Crew Princess 07-11-019-11W4 2011/11 3 273 5,399 52% 1,604 99736 Crew Alderson 06-33-016-11W4 2010/10 16 258 19 3% 2,034 99637 Crew Princess 03-36-018-11W4 2011/11 3 254 118 34% 1,680 98138 Husky Bantry 08-03-019-14W4 2011/02 12 250 42 39% 1,559 1,02539 Crew Princess 16-34-018-11W4 2011/03 11 246 70 51% 2,093 1,00140 Crew Princess 01-14-019-11W4 2010/08 18 245 34 56% 1,920 1,006






Pekisko Type Curve Economics NPV/well Sensitivity (+/- 20%)

Assumptions


Royalties

Operating Cost

Capital Cost

Productivity

Commodity Prices

(C$,mlns)

ALL Pekisko Hz Wells Average Per Well Production

0

100

200

300

400

500

0 3 6 9 12 15 18 21 24


Pro

du

ctio

n R

ate

(bo

e/d

)


Amaranth

Pekisk

o

Card

ium

Card

ium

G

as

Gla

uco

nite

Ho

rn R

iver

Montney

VET


238

SEAL - Area Map (Circa August, 2012) SEAL - Resource Potential


SEAL - Area Production Growth


SEAL - Horizontal Well Operator Summary (Circa August, 2012)


SEAL - Schematic Cross Section Seal - Land Position by Operator

Source: The Edge; CIBC World Markets Inc.Notes 1) 1 section = 640 acres; 2) Denotes private company. Land positions are approximations based on company disclosure and public data, and do not adjust for prospectivity. * PWT and CIC are joint parnters. Source: Company reports; GeoScout; CIBC World Markets Inc.

Note: Map updated as of May 2012. Source: GeoScout; Company reports; Geological Atlas of Western Canada; The Edge; Canadian Discovery Digest; Hubbard et. Al. (1999); Bluesky Depositional Environments; CIBC World Markets Inc.

Seal Land Holders280263 259 250

212

8260

42 4026 22 20

60

50

100

150

200

250

300

Mur

phy

Bayt

ex

Penn

Wes

t*

Shel

l

CIC

*(2)

Stra

ta

Koch

(2)

CN

RL

TAQ

A

Griz

zly(

2)

Impe

rial

Hus

ky

Chi

nook

Net

Sec

tions

(1)

Total

# Operated # Licensed Op./Lic. Oil & Liquids Nat. Gas Nat. Gas Total Oil & Liquids Nat. Gas Total

Company Ticker Hz Wells Wells Wells (bbl/d) (mcf/d) (%) (boe/d) (bbl/d) (mcf/d) (boe/d)

Baytex Enrg Ltd BTE 126 26 152 18,121 3,236 3% 18,660 144 26 148

Shell Cda Lmtd RDS-NYSE 271 53 324 13,588 18,448 18% 16,663 50 68 61

Murphy Oil Comp Ltd MUR-NYSE 217 39 256 6,848 7,618 16% 8,117 32 35 37

Penn West Petrl Ltd PWT 68 12 80 2,983 3,908 18% 3,634 44 57 53

Husky Oil Oprtns Ltd HSE 30 0 30 1,902 955 8% 2,061 63 32 69

Koch Expl Cda G/P Ltd PRIVATE 3 2 5 107 1 0% 107 36 0 36


Seal

-

10

20

30

40

50

60

70

80

90

100

110

120

130

Q2/

08Q

3/08

Q4/

08Q

1/09

Q2/

09Q

3/09

Q4/

09Q

1/10

Q2/

10Q

3/10

Q4/

10Q

1/11

Q2/

11Q

3/11

Q4/

11Q

1/12

Q2/

12Q

3/12

Q4/

12Q

1/13

Q2/

13Q

3/13

Q4/

13Q

1/14

Q2/

14Q

3/14

Q4/

14Q

1/15

Q2/

15Q

3/15

Q4/

15

Tota

l Pro

duct

ion

(MB

oe/d

)

0

10

20

30

40

50

60

70

80

90

100

110

120

130


oe/d)

Pre 2008 2008 2009 2010 20112012 2013 2014 2015 Liquids

Actual Forecast

<1% <1%16%

28%

<1%4% 1% 7% 5% 2% 2%

4.0

2.5

4.3 5.0 6.0

7.5

10.010.0

20.0

15.0

2.5

20.0

25.0

15.0 15.0

0

5

10

15

20

25

Bakk

en(A

lber

ta)

Seal

Duv

erna

y

Car

dium

Tigh

tC

arbo

nate

s

Viki

ng

Bakk

en

(SE

Sask

.)Lo

wer

Shau

navo

n

Peki

sko

Amar

anth

Mon

tney

Oil

Bar

rels

of O

il (B

ln)


Recovered-to-Date

Amaranth

Bakken (US)

Seal

Card

ium

Gas

Gla

uco

nite

Ho

rn R

iver

Montney

VET


239

SEAL - COLD HZ Production Type Curves SEAL - COLD Production SEAL - Type Curve Well Economics (COLD)

Source: Company Reports; Source: Company reports and CIBC World Markets Inc.

SEAL - THERMAL Cyclic Steam Stimulation (CSS) Production Type Curve SEAL - THERMAL Production SEAL - Type Curve Well Economics (THERMAL)

Source: Company Reports; Source: Company reports and CIBC World Markets Inc.

SEAL - Variance of Results - All Time SEAL - Variance of Results - 2011 to Present


SEAL - Distribution By Peak I.P. Rate (Cold Production) SEAL - Top Wells (Cold Production)

SEAL - YOY Actual Results – ALL PRODUCERS SEAL - YOY Actual Results – BAYTEX



Note: We will be watching actual results to either validate or disprove these type curves, and plan to make adjustments on an on-going basis as dictated by empirical data. Source: GeoScout; Company reports.

Notes: Our “Peak I.P. rate” represents the maximum monthly producing-day rate in a well’s first 8 months of production (note that we exclude months with less than 10 days of production). Current rate is a "calendar day" rate (i.e. last month's cumulative volumes divided by 30.5 days). Source: GeoScout; CIBC World Markets Inc.Source: GeoScout; CIBC World Markets Inc.

Variance to Mean - All TIME COLD HORIZONTAL Bluesky/Gething Wells

702 677 636 612 576 541 526 511 491 470 451 441 423-200

-100

0

100

200

300

400

500


Pro

d. R

ate

(Bo

e/d

)


Distribution by Peak I.P. Rate HORIZONTAL Bluesky/Gething Wells

0

100200

300

400500

600

700

800900

1000

11001200

1300

50 100

150

200

250

300

350

400

450

500

550

600

650

700

Well Count

IP R

ate

(Bo

e/d

)

2008 & Earlier (453 Wells)2009 (51 Wells)2010 (58 Wells)2011 (134 Wells)MedianMean (Average)Top/Bottom Quartile

SEAL HZ Wells (COLD) - Type Curves

0

100

200

300

400

500

0 3 6 9 12 15 18 21 24 27 30


Pro

d. R

ate

(bo

e/d

)




BAYTEX - Primary (Cold) Hz Wells Average Per Well Production

0

50

100

150

200

250

300

350

400

450

500

550

0 3 6 9 12 15 18 21 24


Pro

du

ctio

n R

ate

(bo

e/d

)

2007 ( Wells)

2008 (37 Wells)

2009 (18 Wells)

2010 (24 Wells)

2011 (31 Wells)

Baytex has recently completed 4 multi-lateral cold wells (11-15 legs each) achieving initial rates of 800 to +1,000 Boe/d (challenging even our "high case" economics). The YOY improvement in Baytex's results is largely due to the increased number of HZ legs per well.

Variance to Mean - 2011 to PresentCOLD HORIZONTAL Bluesky/Gething Wells

132141 376789-200

-100

0

100

200

300

400

500

600


Pro

d. R

ate

(Bo

e/d

)

Mean (Average)



# o f Wells

SEAL HZ Wells (Thermal) - Type Curve

0

500

1,000

1,500

2,000

2,500

0 12 24 36 48 60Months on Production

Pro

d. R

ate

(bo

e/d

)




We assume peak production is achieved in the 4th steam cycle (yr 4).

Distribution Curve

0

50

100

150

200

250

300

0

200

400

600(Boe/d)

Cou

nt

2011 Wells

All Producers - Primary (Cold) Hz Wells Average Per Well Production

0

50

100

150

200

250

300

350

400

450

500

550

0 3 6 9 12 15 18 21 24 27 30 33 36


Pro

du

ctio

n R

ate

(bo

e/d

)

2004 ( Wells) 2005 ( Wells)

2006 ( Wells) 2007 ( Wells)

2008 (93 Wells) 2009 (51 Wells)

2010 (58 Wells) 2011 (134 Wells)

# o f Wells


1 Baytex Peace River Area 13-01-084-19W5 2011/05 9 1,060 1,086 1% 2,108 5952 Baytex Peace River Area 01-02-084-19W5 2011/04 10 1,037 781 0% 1,464 5853 Baytex Peace River Area 16-02-084-19W5 2011/02 12 973 510 0% 2,138 5974 Murphy Peace River Area 16-12-084-18W5 2011/10 4 962 306 0% 2,118 6135 Baytex Peace River Area 08-01-084-19W5 2011/05 9 950 1,045 1% 2,066 5966 Baytex Peace River Area 14-02-084-19W5 2011/04 10 862 706 0% 2,137 5857 Baytex Peace River Area 13-02-084-19W5 2011/04 10 803 403 0% 2,091 5878 Baytex Peace River Area 01-09-084-19W5 2011/06 8 699 376 2% 2,264 5739 Penn West Peace River Area 16-05-082-15W5 2011/07 7 696 398 0% 2,233 68410 Baytex Peace River Area 16-16-084-19W5 2011/12 2 675 675 3% 1,088 57411 Baytex Peace River Area 05-19-084-18W5 2010/05 21 669 333 4% 2,284 59312 Baytex Peace River Area 16-16-084-18W5 2010/02 24 662 257 1% 2,373 59913 Baytex Peace River Area 09-03-084-19W5 2009/09 29 633 178 1% 2,433 57614 Baytex Peace River Area 12-18-084-18W5 2010/04 22 630 192 1% 2,412 59615 Baytex Peace River Area 08-15-084-19W5 2011/07 7 624 411 2% 2,042 56916 Baytex Peace River Area 13-30-084-18W5 2011/05 9 621 366 0% 2,186 58217 Baytex Peace River Area 13-30-084-18W5 2011/05 9 611 299 0% 2,293 58518 Baytex Peace River Area 16-22-084-18W5 2010/07 19 602 283 1% 2,430 60519 Baytex Peace River Area 01-03-084-19W5 2009/11 27 595 209 1% 2,468 57920 Baytex Peace River Area 09-09-084-19W5 2011/06 8 580 381 1% 1,115 570





Well Cost (C$,mln): $1.75MM 1st yr Decline Rate: 50%Op Costs (incl.trans): $11.00/Boe 2nd yr Decline Rate: 25%Discount Rate: 9% Success Rate: 90%

SEAL (COLD) Type Curve Economics

Assumptions

Low Mid HighMidcycle1 Well Economics Curve Curve Curve NPV (B-Tax) (C$,mlns) - $23.8 $43.6 NPV (A-Tax) (C$,mlns) - $14.7 $29.6 IRR (A-tax) (%) - 20% 31% P/I Ratio2 (A-tax) - 0.5x 1.0x Payback Period (yrs) - 4.5 3.3


Well Cost (C$,mln): $31MM EUR: 3,900 MBoeOp Costs (incl.trans): $10.00/Bo Peak Rate: 2,200 Boe/dDiscount Rate: 9% Peak Year Rate: 1,700 Boe/d

SEAL Thermal Type Curve Economics

Assumptions

Amaranth

Bakken (US)

Seal

Card

ium

Gas

Gla

uco

nite

Ho

rn R

iver

Montney

VET


240

Lower Shaunavon - Area Map (Circa August, 2012) Lower Shaunavon - Resource Potential


Lower Shaunavon - Area Production Growth


Lower Shaunavon - Horizontal Well Operator Summary (Circa August, 2012)


Lower Shaunavon - Schematic Cross Section Lower Shaunavon - Land Position By Operator

Source: CIBC World Markets Inc.1) 1 section = 640 acres; 2) Denotes private company; 3) Denotes CIBC/Geoscout Estimate. Note: Land positions include acreage accessible via farm-in agreements. Source: Company reports; GeoScout; CIBC World Markets Inc.

<1% <1%16%

28%

<1%4% 1% 7% 5% 2% 2%

4.0

2.5

4.3 5.0

6.07.5

10.010.0

20.0

15.0

2.5

20.0

25.0

15.0 15.0

0

5

10

15

20

25

Bakk

en(A

lber

ta)

Seal

Duv

erna

y

Car

dium

Tigh

tC

arbo

nate

s

Viki

ng

Bakk

en

(SE

Sask

.)Lo

wer

Shau

navo

n

Peki

sko

Amar

anth

Mon

tney

Oil

Bar

rels

of O

il (B

ln)


Recovered-to-Date

Shaunavon Land Holders600

234

125 10054

25 100

100

200

300

400

500

600

700

Cre

scen

tPo

int

Wild

Stre

am

Talis

man

(3)

Hus

ky (3

)

Cen

ovus

Taqa

(3)

Dia

z

Net

Sec

tions

(1)


Company Ticker Hz Wells Wells Wells (bbl/d) (mcf/d) (%) (boe/d) (bbl/d) (mcf/d) (boe/d)Crescent Point Enrg Corp CPG 313 30 343 9,989 2,841 5% 10,463 32 9 33Cenovus Enrg Inc CVE 68 49 117 3,475 778 4% 3,605 51 11 53Wild Stream Expl Inc WSX 59 28 87 2,911 58 0% 2,920 49 1 49Anterra Enrg Inc AE.A 1 - 1 521 0 0% 521 521 0 521Jarrod Oils Ltd PRIVATE 7 - 7 351 0 0% 351 50 0 50Husky Oil Oprtns Ltd HSE 7 5 12 117 42 6% 125 17 6 18Grizzly Rsrcs Ltd PRIVATE 1 - 1 27 2 1% 28 27 2 28ARC Rsrcs Ltd ARX 1 8 9 11 0 0% 11 11 0 11Trafina Enrg Ltd TFA.A 1 - 1 10 0 0% 10 10 0 10Avenex Enrg Corp AVF 1 - 1 7 0 0% 7 7 0 7Novus Enrg Inc NVS 1 - 1 7 2 5% 8 7 2 8Penn West Petrl Ltd PWT 1 - 1 1 0 0% 1 1 0 1


Shaunavon

-

5

10

15

20

25

30

35

40

45

50

55

60

65

70

Q2/

08Q

3/08

Q4/

08Q

1/09

Q2/

09Q

3/09

Q4/

09Q

1/10

Q2/

10Q

3/10

Q4/

10Q

1/11

Q2/

11Q

3/11

Q4/

11Q

1/12

Q2/

12Q

3/12

Q4/

12Q

1/13

Q2/

13Q

3/13

Q4/

13Q

1/14

Q2/

14Q

3/14

Q4/

14Q

1/15

Q2/

15Q

3/15

Q4/

15

Tota

l Pro

duct

ion

(MB

oe/d

)

0

5

10

15

20

25

30

35

40

45

50

55

60

65

70


oe/d)

Pre 2008 2008 2009 2010 20112012 2013 2014 2015 Liquids

Actual Forecast

Amaranth

Bakken (US)

Barnett

Sh

au

navo

n

Gla

uco

nite

Ho

rn R

iver

Montney

VET


241

Lower Shaunavon - Generic Type Curves Lower Shaunavon - Type Curve Well Economics (Mid Cycle)

Lower Shaunavon - Variance of Results - All Time Lower Shaunavon - Variance of Results - 2011 to Present


Lower Shaunavon - Distribution By Peak I.P. Rates Lower Shaunavon - Top Wells

Lower Shaunavon - YOY Actual Results – ALL PRODUCERS


Lower Shaunavon - YOY Actual Results – WATERFLOOD PILOT #1






Variance to Mean - All TimeHORIZONTAL Lower Shaunavon Wells

461 432 345 308 275 239 206 179 147 124 103 93 78-150

-100

-50

0

50

100

150

200

250

300

350


Pro

d.

Rat

e (B

oe/

d)

Mean (Average)



# of Wells

Shaunavon Hz Wells - Type Curves

0

50

100

150

200

250

300

350


Pro

d.

Rat

e (B

oe/

d) High Case: 250 Boe/d IP, 225 MBoe recovery



Distribution by Peak I.P. Rate HORIZONTAL Shaunavon Wells

0

100

200

300

400

500

600

700

25 50 75 100

125

150

175

200

225

250

275

300

325

350

375

400

425

450

Well Count

Pea

k I.

P.

Rat

e (B

oe/

d) 2008 & Earlier (104 Wells)

2009 (71 Wells)2010 (113 Wells)2011 (173 Wells)MedianMean (Average)Top/Bottom Quartile

Variance to Mean - 2011 to PresentHORIZONTAL Lower Shaunavon Wells

173 147 62 30 13-150

-100

-50

0

50

100

150

200

250

300

350


Pro

d.

Rat

e (B

oe/

d)

Mean (Average)



# of Wells

c

ALL PRODUCERS - Shaunavon Hz Wells Average Per Well Production

0

50

100

150

200

250

300

350


Pro

d.

Rat

e (B

oe/

d)

2008 (82 Wells)

2009 (71 Wells)

2010 (113 Wells)

2011 (173 Wells)


0

20

40

60

80

100

2006

-09

2007

-01

2007

-05

2007

-09

2008

-01

2008

-05

2008

-09

2009

-01

2009

-05

2009

-09

2010

-01

2010

-05

2010

-09

2011

-01

2011

-05

Wat

er C

ut

(%)

0

100

200

300

400

500

600

Pro

du

ctio

n (

Bo

e/d

)

Water Cut (%) Production (Boe/d)A 2nd waterflood pilot into the lower Shaunavon has now commenced.

Injection Started

Waterflood Response?

While our Shaunavon type curve looks very similar to the Bakken, Shaunavon economics are slightly less attractive because the play produces medium

Distribution Curve

050

100150200250300

0

160

320

480(Boe/d)

Cou

nt


1 Crescent Point Swift Current Medi11-009-19W3/00 (33 2009/11 27 428 37 0% 2,179 N/A2 Crescent Point Swift Current Medi02-005-20W3/00 (33 2011/08 6 375 194 9% 2,846 N/A3 Crescent Point Swift Current Medi21-008-19W3/00 (33 2011/02 12 373 162 7% 2,863 N/A4 Crescent Point Swift Current Medi16-008-19W3/00 (33 2010/01 25 372 37 1% 2,870 N/A5 Crescent Point Swift Current Medi03-009-19W3/00 (33 2009/07 31 345 4 0% 2,744 N/A6 Crescent Point Swift Current Medi04-005-20W3/00 (33 2011/09 5 342 177 9% 2,585 N/A7 Crescent Point Swift Current Medi02-006-20W3/00 (33 2010/10 16 341 235 1% 2,411 N/A8 Crescent Point Swift Current Medi11-009-19W3/00 (33 2009/11 27 339 17 0% 2,248 N/A9 Crescent Point Swift Current Medi15-009-19W3/00 (33 2007/02 60 328 41 1% 2,468 1,365

10 Crescent Point Swift Current Medi36-003-20W3/00 (33 2008/08 42 324 11 0% 2,949 N/A11 Crescent Point Swift Current Medi30-008-19W3/00 (33 2008/08 42 294 9 9% 2,681 N/A12 Crescent Point Swift Current Medi33-009-19W3/00 (33 2008/10 40 288 18 9% 2,687 N/A13 Crescent Point Swift Current Medi10-009-19W3/00 (33 2007/07 55 287 48 0% 2,067 1,35714 Crescent Point Swift Current Medi06-009-18W3/00 (33 2007/11 51 286 13 0% 2,561 1,37915 Crescent Point Swift Current Medi31-007-19W3/00 (33 2008/03 47 282 11 0% 2,874 N/A16 Crescent Point Swift Current Medi16-009-19W3/00 (33 2007/08 54 279 5 2% 2,613 1,36717 Crescent Point Swift Current Medi09-010-19W3/00 (33 2011/03 11 277 77 10% 2,849 N/A18 Crescent Point Swift Current Medi31-005-20W3/00 (33 2011/08 6 272 167 0% 2,704 N/A19 Crescent Point Swift Current Medi16-009-19W3/00 (33 2011/07 7 266 125 9% 2,740 N/A20 Crescent Point Swift Current Medi11-005-20W3/00 (33 2008/07 43 265 31 0% 2,998 N/A21 Crescent Point Swift Current Medi31-005-20W3/00 (33 2011/02 12 263 127 0% 2,561 N/A22 Crescent Point Swift Current Medi22-009-19W3/00 (33 2010/12 14 257 34 3% 2,596 N/A23 Crescent Point Swift Current Medi04-009-19W3/00 (33 2009/02 36 256 2 0% 2,657 N/A24 Crescent Point Swift Current Medi07-006-19W3/00 (33 2011/10 4 253 172 0% 2,951 N/A25 Crescent Point Swift Current Medi21-004-20W3/00 (33 2011/07 7 250 134 0% 2,567 N/A26 Crescent Point Swift Current Medi09-006-20W3/00 (33 2011/03 11 250 90 0% 2,347 N/A27 Crescent Point Swift Current Medi09-009-19W3/00 (33 2007/09 53 250 27 6% 2,851 1,37228 Crescent Point Swift Current Medi03-008-19W3/00 (33 2011/09 5 248 54 8% 2,546 N/A29 Crescent Point Swift Current Medi13-006-20W3/00 (33 2011/10 4 248 148 0% 2,963 N/A30 Crescent Point Swift Current Medi21-004-20W3/00 (33 2010/12 14 245 130 0% 2,579 N/A31 Crescent Point Swift Current Medi12-009-19W3/00 (33 2007/07 55 243 7 0% 2,687 1,36432 Crescent Point Swift Current Medi05-008-19W3/00 (33 2008/03 47 241 14 0% 2,605 N/A33 Crescent Point Swift Current Medi17-005-20W3/00 (33 2011/10 4 237 190 0% 2,889 N/A34 Crescent Point Swift Current Medi12-005-20W3/00 (33 2008/08 42 236 22 0% 2,932 N/A35 Crescent Point Swift Current Medi19-005-20W3/00 (33 2010/03 23 234 101 1% 2,548 N/A36 Crescent Point Swift Current Medi10-009-19W3/00 (33 2007/11 51 231 3 0% 2,405 1,36437 Crescent Point Swift Current Medi23-009-19W3/00 (33 2007/02 60 226 11 0% 2,527 1,35438 Crescent Point Swift Current Medi05-008-19W3/00 (33 2008/09 41 224 35 0% 2,671 N/A39 Crescent Point Swift Current Medi03-006-20W3/00 (33 2010/07 19 222 19 0% 3,009 1,43940 Crescent Point Swift Current Medi16-009-19W3/00 (33 2007/11 51 222 8 9% 2,676 1,37141 Crescent Point Swift Current Medi30-005-20W3/00 (33 2010/05 21 221 69 2% 2,836 N/A42 Crescent Point Swift Current Medi01-008-19W3/00 (33 2010/06 20 219 42 5% 2,748 N/A43 Crescent Point Swift Current Medi26-003-20W3/00 (33 2011/10 4 217 199 0% 2,913 N/A44 Cenovus Swift Current Medi22-005-20W3/00 (33 2011/01 13 216 159 1% 2,701 N/A45 Crescent Point Swift Current Medi12-006-20W3/00 (33 2011/08 6 214 132 0% 2,950 N/A46 Crescent Point Swift Current Medi10-008-19W3/00 (33 2007/11 51 213 10 1% 2,893 1,38347 Crescent Point Swift Current Medi19-005-20W3/00 (33 2011/09 5 212 188 0% 2,268 N/A48 Crescent Point Swift Current Medi07-006-19W3/00 (33 2011/10 4 211 175 0% 2,419 N/A49 Crescent Point Swift Current Medi18-009-19W3/00 (33 2008/06 44 211 21 9% 2,397 N/A50 Crescent Point Swift Current Medi06-008-18W3/00 (33 2010/08 18 211 20 0% 2,950 N/A51 Crescent Point Swift Current Medi34-007-19W3/00 (33 2008/08 42 210 16 0% 2,701 N/A52 Crescent Point Swift Current Medi22-003-20W3/00 (33 2011/10 4 210 210 0% 2,893 N/A53 Crescent Point Swift Current Medi04-009-19W3/00 (33 2008/08 42 209 17 9% 2,710 N/A54 Crescent Point Swift Current Medi03-009-19W3/00 (33 2011/11 3 209 209 0% 2,667 N/A55 Crescent Point Swift Current Medi06-008-19W3/00 (33 2008/09 41 208 13 0% 2,686 N/A56 Crescent Point Swift Current Medi11-005-20W3/00 (33 2008/11 39 207 26 0% 2,971 N/A57 Crescent Point Swift Current Medi32-004-20W3/00 (33 2010/09 17 206 59 9% 2,955 N/A58 Crescent Point Swift Current Medi21-009-19W3/00 (33 2008/07 43 202 23 1% 2,774 N/A59 Crescent Point Swift Current Medi35-007-19W3/00 (33 2010/02 24 201 52 7% 2,904 N/A60 Crescent Point Swift Current Medi22-003-20W3/00 (33 2009/11 27 200 43 1% 2,871 N/A61 Crescent Point Swift Current Medi32-007-19W3/00 (33 2008/10 40 198 18 0% 2,644 N/A62 Crescent Point Swift Current Medi33-007-19W3/00 (33 2008/11 39 198 8 0% 2,551 N/A63 Crescent Point Swift Current Medi23-009-19W3/00 (33 2010/09 17 198 30 11% 2,530 N/A64 Crescent Point Swift Current Medi34-007-19W3/00 (33 2008/10 40 196 19 0% 2,706 N/A65 Crescent Point Swift Current Medi06-008-19W3/00 (33 2008/09 41 196 67 0% 2,713 N/A66 Crescent Point Swift Current Medi32-007-19W3/00 (33 2008/12 38 196 23 0% 2,651 N/A67 Crescent Point Swift Current Medi13-009-19W3/00 (33 2007/08 54 196 16 3% 2,652 1,36468 Crescent Point Swift Current Medi14-009-19W3/00 (33 2008/01 49 195 29 0% 2,038 1,34869 Crescent Point Swift Current Medi10-006-20W3/00 (33 2010/07 19 194 43 0% 2,896 N/A70 Crescent Point Swift Current Medi34-007-19W3/00 (33 2011/09 5 194 118 4% 2,889 N/A71 Crescent Point Swift Current Medi01-009-19W3/00 (33 2009/05 33 193 3 0% 2,689 N/A72 Crescent Point Swift Current Medi02-008-19W3/00 (33 2008/07 43 191 11 9% 2,626 N/A73 Crescent Point Swift Current Medi35-007-19W3/00 (33 2008/10 40 191 25 0% 2,617 N/A74 Crescent Point Swift Current Medi34-007-19W3/00 (33 2008/06 44 191 9 0% 2,691 N/A75 Crescent Point Swift Current Medi15-009-19W3/00 (33 2007/11 51 190 10 1% 2,574 1,364






Shaunavon Type Curve Economics NPV/well Sensitivity (+/- 20%)

Assumptions


Royalties

Operating Cost

Capital Cost

Productivity

Commodity Prices

(C$,mlns)

Amaranth

Bakken (US)

Barnett

Sh

au

navo

n

Gla

uco

nite

Ho

rn R

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Viking - Area Map (Circa August, 2012) Viking - Resource Potential


Viking - Area Production Growth


Viking - Horizontal Well Operator Summary (Circa August, 2012)


Viking - Schematic Cross Section Viking - Land Position By Operator

Source: The Edge, Canadian Discovery Digest, CIBC World Markets Inc.1) 1 section = 640 acres; 2) Denotes private company; 3) Denotes CIBC/Geoscout estimate Note: Land positions include acreage accessible via farm-in agreements. Source: Company reports; GeoScout; CIBC World Markets Inc.

ALBERTA SASK

Viking Land Holders

248

245

240

220

170

150

150

137

114

110

110

100

98 85 85 75 60 60 60 51 47 45 44 40 31

30 30 27 24

0

100

200

300

400

500

600

700

800

900

Pe

nn W

est

Cut

pick

(2)

Wes

tfire

Bon

avis

ta

Dev

on(3

)

NA

L(3)

Hus

ky(3

)

ISH

Ene

rgy(

2)(3

)

Cre

scen

t P

oint

Wild

Str

eam

Silv

erba

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)

Nov

us

Con

ocoP

hilli

ps(3

)

Ene

rplu

s

Bay

tex

CN

RL(

3)

Com

pass

Imp

eria

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le

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ne(2

)

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gon

Ren

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Ver

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Ka

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y

Pen

grow

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t S

ec

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ns

(1)

1170


Company Ticker Hz Wells Wells Wells (bbl/d) (boe/d) (mcf/d) (%) (boe/d) (bbl/d) (mcf/d) (boe/d)Penn West Petrl Ltd PWT 132 26 158 2,672 661 3,965 20% 3,333 20 30 25Novus Enrg Inc NVS 78 111 189 1,900 837 5,020 31% 2,737 24 64 35Renegade Petrls Ltd RPL 59 54 113 1,739 0 0 0% 1,739 29 0 29Teine Enrg Ltd PRIVATE 51 47 98 855 65 390 7% 920 17 8 18Husky Oil Oprtns Ltd HSE 18 15 33 575 12 74 2% 587 32 4 33Allstar Enrg Lmtd PRIVATE 15 15 30 258 116 697 31% 374 17 46 25Home Quarter Rsrcs Ltd PRIVATE 16 5 21 281 66 395 19% 347 18 25 22Flagstone Enrg Inc PRIVATE 21 21 42 346 0 0 0% 346 16 0 16Polar Star Cdn O&G Inc PRIVATE 24 14 38 266 65 392 20% 332 11 16 14Invicta Enrg Corp VCA 11 7 18 219 110 659 33% 329 20 60 30Harvest Oprtns Corp PRIVATE 13 19 32 227 96 577 30% 323 17 44 25ISH Enrg Ltd PRIVATE 12 30 42 204 66 396 24% 270 17 33 22Devon Cda Corp DVN 14 16 30 250 4 21 1% 253 18 2 18Crescent Point Enrg Corp CPG 25 39 64 214 0 0 0% 214 9 0 9Westfire Enrg Ltd WFE 17 27 44 164 5 27 3% 168 10 2 10


Viking

-

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

160

Q2/

08Q

3/08

Q4/

08Q

1/09

Q2/

09Q

3/09

Q4/

09Q

1/10

Q2/

10Q

3/10

Q4/

10Q

1/11

Q2/

11Q

3/11

Q4/

11Q

1/12

Q2/

12Q

3/12

Q4/

12Q

1/13

Q2/

13Q

3/13

Q4/

13Q

1/14

Q2/

14Q

3/14

Q4/

14Q

1/15

Q2/

15Q

3/15

Q4/

15

Tota

l Pro

duct

ion

(MB

oe/d

)

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

160


oe/d)

Pre 2008 2008 2009 2010 2011 2012

2013 2014 2015 Liquids

Actual Forecast

<1% <1%16%

28%

<1%4% 1% 7% 5% 2% 2%

4.0

2.5

4.3 5.0 6.0

7.5

10.010.0

20.0

15.0

2.5

20.0

25.0

15.0 15.0

0

5

10

15

20

25

Bakk

en(A

lber

ta)

Seal

Duv

erna

y

Car

dium

Tigh

tC

arbo

nate

s

Viki

ng

Bakk

en

(SE

Sask

.)Lo

wer

Shau

navo

n

Peki

sko

Amar

anth

Mon

tney

Oil

Bar

rels

of O

il (B

ln)


Recovered-to-Date

Amaranth

Bakken (US)

Barnett

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Viking - Generic Type Curves Viking - Type Curve Well Economics (Mid Cycle)

Viking - Variance of Results - All Time Viking - Variance of Results - 2011 to Present


Viking - Distribution By Peak I.P. Rates Viking - Top Wells


Viking - YOY Actual Results - All Producers Viking - Actual Results - All Producers By Area





Distribution by Peak 30-Day I.P. Rate HORIZONTAL Viking Wells

0

100

200

300

400

500

600

700

800

50 100

150

200

250

300

350

400

450

500

550

600

650

700

750

800

850

900

950

1000

1050

1100

1150

1200

1250

1300

1350

1400

1450

Well Count

Pea

k I.

P.

Rat

e (B

oe/

d) 2008 (47 Wells)

2009 (37 Wells)2010 (424 Wells)2011 (758 Wells)2012 (211 Wells)MedianMean (Average)Top/Bottom Quartile

Variance to Mean - 2011 to PresentHORIZONTAL Viking Wells

758 747 613 343 169 88-100

-50

0

50

100

150

200

3 6 9 12 15 18 21 24 27 30 33 36


Pro

d.

Rat

e (B

oe/

d)

Mean (Average)



Variance to Mean - All TimeHORIZONTAL Viking Wells

1477 1115 838 655 508 355 217 161 103 60 511308-100

-50

0

50

100

150

200

3 6 9 12 15 18 21 24 27 30 33 36


Pro

d.

Rat

e (B

oe/

d)

Mean (Average)



# of

Wells

# of

Wells

Viking HZ Wells - Type Curves

0

50

100

150

200

0 3 6 9 12 15 18 21 24 27 30


Pro

d.

Rat

e (b

oe/

d)




ALL Viking Hz Wells Average Per Well Production

0

25

50

75

100

125

150

175

200

225

250


Pro

d.

Rat

e (B

oe/

d) 2008 (47 Wells)


ALL PRODUCERS By Area - Viking Hz Wells Average Per Well Production

0

25

50

75

100

125

150

175

200

225

250


Pro

d.

Rat

e (b

oe/

d)

Central Alberta (31 Wells)Provost (227 Wells)Redwater (187 Wells)SW SASK (1005 Wells)

Date On Mths % ConfidentialRank Operator Strike Area UWI (Well Location) Stream On Peak I.P. Current Gas Msrd. Vt. Status?

1 Glencoe Chigwell 10-33-043-26W4 2010/12 17 918 977 83% 2,304 1,4052 Glencoe Chigwell 09-23-042-26W4 2011/03 14 726 526 28% 2,606 1,3803 Glencoe Chigwell 01-13-042-26W4 2012/02 3 724 712 35% 2,951 1,3784 Glencoe Chigwell 07-26-042-26W4 2011/04 13 698 593 74% 2,266 1,3715 Superman Westerose South 04-34-043-03W5 2011/07 10 654 134 13% 3,251 1,7786 Superman Sylvan Lake 01-34-037-01W5 2011/02 15 588 19 15% 3,251 1,7957 Cutpick Halkirk East 14-07-040-13W4 2011/01 16 490 52 12% 2,252 8588 Angle Crossfield 01-20-030-03W5 2010/07 22 475 99 21% 3,555 2,367 Y9 Cutpick Halkirk East 13-09-040-13W4 2011/08 9 438 86 18% 2,360 836

10 NAL Caroline 11-36-035-07W5 2011/05 12 426 15 28% 3,649 2,72211 Angle Harmattan East 08-17-031-02W5 2010/09 20 407 27 75% 3,466 2,17512 Sure Redwater 03-02-058-23W4 2010/11 18 374 67 11% 1,806 73013 Cutpick Halkirk East 12-09-040-13W4 2011/09 8 356 67 34% 2,455 83414 Cutpick Halkirk East 14-14-040-13W4 2010/11 18 350 66 13% 2,059 83115 Cutpick Provost 15-13-039-12W4 2011/10 7 330 132 15% 2,213 82516 Cutpick Halkirk East 08-20-040-14W4 2011/02 15 318 55 17% 2,257 86817 Cutpick Halkirk East 15-07-040-13W4 2011/10 7 313 67 4% 2,216 85418 Cutpick Halkirk East 06-14-040-13W4 2010/09 20 304 30 6% 2,123 83519 Bonterra Willesden Green 12-23-043-09W5 2012/02 3 297 204 46% 3,532 2,04820 Velvet Carrot Creek 01-28-052-14W5 2011/03 14 296 106 48% 3,430 2,08021 Cutpick Halkirk East 16-07-040-13W4 2010/11 18 293 87 1% 2,175 84922 Baccalieu Harmattan East 16-30-031-03W5 2011/10 7 287 209 49% 3,623 2,34523 Angle Crossfield 16-11-029-02W5 2010/12 17 280 77 94% 3,477 2,21324 Cutpick Halkirk East 08-13-040-14W4 2012/03 2 255 255 12% 2,041 85325 Cutpick Provost 16-11-038-12W4 2011/03 14 250 70 18% 2,300 856



Distribution Curve

0200400600800

100012001400

0

150

300(Boe/d)

Cou

ntLow Mid High




Viking Type Curve Economics NPV/well Sensitivity (+/- 20%)

Assumptions

CIBC Base Commodity Price Assumption$0.5 $0.0 $0.5

Royalties

Operating Cost

Capital Cost

Productivity

Commodity Prices

(C$,mlns)

Amaranth

Bakken (US)

Barnett

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Viking - Sub-Area Map (Circa August, 2012)


Amaranth

Bakken (US)

Barnett

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Viking - Generic Type Curves Viking - YOY Actual Results - All Producers


Viking - YOY Actual Results - SW SASK Viking - YOY Actual Results - REDWATER


Viking - YOY Actual Results - CENTRAL ALBERTA Viking - YOY Actual Results - PROVOST, AB


ALL Viking Hz Wells Average Per Well Production

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150


Pro

d.

Rat

e (B

oe/

d) 2008 (47 Wells)


SW SASK - Viking Hz Wells Average Per Well Production

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150


Pro

d.

Rat

e (B

oe/

d)


Lower drilling costs for the Viking in SW Saskatchewan allow economics to remain competitive with other tight oil plays, despite the area's lower productivity.

RED WATER - Viking Hz Wells Average Per Well Production

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150


Pro

d.

Rat

e (B

oe/

d)


While HZ Viking wells at Red Water have been more productive than those in SW Saskatchewan, the resource potential at Redwater is somewhat smaller.

PROVOST AB - Viking Hz Wells Average Per Well Production

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150


Pro

d.

Rat

e (B

oe/

d)

2010 (45 Wells)

2011 (136 Wells)

2012 (46 Wells)

While less known, we consider the Provost pool to be the most interesting emerging Viking sub-area (owing to its ariel extent, the high productivity of its initial wells). Recent activity has begun to test the prospectivity of the southern part of the play.

Viking HZ Wells - Type Curves

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150


Pro

d.

Rat

e (b

oe/

d)




CENTRAL ALBERTA - Viking Hz Wells Average Per Well Production

0

20

40

60

80

100

120

140

160

180

200

220

240

260

280

300


Pro

d.

Rat

e (B

oe/

d)

2010 (14 Wells)2011 (10 Wells)2012 (7 Wells)

Recent wells drilled by Glencoe (private) at Chigwell, and by NAL at Caroline represent the best Viking wells drilled to-date. We will be watching follow up wells in these areas closely to establish repeatability.

Amaranth

Bakken (US)

Barnett

Du

vern

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Oil

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Amaranth Bakken (US) Barnett

Duv

er

nay Viking Oil H

or

n

Riv

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248

Methodology: New Tools For A New Ball Game – “Welcome To The Matrix”

Our price targets are set close to our Risked NAV – which we define as our CORE NAV (2P booked reserves) + a company’s “Risked upside potential.”

Our price targets are set close to our Risked NAV – which we define as our CORE NAV (2P booked reserves) + a company’s “Risked upside potential.”

As plays improve their “scores”in the criteria outlined in our developmental and geological/asset frameworks, the plays become “de-risked”and shift from tier 5 towards tier 1, receiving greater credit in our Risked NAV.

Our de-risking tiers correlate with cascading risking percentages which are applied to drilling inventories on a year-by-year basis. Our risking not only becomes more punitive in the higher risking tiers (where riskier plays are placed) but also is more punitive for wells drilled into the future. The additional “time risking” in each tier is incremental to our 9% discount rate, and is justified by basic assumptions such as the notion that companies drill their best wells first, down-spacing wells are typically less productive, and, empirically, investors are less inclined to pay for wells drilled 5 years from now than for wells expected to be drilled in a year.


Amaranth

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Methodology: Putting The Pieces Together – Our Risked NAV Roll-up NET ASSET VALUE SUMMARY (9% disc. rate; base commodity prices)

RISKED & UNRISKED UPSIDE (Unbooked Prospects)

CORE NAV (Booked Reserves) Unbooked Prospects(4): )%()%()erahs/$C(Proved + Probable Res. Cardium - (AB) $6.26 %42%92

Undeveloped Land(2) Colorado/Viking (AB/SK) $3.15 %51%51

Long Term Debt Amaranth (MB) $3.08 %01%41

Other Assets and Liab. Seal - Cold Prod. (AB) $2.37 %21%11

CORE NAV(3) Seal - Thermal (AB) $2.45 %12%21

Carbonates (AB) $3.30 16% $7.53 16%Cordova Embayment(5) $0.69 3% $0.69 2%

%001%00103.12$EDISPU LATOT

NAV & Price Target SummaryRisked NAV $33.50

)80.1$(sn'tsiD tsaceroF sseL VAN EROC24.23$edispU deksiR

elpitluM tegraT ecirPVAN DEKSIR 0.9x

Unrisked Upside (Incr.) PRICE TARGET(6)$29.00

53.81$ecirP tnerruC VAN "YKSEULB" Forecast Return 64%

Cardium - (AB) Impact of Risking

Assumptions: A-Tax B-Tax RISKNPV/well - Midcycle ($M) 4.1 4.6 timeline Undiscounted Discounted Bluesky RISKED Undiscounted Discounted Bluesky RISKEDRisking Tier (1 to 5) 2 (TIER 2) (wells/yr) (wells/yr) (wells/yr) (wells/yr) NPV/yr ($M) NPV/yr ($M) NPV/yr ($M) NPV/yr ($M)

1 75% 2998 325 115 86 $13,734 $1,366 $483 $363 Relative NPVs Impact

0401snoitceS teN 2 60% 325 168 883$646$352,1$101 ($/share) (%) (%)

%08ytivitcepsorP 3 50% 325 220 983$877$051,1$011 Undiscounted $29.04 ###

Prospective Sections 832 4 40% 325 273 453$488$550,1$901 Discounted $18.69 ### -36%

Wells per Section 4 5 30% 325 325 092$869$869$89 Bluesky $16.25 ### -13%

Booked (or producing) Locations 330 6 30% 325 325 662$888$888$89 Risked $6.26 ### -61%

Max Well Inv. (less booked loc.) 2998 7 30% 325 325 122$637$637$89RISKED Well Inventory 1073 8 30% 325 325 202$576$576$89

Total 2998 2998 2998 1073 $13,734 $8,837 $7,683 $2,960Initial # Wells/yr (company) 115 Undiscounted Discounted Bluesky RISKED

Optimal # Wells per Year 325 (UnRisked) (Risked) $26.18/boe $16.84/boe $14.64/boe $5.64/boeYears to Optimal Pace 5 525 188 $29.04/sh $18.69/sh $16.25/sh $6.26/shOptimal Years to Dev. Inventory 9

Colorado/Viking (AB/SK) Impact of Risking


1 60% 5336 350 145 87 $10,916 $657 $272 $163 Relative NPVs Impact

0711snoitceS teN 2 50% 350 196 961$833$306$89 ($/share) (%) (%)

%06ytivitcepsorP 3 40% 350 248 651$193$355$99 Undiscounted $23.08 ###

Prospective Sections 702 4 30% 350 299 031$334$705$09 Discounted $11.79 ### -49%





Optimal # Wells per Year 350 (UnRisked) (Risked) (C$/boe) $27.28/boe $13.93/boe $12.29/boe $3.72/boeYears to Optimal Pace 5 400 111 (C$/share) $23.08/sh $11.79/sh $10.40/sh $3.15/sh

Optimal Years to Dev. Inventory 15

Amaranth (MB) Impact of Risking










Optimal # Wells per Year 150 (UnRisked) (Risked) (C$/boe) $32.27/boe $22.60/boe $22.46/boe $10.54/boeYears to Optimal Pace 5 138 61 (C$/share) $9.42/sh $6.59/sh $6.55/sh $3.08/shOptimal Years to Dev. Inventory 7

p Seal - Cold Prod. (AB) Impact of Risking







Booked (or producing) Locations - 6 25% 80 80 68$443$443$02 Risked $2.37 ### -72%



Optimal # Wells per Year 80 (UnRisked) (Risked) (C$/boe) $19.36/boe $8.68/boe $6.94/boe $1.94/boeYears to Optimal Pace 5 577 152 (C$/share) $23.63/sh $10.59/sh $8.47/sh $2.37/sh

Optimal Years to Dev. Inventory 19

Seal - Thermal (AB) Impact of Risking




%05ytivitcepsorP 3 25% 25 13 501$224$118$3 U N C O Undiscounted $45.85 ###


Wells per Section 4 5 15% 25 25 201$386$386$4 C O M PA Bluesky $14.70 ### -23%

Booked (or producing) Locations - 6 15% 25 25 49$626$626$4 Risked $2.45 5% -83%


Total 516 500 440 70 $21,683 $9,081 $6,951 $1,160Initial # Modules per year 1 Undiscounted Discounted Bluesky RISKED

Optimal # Modules per Year 25 (UnRisked) (Risked) (C$/boe) $12.97/boe $5.43/boe $4.16/boe $0.69/boeYears to Optimal Pace 5 1,672 264 (C$/share) $45.85/sh $19.20/sh $14.70/sh $2.45/shOptimal Years to Dev. Inventory 21

($7.37)

$19.21

$0.89

($0.54)

$39.07

$33.50

$21.30

$12.20

$39.07

$72.56

$10.40

$6.55

$8.47

$14.70

$68.59

$7.25

$3.48

$12.20

Resource (MMBoe)

Resource (MMBoe)

Resource (MMBoe)

YEAR

YEAR

Resource (MMBoe)

YEAR

Drilling Inventory

Unconstrained Pace Company Pace


Drilling Inventory

YEAR

YEAR

Risked Valuation

Resource (MMBoe)

Drilling Inventory

Company Pace

Drilling InventoryecaP deniartsnocnUecaP deniartsnocnU ecaP ynapmoCecaP ynapmoC

Risked Valuation

CO

MP

AN

Y


UN

CO

NS

TR

AIN

ED

UN

CO

NS

TR

AIN

ED

CO

MP

AN

Y

Unconstrained Pace

Risked Valuation

Drilling Inventory


Unconstrained PaceCompany PaceUnconstrained Pace Company Pace

Risked Valuation

Risked Valuation

Unconstrained Pace

UN

CO

NS

TR

AIN

ED

CO

MP

AN

Y

UN

CO

NS

TR

AIN

ED

CO

MP

AN

Y

Company Pace

Total Upside

("Bluesky")

Unrisked

(incremental)

$10.84$1.38

Risked Upside(C$/share)(C$/share)

$9.99 $16.25

$12.25

$6.10

Risked NAV SENSITIVITY - Penn West Exploration

$2.64

$1.72

$2.52

$15.41

$9.60

$3.80

$4.21

$4.34

$17.96

$10.80

Price Target

Risked NAV

Current Price

$16 $20 $24 $28 $32 $36 $40 $44 $48 $52

Wells per Year(+/- 20%)

Operating Costs(+/- 20%)

Capital Costs (+/- 20%)

Ultimate Recovery (+/- 20%)

Commodity Price(+/- 20%)

$19.20$14.70

$2.45

$45.85

$0.00$5.00

$10.00$15.00$20.00$25.00$30.00$35.00$40.00$45.00$50.00

Undisc

ount

ed

Discou

nted

Bluesk

y

Risked

UNCONSTRAINED(not in valuation)

COMPANY

(C$/

sh

are

)

Included in Valuation

$10.59$8.47

$2.37

$23.63

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

Undisc

ount

ed

Discou

nted

Bluesk

y

Risked


COMPANY

(C$/

sha

re)


$18.69$16.25

$6.26

$29.04

$0.00$5.00

$10.00$15.00$20.00$25.00$30.00$35.00

Undisc

ount

ed

Discou

nted

Bluesk

y

Risked


COMPANY

(C$

/sh

are

)


$6.59 $6.55

$3.08

$9.42

$0.00$1.00$2.00$3.00$4.00$5.00$6.00$7.00$8.00$9.00

$10.00

Undisc

ount

ed

Discou

nted

Bluesk

y

Risked


COMPANY(C

$/s

har

e)


$11.79 $10.40

$3.15

$23.08

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

Undisc

ount

ed

Discou

nted

Bluesk

y

Risked


COMPANY

(C$

/sh

are

)


Core NAV

Risked Upside

Core NAV

Risked Upside

Our $29.00/share target price is based on a discounted 0.9x multiple to Penn West's Risked NAV (vs. the group avg. of 1.0x).

We award a discounted multiple to Penn West primarily due to the company's lower than average production per share growth profile.

Risked and UnRiskedupside summary (by play).

Core NAV summary.

Target multiple: Near-term production growth (shown to the right) is the greatest factor in determining whether or not a company receives a premium or a discounted target multiple.

Key assumptions: key assumptions for each play include NPV/well, prospective net sections, wells per section, initial wells per year, and optimal wells per year.

De-risking Tier: it is at this step that we integrate our risk ranking from our “matrix” on the preceding page.

Inventory / Pace of Development: – the company’s pace of development and the risked inventory included in our valuation are shown here.

Value of risked and unriskedinventory.

Impact of risking: the impact of our different layers of risking is illustrated here, as is the value per unit included in our valuation for each play.

Target Price

Bluesky (unrisked) NAV

Risked NAV


Amaranth

Bakken (US)

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Eagleford

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Comparative Valuations

Exhibit 52. Senior E&P – Valuations

CIBC Price Deck 2011 2011 2011

Current Target Target Target Dividend Price / Price / Price / EV / DACF P/EPS Free Cash Flow Yield - %

Price Price Rating Return Yield ~ Base NAV Risked NAVUnrisked

NAV2011 2012E 2013E 2014E 2015E 2016E 2011 2012E 2013E 2014E 2015E 2016E 2011 2012E 2013E 2014E 2015E 2016E

Canadian Integrateds

Cenovus Energy $32.34 $40.00 SO 24% 2.7% 113% 81% 68% 7.7x 7.0x 7.5x 7.1x 6.7x 5.8x 19.8x 16.0x 15.7x 14.6x 13.3x 11.6x 3% 2% 2% 1% 2% 4%Husky Energy $26.86 $29.00 SP 8% 4.5% 105% 88% 64% 5.0x 6.6x 6.9x 5.9x 5.6x 5.3x 11.6x 15.9x 15.6x 12.7x 11.8x 11.2x 0% -1% 0% 5% 4% 4%Imperial Oil Ltd $45.28 $44.00 SU -3% 1.0% 127% 108% 80% 9.6x 9.7x 9.1x 9.4x 7.3x 6.9x 11.5x 11.9x 12.3x 12.9x 10.1x 10.0x 1% -3% -1% 0% 4% 4%Suncor Energy $31.57 $42.00 SO 33% 1.6% 88% 77% 64% 5.6x 6.0x 6.2x 6.0x 5.8x 5.6x 8.8x 10.7x 11.7x 11.7x 10.9x 10.5x 12% 3% 0% 0% 1% 1%Average 7.0x 7.3x 7.4x 7.1x 6.3x 5.9x 12.9x 13.6x 13.8x 13.0x 11.5x 10.8x 4% 0% 0% 2% 3% 3%

Canadian Large Caps

Canadian Natural Resources $30.15 $34.00 SO 13% 1.4% 104% 89% 75% 6.1x 6.9x 6.1x 5.3x 4.9x 4.2x 13.1x 19.3x 14.6x 11.5x 10.1x 8.6x 1% -2% -1% 1% 2% 7%Encana (USD) $22.15 $23.00 SP 4% 3.6% 273% 92% 33% 5.1x 5.3x 8.4x 7.1x 6.1x 5.8x 40.8x 18.9x 53.9x 19.9x 15.2x 12.1x -6% 0% -3% -1% -3% -5%Nexen $25.43 $27.50 SU 8% 0.8% 150% 126% 80% 7.2x 6.0x 5.1x 5.4x 4.6x 5.0x 15.0x 30.1x 27.5x 26.7x 19.2x 28.5x 2% 2% 2% 1% 7% 5%Talisman Energy (USD) $13.22 $18.00 SO 36% 2.0% 129% 68% 38% 5.5x 5.5x 5.5x 5.2x 4.7x 4.5x 22.5x 34.7x 37.8x 22.0x 18.9x 16.0x -13% -5% -2% -2% -1% -1%Average 6.0x 5.9x 6.3x 5.7x 5.1x 4.9x 22.9x 25.7x 33.4x 20.0x 15.9x 16.3x -4% -1% -1% 0% 1% 1%

Oil Sands Pure Plays

Canadian Oil Sands $20.99 $18.00 SU -14% 6.0% 128% 120% 113% 5.4x 7.8x 11.6x 9.0x 8.6x 8.7x 8.9x 13.0x 18.0x 14.6x 14.3x 13.7x 12% 2% -3% 1% 2% 9%Connacher Oil & Gas $0.45 $0.90 Spec-SP 100% 0.0% 71% 50% 27% 25.3x 11.6x 8.9x 8.7x 7.1x 6.4x nm nm nm nm nm nm 0% -9% -2% -116% -93% -58%MEG Energy $40.00 $50.00 SO 25% 0.0% 125% 78% 56% 25.5x 48.9x 32.2x 14.9x 11.9x 13.5x nm nm 185.8x 36.6x 23.1x 26.4x -7% -21% -18% -15% -15% -16%Average 18.7x 22.8x 17.5x 10.9x 9.2x 9.6x 8.9x 13.0x 101.9x 25.6x 18.7x 20.1x 2% -9% -8% -44% -35% -22%

Sensitivity Based on Current Forward Strip 2011 2011 2011

Current Target Target Target Dividend Price / Price / Price / EV / DACF P/EPS Free Cash Flow Yield - %

Price Price Rating Return Yield Base NAV Risked NAVUnrisked

NAV2011 2012E 2013E 2014E 2015E 2016E 2011 2012E 2013E 2014E 2015E 2016E 2011 2012E 2013E 2014E 2015E 2016E


Cenovus Energy $32.34 $40.00 SO 24% 2.7% 110% 79% 67% 7.7x 6.9x 7.2x 6.6x 6.3x 5.6x 19.8x 15.7x 14.5x 13.1x 12.5x 11.3x 3% 2% 2% 2% 3% 4%Husky Energy $26.86 $29.00 SP 8% 4.5% 105% 88% 65% 5.0x 6.3x 6.6x 5.6x 5.5x 5.3x 11.6x 14.6x 14.8x 12.0x 11.9x 11.9x 0% -1% 0% 5% 4% 4%Imperial Oil Ltd $45.28 $44.00 SU -3% 1.0% 123% 105% 81% 9.6x 9.2x 8.6x 8.7x 6.8x 6.6x 11.5x 11.3x 11.5x 11.8x 9.6x 9.8x 1% -2% 0% 1% 5% 5%Suncor Energy $31.57 $42.00 SO 33% 1.6% 85% 74% 62% 5.6x 5.5x 5.6x 5.4x 5.4x 5.3x 8.8x 9.7x 10.5x 10.3x 10.2x 10.2x 12% 4% 1% 2% 2% 2%Average 7.0x 7.0x 7.0x 6.6x 6.0x 5.7x 12.9x 12.8x 12.8x 11.8x 11.0x 10.8x 4% 1% 1% 2% 3% 4%

Canadian Large Caps

Canadian Natural Resources $30.15 $34.00 SO 13% 1.4% 100% 87% 74% 6.1x 6.4x 5.6x 4.8x 4.6x 4.0x 13.1x 15.8x 12.4x 10.0x 9.5x 8.5x 1% -1% 1% 2% 2% 7%Encana (USD) $22.15 $23.00 SP 4% 3.6% nm 196% 58% 5.1x 5.4x 10.4x 9.7x 8.3x 8.1x 40.8x 19.3x nm nm 39.8x 27.5x -6% 0% -6% -6% -8% -10%Nexen $25.43 $27.50 SU 8% 0.8% 141% 122% 83% 7.2x 5.7x 4.8x 5.0x 4.5x 4.9x 15.0x 24.0x 21.8x 22.2x 18.0x 29.8x 2% 3% 3% 2% 8% 5%Talisman Energy (USD) $13.22 $18.00 SO 36% 2.0% 133% 76% 45% 5.5x 5.4x 5.3x 5.0x 4.8x 4.8x 22.5x 31.7x 30.5x 20.1x 20.5x 20.4x -13% -4% -1% -2% -1% -3%Average 6.0x 5.7x 6.5x 6.1x 5.5x 5.5x 22.9x 22.7x 21.6x 17.4x 22.0x 21.5x -4% 0% -1% -1% 0% 0%


Canadian Oil Sands $20.99 $18.00 SU -14% 6.0% 118% 111% 105% 5.4x 7.2x 9.8x 7.9x 7.8x 8.2x 8.9x 11.7x 13.9x 11.8x 12.4x 12.6x 12% 3% -2% 2% 3% 9%Connacher Oil & Gas $0.45 $0.90 Spec-SP 100% 0.0% 55% 42% 25% 25.3x 10.6x 7.8x 7.0x 5.2x 5.1x nm nm nm nm nm nm 0% -5% 3% -105% -82% -47%MEG Energy $40.00 $50.00 SO 25% 0.0% 121% 76% 55% 25.5x 44.8x 29.5x 13.5x 11.1x 13.0x nm nm 119.5x 21.6x 14.9x 17.6x -7% -20% -18% -14% -14% -16%Average 18.7x 20.9x 15.7x 9.5x 8.0x 8.8x 8.9x 11.7x 66.7x 16.7x 13.7x 15.1x 2% -8% -5% -39% -31% -18%


Amaranth Bakken (US) Barnett Eagleford Fayetteville Methodology Comparative Valuations

VET

Exhibit 53. Senior E&P – Forecasted CFPS And EPS Sensitivities

CIBC Price Deck 2011 2011CFPS (Diluted) CAGR Operating EPS (Diluted) CAGR

2011 2012E 2013E 2014E 2015E 2016E T + 2 T + 5 2011 2012E 2013E 2014E 2015E 2016E T + 2 T + 5


Cenovus Energy $4.32 $4.88 $4.70 $5.09 $5.50 $6.25 4% 8% $1.64 $2.02 $2.06 $2.22 $2.44 $2.79 12% 11%Husky Energy $5.63 $4.43 $4.48 $5.24 $5.52 $5.88 -11% 1% $2.31 $1.69 $1.72 $2.11 $2.28 $2.39 -14% 1%Imperial Oil Ltd $4.70 $4.84 $5.21 $5.11 $6.45 $6.59 5% 7% $3.95 $3.79 $3.67 $3.50 $4.49 $4.52 -4% 3%Suncor Energy $6.17 $5.74 $5.72 $5.84 $6.14 $6.45 -4% 1% $3.59 $2.95 $2.69 $2.71 $2.89 $3.01 -13% -3%Average -1% 4% -5% 3%

Canadian Large Caps

Canadian Natural Resources $5.94 $5.43 $6.31 $7.29 $7.90 $8.80 3% 8% $2.30 $1.56 $2.07 $2.61 $2.97 $3.49 -5% 9%Encana (USD) $5.60 $4.90 $3.70 $4.60 $5.03 $5.71 -19% 0% $0.54 $1.17 $0.41 $1.12 $1.45 $1.83 -13% 28%Nexen $4.49 $5.02 $5.72 $5.44 $5.94 $5.31 13% 3% $1.70 $0.85 $0.93 $0.95 $1.32 $0.89 -26% -12%Talisman Energy (USD) $3.33 $3.12 $3.05 $3.38 $3.74 $4.02 -4% 4% $0.59 $0.38 $0.35 $0.60 $0.70 $0.83 -23% 7%Average -3% 3% -17% 8%


Canadian Oil Sands $3.92 $2.80 $2.09 $2.69 $2.79 $2.74 -27% -7% $2.35 $1.61 $1.16 $1.44 $1.46 $1.53 -30% -8%Connacher Oil & Gas $0.09 $0.05 $0.09 $0.13 $0.24 $0.32 -3% 28% ($0.20) ($0.22) ($0.16) ($0.13) ($0.09) ($0.09) nm nmMEG Energy $1.54 $0.97 $1.70 $4.07 $5.55 $5.37 5% 28% $0.55 ($0.01) $0.22 $1.09 $1.73 $1.51 -38% 22%Average -9% 17% -34% 7%

2011

Sensitivity Based on Current Forward Strip 2011CFPS (Diluted) CAGR Operating EPS (Diluted) CAGR

2011 2012E 2013E 2014E 2015E 2016E T + 2 T + 5 2011 2012E 2013E 2014E 2015E 2016E T + 2 T + 5


Cenovus Energy $4.32 $4.95 $4.91 $5.40 $5.68 $6.35 7% 8% $1.64 $2.06 $2.23 $2.47 $2.58 $2.87 17% 12%Husky Energy $5.63 $4.62 $4.58 $5.38 $5.51 $5.74 -10% 0% $2.31 $1.84 $1.81 $2.24 $2.27 $2.26 -11% 0%Imperial Oil Ltd $4.70 $5.07 $5.51 $5.46 $6.69 $6.71 8% 7% $3.95 $4.00 $3.95 $3.82 $4.72 $4.64 0% 3%Suncor Energy $6.17 $6.13 $6.12 $6.27 $6.37 $6.56 0% 1% $3.59 $3.26 $3.02 $3.08 $3.09 $3.11 -8% -3%Average 1% 4% -1% 3%

Canadian Large Caps

Canadian Natural Resources $5.94 $5.81 $6.71 $7.74 $8.12 $8.90 6% 8% $2.30 $1.91 $2.43 $3.02 $3.16 $3.56 3% 9%Encana (USD) $5.60 $4.86 $3.06 $3.54 $3.90 $4.41 -26% -5% $0.54 $1.15 ($0.07) $0.32 $0.56 $0.80 nm 8%Nexen $4.49 $5.23 $5.96 $5.64 $6.03 $5.31 15% 3% $1.70 $1.06 $1.17 $1.15 $1.41 $0.85 -17% -13%Talisman Energy (USD) $3.33 $3.18 $3.15 $3.45 $3.67 $3.79 -3% 3% $0.59 $0.42 $0.43 $0.66 $0.64 $0.65 -14% 2%Average -5% 0% -9% 2%


Canadian Oil Sands $3.92 $3.00 $2.44 $3.04 $3.02 $2.86 -21% -6% $2.35 $1.79 $1.51 $1.78 $1.69 $1.66 -20% -7%Connacher Oil & Gas $0.09 $0.07 $0.11 $0.19 $0.29 $0.37 9% 32% ($0.20) ($0.22) ($0.14) ($0.09) ($0.05) ($0.05) nm nmMEG Energy $1.54 $1.05 $1.84 $4.42 $5.91 $5.52 9% 29% $0.55 $0.05 $0.33 $1.86 $2.68 $2.27 -22% 33%Average -1% 18% -21% 13%



VET

Exhibit 54. Senior E&P – Forecasted Capital Spending Sensitivities

CIBC Price Deck 2011 2011 2011Capital Expenditures ($mm) Cash Flow From Continuing Operations ($mm) Reinvestment Ratio (Net Capex / Cash Flow)

2011 2012E 2013E 2014E 2015E 2016E 2011 2012E 2013E 2014E 2015E 2016E 2011 2012E 2013E 2014E 2015E 2016ECanadian Integrateds

Cenovus Energy $2,744 $3,257 $3,118 $3,669 $3,615 $3,805 $3,276 $3,699 $3,555 $3,848 $4,158 $4,723 0.8x 0.9x 0.9x 1.0x 0.9x 0.8xHusky Energy $5,278 $4,680 $4,483 $3,812 $4,229 $4,567 $4,823 $3,862 $4,359 $5,105 $5,374 $5,721 1.1x 1.2x 1.0x 0.7x 0.8x 0.8xImperial Oil Ltd $3,974 $5,245 $4,817 $4,369 $3,980 $3,974 $4,009 $4,135 $4,459 $4,373 $5,512 $5,634 0.9x 1.2x 1.1x 1.0x 0.7x 0.7xSuncor Energy $6,876 $7,455 $8,926 $8,858 $9,066 $9,345 $9,746 $8,941 $8,893 $9,084 $9,545 $10,022 0.4x 0.8x 1.0x 1.0x 0.9x 0.9xAverage 0.8x 1.0x 1.0x 0.9x 0.8x 0.8x

Canadian Large Caps

Canadian Natural Resources $6,183 $6,501 $6,981 $7,693 $8,092 $7,480 $6,279 $5,899 $6,924 $7,988 $8,661 $9,652 1.0x 1.1x 1.0x 1.0x 0.9x 0.8xEncana (USD) $4,578 $3,784 $4,519 $3,918 $4,424 $5,046 $4,135 $3,611 $2,725 $3,387 $3,707 $4,205 0.7x 0.3x 1.2x 1.1x 1.1x 1.2xNexen $2,569 $3,043 $2,851 $2,821 $2,276 $2,290 $2,368 $2,687 $3,137 $2,987 $3,258 $2,915 0.9x 0.9x 0.9x 0.9x 0.7x 0.8xTalisman Energy (USD) $4,289 $3,763 $3,259 $3,673 $3,768 $4,154 $3,434 $3,200 $3,016 $3,348 $3,702 $3,978 1.3x 0.4x 1.1x 1.1x 1.0x 1.0xAverage 1.0x 0.7x 1.1x 1.0x 0.9x 0.9x


Canadian Oil Sands $643 $1,124 $1,334 $1,249 $1,115 $466 $1,897 $1,353 $1,013 $1,303 $1,351 $1,324 0.3x 0.8x 1.3x 1.0x 0.8x 0.4xConnacher Oil & Gas $158 $49 $42 $295 $293 $260 $41 $24 $38 $60 $106 $143 1.0x 1.7x 1.1x 4.9x 2.8x 1.8xMEG Energy $856 $1,799 $1,759 $1,999 $2,254 $2,353 $296 $193 $339 $813 $1,108 $1,072 2.9x 9.3x 5.2x 2.5x 2.0x 2.2xAverage 1.4x 3.9x 2.5x 2.8x 1.9x 1.5x

2011.0x

Sensitivity Based on Current Forward Strip 2011 2011Capital Expenditures ($mm) Cash Flow From Continuing Operations ($mm) Reinvestment Ratio (Net Capex / Cash Flow)

2011 2012E 2013E 2014E 2015E 2016E 2011 2012E 2013E 2014E 2015E 2016E 2011 2012E 2013E 2014E 2015E 2016ECanadian Integrateds

Cenovus Energy $2,744 $3,257 $3,118 $3,669 $3,615 $3,805 $3,276 $3,750 $3,712 $4,082 $4,292 $4,801 0.8x 0.9x 0.8x 0.9x 0.8x 0.8xHusky Energy $5,278 $4,679 $4,481 $3,811 $4,230 $4,564 $4,823 $4,043 $4,463 $5,235 $5,367 $5,588 1.1x 1.2x 1.0x 0.7x 0.8x 0.8xImperial Oil Ltd $3,974 $5,245 $4,817 $4,369 $3,980 $3,974 $4,009 $4,327 $4,713 $4,666 $5,724 $5,736 0.9x 1.2x 1.0x 0.9x 0.7x 0.7xSuncor Energy $6,876 $7,451 $8,918 $8,856 $9,066 $9,347 $9,746 $9,551 $9,512 $9,747 $9,908 $10,194 0.4x 0.8x 0.9x 0.9x 0.9x 0.9xAverage 0.8x 1.0x 1.0x 0.9x 0.8x 0.8x

Canadian Large Caps

Canadian Natural Resources $6,183 $6,500 $6,978 $7,687 $8,084 $7,470 $6,279 $6,320 $7,359 $8,483 $8,908 $9,760 1.0x 1.0x 1.0x 0.9x 0.9x 0.8xEncana (USD) $4,578 $3,784 $4,519 $3,918 $4,424 $5,046 $4,135 $3,580 $2,251 $2,606 $2,872 $3,247 0.7x 0.3x 1.5x 1.4x 1.4x 1.5xNexen $2,569 $3,042 $2,849 $2,820 $2,276 $2,292 $2,368 $2,803 $3,270 $3,093 $3,308 $2,916 0.9x 0.9x 0.9x 0.9x 0.7x 0.8xTalisman Energy (USD) $4,289 $3,763 $3,259 $3,673 $3,766 $4,153 $3,434 $3,256 $3,116 $3,413 $3,630 $3,753 1.3x 0.4x 1.0x 1.1x 1.0x 1.1xAverage 1.0x 0.6x 1.1x 1.1x 1.0x 1.0x


Canadian Oil Sands $643 $1,124 $1,334 $1,249 $1,115 $466 $1,897 $1,453 $1,179 $1,470 $1,460 $1,386 0.3x 0.8x 1.1x 0.9x 0.8x 0.3xConnacher Oil & Gas $158 $49 $42 $295 $293 $260 $41 $30 $49 $84 $128 $165 1.0x 1.4x 0.9x 3.5x 2.3x 1.6xMEG Energy $856 $1,798 $1,759 $1,999 $2,253 $2,352 $296 $210 $367 $882 $1,181 $1,101 2.9x 8.5x 4.8x 2.3x 1.9x 2.1xAverage 1.4x 3.6x 2.3x 2.2x 1.7x 1.3x



VET

Exhibit 55. Senior E&P – Forecasted Balance Sheet Sensitivities

CIBC Price Deck 2011 2011 2011Net Debt - $mm Net Debt / Debt + Equity Net Debt / Cash Flow

2011 2012E 2013E 2014E 2015E 2016E 2011 2012E 2013E 2014E 2015E 2016E 2011 2012E 2013E 2014E 2015E 2016E


Cenovus Energy $3,032 $3,453 $3,723 $4,209 $4,331 $4,079 24% 25% 25% 25% 24% 21% 0.9x 0.9x 1.0x 1.1x 1.0x 0.9xHusky Energy $2,260 $3,219 $4,544 $4,420 $4,444 $4,457 11% 15% 19% 18% 18% 17% 0.4x 0.7x 1.0x 0.9x 0.8x 0.8xImperial Oil Ltd $5 $1,653 $2,409 $2,803 $1,669 $408 0% 9% 12% 12% 6% 1% 0.0x 0.4x 0.5x 0.6x 0.3x 0.1xSuncor Energy $6,976 $5,657 $6,613 $7,271 $7,738 $8,072 15% 12% 13% 13% 13% 13% 0.7x 0.6x 0.7x 0.8x 0.8x 0.8xAverage 13% 15% 16% 17% 15% 12% 0.5x 0.7x 0.8x 0.9x 0.7x 0.6x

Canadian Large Caps

Canadian Natural Resources $8,537 $9,870 $10,624 $10,789 $10,680 $8,968 27% 29% 29% 27% 25% 20% 1.4x 1.7x 1.5x 1.4x 1.2x 0.9xEncana (USD) $7,351 $5,452 $6,689 $7,602 $8,700 $10,122 31% 39% 45% 47% 49% 51% 1.8x 1.5x 2.5x 2.2x 2.3x 2.4xNexen $3,538 $2,745 $2,609 $2,550 $1,673 $1,155 30% 23% 22% 21% 14% 10% 1.5x 1.0x 0.8x 0.9x 0.5x 0.4xTalisman Energy (USD) $4,481 $3,649 $4,165 $4,757 $5,090 $5,532 31% 27% 30% 32% 32% 33% 1.3x 1.2x 1.4x 1.4x 1.4x 1.4xAverage 30% 30% 31% 32% 30% 28% 1.5x 1.3x 1.6x 1.5x 1.4x 1.3x


Canadian Oil Sands $412 $919 $1,780 $2,233 $2,241 $2,249 8% 16% 27% 31% 29% 30% 0.2x 0.7x 1.8x 1.7x 1.7x 1.7xConnacher Oil & Gas $829 $839 $806 $1,041 $1,228 $1,345 66% 72% 73% 82% 86% 90% 20.2x 34.6x 21.0x 17.3x 11.6x 9.4xMEG Energy $24 $1,668 $3,119 $4,305 $5,451 $6,732 1% 29% 44% 50% 54% 58% 0.1x 8.6x 9.2x 5.3x 4.9x 6.3xAverage 25% 39% 48% 54% 57% 59% 6.8x 14.6x 10.7x 8.1x 6.0x 5.8x

2,011.0x

Sensitivity Based on Current Forward Strip 20113-Jul-05

Net Debt - $mm Net Debt / Debt + Equity Net Debt / Cash Flow2011 2012E 2013E 2014E 2015E 2016E 2011 2012E 2013E 2014E 2015E 2016E 2011 2012E 2013E 2014E 2015E 2016E


Cenovus Energy $3,032 $3,353 $3,441 $3,729 $3,753 $3,446 24% 24% 23% 23% 21% 18% 0.9x 0.9x 0.9x 0.9x 0.9x 0.7xHusky Energy $2,260 $2,998 $4,190 $3,968 $4,032 $4,197 11% 14% 18% 16% 16% 16% 0.4x 0.7x 0.9x 0.8x 0.8x 0.8xImperial Oil Ltd $5 $1,460 $1,963 $2,064 $719 ($645) 0% 8% 9% 9% 3% -2% 0.0x 0.3x 0.4x 0.4x 0.1x -0.1xSuncor Energy $6,976 $4,931 $5,200 $5,274 $5,477 $5,705 15% 11% 10% 10% 10% 9% 0.7x 0.5x 0.5x 0.5x 0.6x 0.6xAverage 13% 14% 14% 14% 11% 8% 0.5x 0.6x 0.7x 0.7x 0.6x 0.5x

Canadian Large Caps

Canadian Natural Resources $8,537 $9,347 $9,609 $9,346 $9,069 $7,291 27% 27% 26% 24% 21% 17% 1.4x 1.5x 1.3x 1.1x 1.0x 0.7xEncana (USD) $7,351 $5,494 $7,210 $8,896 $10,820 $13,193 31% 39% 48% 54% 59% 64% 1.8x 1.5x 3.2x 3.4x 3.8x 4.1xNexen $3,538 $2,573 $2,264 $2,143 $1,276 $796 30% 22% 19% 17% 11% 7% 1.5x 0.9x 0.7x 0.7x 0.4x 0.3xTalisman Energy (USD) $4,481 $3,585 $3,996 $4,529 $4,941 $5,613 31% 27% 29% 30% 32% 34% 1.3x 1.1x 1.3x 1.3x 1.4x 1.5xAverage 30% 29% 30% 31% 31% 30% 1.5x 1.3x 1.6x 1.6x 1.6x 1.6x


Canadian Oil Sands $412 $820 $1,515 $1,801 $1,809 $1,817 8% 15% 23% 25% 24% 24% 0.2x 0.6x 1.3x 1.2x 1.2x 1.3xConnacher Oil & Gas $829 $825 $777 $995 $1,167 $1,266 66% 71% 71% 79% 83% 85% 20.2x 27.0x 15.8x 11.8x 9.1x 7.7xMEG Energy $24 $1,637 $3,040 $4,183 $5,290 $6,563 1% 29% 43% 48% 52% 55% 0.1x 7.8x 8.3x 4.7x 4.5x 6.0xAverage 25% 38% 46% 51% 53% 55% 6.8x 11.8x 8.5x 5.9x 4.9x 5.0x



VET

Exhibit 56. Senior E&P – Forecasted Production Profiles

Total Company Production (boe/d) 2012E CAGR Long-Life Production (as % of Total)2011 2012E 2013E 2014E 2015E 2016E % Gas % Oil T + 2 T + 5 2011 2012E 2013E 2014E 2015E 2016E


Cenovus Energy 243,492 260,488 282,087 317,203 345,173 395,906 38% 62% 8% 10% 27% 32% 34% 40% 44% 49%

Husky Energy 312,501 303,148 338,438 386,221 406,624 433,242 32% 68% 4% 7% 90% 91% 92% 93% 94% 95%

Imperial Oil Ltd 300,137 304,177 360,943 371,027 453,668 476,277 14% 86% 10% 10% 78% 78% 81% 82% 85% 86%

Suncor Energy 545,923 557,110 635,466 705,577 721,580 750,690 9% 91% 8% 7% 62% 67% 67% 71% 71% 76%

Average 23% 77% 7% 8%

Canadian Large Caps

Canadian Natural Resources 598,245 677,116 743,433 818,100 863,736 934,310 31% 69% 11% 9% 23% 29% 31% 34% 35% 39%

Encana 523,064 540,725 559,812 545,657 551,375 575,205 94% 6% 3% 2% 90% 91% 92% 93% 94% 95%

Nexen 202,687 197,402 230,465 224,962 233,133 213,188 16% 84% 7% 1% 8% 10% 11% 11% 14% 16%

Talisman Energy 426,219 437,666 422,514 457,222 478,197 504,401 60% 40% 0% 3% 24% 32% 39% 45% 51% 55%

Average 50% 50% 5% 4%


Athabasca Oil Sands 0 2,081 10,700 19,050 31,800 45,713 34% 66% nm nm nm 0% 0% 51% 75% 87%

Canadian Oil Sands 106,088 106,649 108,016 111,873 115,731 115,731 0% 100% 1% 2% 100% 100% 100% 100% 100% 100%

Connacher Oil & Gas 14,519 13,381 14,552 16,547 18,547 23,400 0% 100% 0% 10% 97% 98% 98% 98% 98% 99%

MEG Energy 26,524 28,149 34,513 68,100 80,072 76,069 0% 100% 14% 23% 100% 100% 100% 100% 100% 100%

Average 0% 100% 5% 12%



VET

Exhibit 57. Oil Sands Pure Plays – Valuation Metrics

Current Target Target Target Market Net Debt EV Base Price/ Risked Price/ Unrisked Price/ EV / DACF EV / Undeveloped Bbl

Price Price Rating Return Cap ($MM) 2011 ($MM) ($MM) NAV Base NAV NAV Risked NAV NAV Unrisked NAV 2011 2012E 2013E 2014E 2015E 2016E Current Px Target Px


Athabasca Oil Sands $12.78 $17.00 SO 33% $5,106 ($750) $4,356 $3.56 359% $18.12 71% $48.88 26% nm nm nm 26.4x 14.0x 11.3x $0.50 $0.73Canadian Oil Sands $20.99 $18.00 SU -14% $10,171 $412 $10,583 $16.45 128% $17.51 120% $18.57 113% 5.4x 7.8x 11.6x 9.0x 8.6x 8.7x $1.81 $0.40Connacher Oil & Gas $0.45 $0.90 Spec-SP 100% $202 $829 $1,031 $0.64 71% $0.89 50% $1.66 27% 25.3x 11.6x 8.9x 8.7x 7.1x 6.4x ($0.18) $0.24MEG Energy $40.00 $50.00 SO 25% $7,773 $24 $7,797 $32.12 125% $51.10 78% $71.36 56% 25.5x 48.9x 32.2x 14.9x 11.9x 13.5x $0.32 $0.69Petrobank (HBU) $0.00 $2.50 SO nm nm $74 nm $1.81 nm $2.49 nm $5.61 nm nm nm nm nm nm nm ($0.34) $0.41

Average $5,813 $118 $5,942 $0.42 $0.49


Exhibit 58. Oil Sands Pure Plays – Operating Metrics

Resources (MMBbls) Production (Bbls/d) CAGR CFPS CAGR

2P Best Estimate Contingent 2P + 2C % SAGD 2011 2012E 2013E 2014E 2015E 2016E T + 2 T + 5 2011 2012E 2013E 2014E 2015E 2016E T + 2 T + 5


Athabasca Oil Sands 339 10,400 10,739 100% 0 2,081 10,700 19,050 31,800 45,713 nm nm ($0.07) ($0.05) $0.20 $0.54 $1.04 $1.51 nm nmCanadian Oil Sands 1,860 1,800 3,660 0% 106,088 106,649 108,016 111,873 115,731 115,731 1% 2% $3.92 $2.80 $2.09 $2.69 $2.79 $2.74 -27% -7%Connacher Oil & Gas 502 223 725 100% 14,519 13,381 14,552 16,547 18,547 23,400 0% 10% $0.09 $0.05 $0.09 $0.13 $0.24 $0.32 -3% 28%MEG Energy 1,919 3,716 5,635 100% 26,524 28,149 34,513 68,100 80,072 76,069 14% 23% $1.54 $0.97 $1.70 $4.07 $5.55 $5.37 5% 28%Petrobank (HBU) 0 nm nm 0 350 1,441 18,601 19,501 18,901 nm nm ($0.16) ($0.06) $0.20 $0.45 $0.58 $0.48 nm nmAverage 5% 12% -9% 17%


Exhibit 59. Oil Sands Pure Plays – Liquidity and NAV Sensitivities

CAPEX Available Liquidity Risked NAV Unrisked NAV

2011 2012E 2012E 2013E $60.00 $70.00 $80.00 $90.00 $100.00 $110.00 $60.00 $70.00 $80.00 $90.00 $100.00 $110.00


Athabasca Oil Sands $610 ($757) $1,199 ($135) $13.17 $14.64 $16.11 $17.43 $18.70 $19.83 $30.16 $35.06 $40.23 $45.01 $49.58 $53.79Canadian Oil Sands $643 $1,124 $2,942 ($81) $4.02 $9.20 $14.08 $18.53 $22.63 $26.45 $5.08 $10.26 $15.14 $19.59 $23.70 $27.52Connacher Oil & Gas $40 $42 $49 $24 ($0.45) ($0.01) $0.38 $0.80 $1.21 $1.55 $0.05 $0.53 $0.97 $1.51 $2.05 $2.51MEG Energy $856 $1,791 $2,392 $163 $27.41 $35.88 $43.40 $50.69 $57.53 $63.70 $38.46 $50.14 $60.43 $70.61 $80.14 $88.68Petrobank (HBU) $169 $43 ($125) ($175) $5.09 $5.09 $7.94 $10.43 $12.78 $14.77 $9.60 $15.24 $20.17 $24.80 $28.72 $32.35



VET

Exhibit 60. Intermediate E&Ps – Investment Ratings And Valuation Share Total TotalPrice Shares Market Total Senior Conv. Enterprise Debt/CF Debt/CF Total Cur. Drawn ($M) Target Expected

Symbol 08/13/12 High Low O/S (M) Cap ($M) Debt Notes Debs. Value 2012E 2013E Avail ($M) Current Current 2012E Price Return Rating

ARC ARX $23.27 $26.74 $18.36 291.5 $6,784 $713.3 $760 $0 $7,497 R R $1,025 -$181 R R R R RBaytex BTE $44.09 $59.40 $38.54 118.9 $5,243 $375.1 $445 $0 $5,618 0.8x 1.0x $700 -$134 -19% -7% $46.00 10% SPBonavista BNP $17.06 $27.49 $13.76 168.6 $2,876 $1,121.3 $557 $0 $3,997 3.0x 2.9x $1,000 $476 48% 55% $22.00 37% SOBonterra BNE $47.20 $57.40 $38.75 19.7 $932 $133.4 $0 $0 $1,065 2.1x 2.1x $120 $76 63% 93% $49.00 10% SPCrescent Point CPG $41.10 $47.30 $35.51 327.1 $13,444 $1,592.4 $838 $0 $15,036 R R $2,100 $583 R R R R REagle EGL.UN $9.73 $11.74 $7.95 27.9 $271 $36.5 $0 $0 $308 1.0x 0.9x $49 $24 49% 41% $12.00 34% SOEnerplus ERF $14.49 $30.95 $11.67 197.3 $2,859 $1,400.2 $791 $0 $4,260 2.5x 2.3x $1,000 $369 37% 31% $14.50 8% SUFreehold FRU $19.30 $21.59 $14.51 65.4 $1,263 $25.1 $0 $0 $1,288 0.4x 0.6x $210 $23 11% 15% $20.00 10% SPLongview LNV $6.35 $11.05 $5.89 46.8 $297 $118.8 $0 $0 $416 2.0x 2.2x $200 $112 56% 57% $9.00 51% SPParallel PLT.UN $6.26 $9.40 $5.20 50.3 $315 $201.1 $57 $0 $516 5.6x 4.2x $175 $134 76% 75% $6.25 14% SOPerpetual PMT $1.13 $3.17 $0.55 147.1 $166 $319.5 $147 $85 $486 6.6x 5.3x $140 $81 58% 45% $2.00 77% SOPengrowth PGF $6.76 $11.48 $5.92 500.4 $3,383 $1,932.1 $959 $238 $5,315 3.9x 1.8x $1,250 $474 38% 15% $8.00 25% SPPenn West PWT $14.14 $22.22 $12.51 474.6 $6,711 $4,066.0 $1,974 $0 $10,777 3.7x 3.6x $3,000 $1,717 57% 68% $18.50 38% SOPetroBakken PBN $12.72 $18.29 $6.04 187.9 $2,390 $1,567.2 $874 $300 $3,957 2.9x 2.7x $1,400 $213 15% 33% $18.00 49% SOPeyto PEY $20.76 $26.33 $14.62 143.9 $2,987 $505.4 $100 $0 $3,492 2.4x 1.7x $700 $475 68% 96% $26.00 29% SOProgress PRQ $22.33 $23.00 $9.44 234.6 $5,238 $471.6 $0 $400 $5,709 3.9x 3.2x $650 $47 7% 27% $22.00 0% SPTrilogy TET $23.79 $39.47 $20.23 116.3 $2,766 $605.3 $0 $0 $3,371 1.5x 1.1x $600 $567 95% 71% $34.00 45% SOTwin Butte TBE $2.56 $3.00 $1.28 192.0 $492 $163.0 $0 $0 $655 1.5x 1.7x $240 $121 51% 73% $2.65 14% SPVermilion VET $46.00 $50.96 $38.62 98.3 $4,523 $524.1 $222 $0 $5,047 1.2x 1.3x $950 $230 24% 52% $48.00 9% SP

Total/Average - INTERMEDIATES $4,307 $1,095 $548 $73 $5,402 2.9x 2.4x 41% 48% 28%Total/Average - JUNIORS $528 $109 $12 $0 $636 2.1x 1.9x 49% 52% 25%Total/Average $3,313 $835 $407 $54 $4,148 2.6x 2.3x 43% 49% 27%

Cash Dist'n/Dividends Core Risked Unrisked EV/ EV/P+P($ per Share) P+P NAV NAV NAV P/Core P/Risked P/Bluesky Prd'n Reserves

2012E 2013E 2012E 2013E 2011A 2012E 2013E 2012E 2013E 2012E 2013E 2012E 2013E ($/sh) ($/sh) ($/sh) NAV NAV NAV ($/boe/d) ($/boe)

ARC ARX R R R R R R R R R R R R R R R R R R R R RBaytex BTE $2.64 $2.64 6.0% 6.0% $4.79 $4.26 $4.17 -11.0% -2.2% 10.3x 10.6x 10.7x 11.4x $14.96 $42.73 $82.70 295% 103% 53% $104,030 $22.28Bonavista BNP $1.44 $1.44 8.4% 8.4% $3.44 $2.13 $2.36 -38.2% 11.1% 8.0x 7.2x 10.0x 9.2x $9.00 $22.45 $48.83 190% 76% 35% $58,140 $11.71Bonterra BNE $3.12 $3.12 6.6% 6.6% $5.27 $4.04 $4.80 -23.4% 18.8% 11.7x 9.8x 13.1x 11.3x $15.00 $46.01 $70.14 315% 103% 67% $157,822 $25.89Crescent Point CPG R R R R R R R R R R R R R R R R R R R R REagle EGL.UN $1.05 $1.05 10.8% 10.8% $1.11 $1.76 $1.76 58.7% 0.0% 5.5x 5.5x 6.5x 6.5x $9.02 $11.95 $17.89 108% 81% 54% $106,170 $40.12Enerplus ERF $1.53 $1.08 10.6% 7.5% $3.19 $3.17 $3.79 -0.7% 19.8% 4.6x 3.8x 6.5x 5.5x $10.44 $16.54 $33.08 139% 88% 44% $51,166 $13.23Freehold FRU $1.58 $1.44 8.2% 7.5% $2.14 $1.29 $1.31 -40.0% 1.6% 15.0x 14.8x 15.1x 15.0x $7.69 n.a. n.a. 251% n.a. n.a. $155,179 $58.05Longview LNV $0.60 $0.60 9.4% 9.4% $1.60 $1.24 $1.30 -22.4% 4.9% 5.1x 4.9x 6.7x 6.6x $8.03 $9.24 $9.90 79% 69% 64% $65,497 $10.99Parallel PLT.UN $0.89 $0.72 14.1% 11.5% $0.67 $0.76 $0.92 12.9% 21.5% 8.3x 6.8x 11.5x 9.2x $8.54 $7.09 $8.49 73% 88% 74% $83,857 $16.65Perpetual PMT $0.00 $0.00 0.0% 0.0% $0.52 $0.37 $0.46 -28.6% 24.9% 3.0x 2.4x 6.1x 5.5x $2.03 $2.72 $4.61 56% 42% 25% $22,859 $6.04Pengrowth PGF $0.66 $0.48 9.8% 7.1% $1.87 $1.23 $1.35 -34.3% 9.8% 5.5x 5.0x 6.9x 6.1x $4.32 $8.33 $14.51 156% 81% 47% $60,918 $16.12Penn West PWT $1.08 $1.08 7.6% 7.6% $3.29 $2.41 $2.74 -26.7% 13.7% 5.9x 5.2x 8.1x 7.4x $6.64 $22.06 $48.15 213% 64% 29% $62,838 $14.99PetroBakken PBN $0.96 $0.96 7.5% 7.5% $3.79 $3.14 $3.66 -17.1% 16.5% 4.0x 3.5x 6.1x 5.4x $8.13 $23.79 $31.54 156% 53% 40% $87,452 $19.60Peyto PEY $0.72 $0.72 3.5% 3.5% $2.36 $2.27 $3.27 -4.0% 44.3% 9.2x 6.3x 10.7x 7.5x $9.32 $25.36 $46.31 223% 82% 45% $76,338 $10.83Progress PRQ $0.40 $0.40 1.8% 1.8% $0.99 $0.65 $0.97 -34.0% 48.5% 34.1x 23.0x 32.3x 23.2x $2.08 $11.54 $26.23 1075% 193% 85% $123,442 $17.65Trilogy TET $0.42 $0.42 1.8% 1.8% $1.89 $2.75 $4.23 45.6% 53.7% 8.6x 5.6x 11.3x 7.1x $6.44 $31.49 $82.97 369% 76% 29% $91,110 $38.06Twin Butte TBE $0.16 $0.18 6.2% 7.0% $0.44 $0.59 $0.50 33.1% -15.6% 4.4x 5.2x 5.5x 6.4x $1.73 $2.46 $2.77 148% 104% 92% $46,069 $18.38Vermilion VET $2.28 $2.28 5.0% 5.0% $5.22 $5.23 $5.59 0.1% 6.9% 8.8x 8.2x 9.4x 8.9x $28.43 $40.73 $58.29 162% 113% 79% $129,420 $34.52

Total/Average - INTERMEDIATES 5.7% 5.2% -14.4% 22.1% 9.5x 7.6x 10.9x 9.0x 279% 89% 48% $85,461 $19.24Total/Average - JUNIORS 9.8% 9.2% 8.5% 2.5% 7.7x 7.4x 9.0x 8.7x 132% 86% 71% $91,354 $28.84Total/Average 6.9% 6.4% -7.6% 16.4% 8.9x 7.5x 10.4x 9.0x 236% 88% 54% $87,194 $22.06

CIBC Base Assumptions

Price Forecast 2011A 2012E 2013E 2014E Long-termCrude Oil (US$/bbl) $95.05 $90.00 $87.50 $85.00 $85.00Nymex Gas (US$/mcf) $4.03 $2.70 $3.75 $4.50 $4.75Natural Gas (C$/mcf) $3.66 $2.39 $3.43 $4.08 $4.34F/X (US$/C$) $1.01 $0.99 $0.98 $0.98 $0.98

Gill

Kaliel

Gill/Grayfer

KalielKalielKaliel

Grayfer

Kaliel

P/CF (x) EV/DACF (x)

Kaliel

Grayfer

Kaliel

GillKalielKaliel

Kaliel

Gill

Bank Credit Lines

KalielKalielKaliel

Drawn (%)Analyst

KalielKaliel

Cash Yield

Enterprise Value ($M)

($ per Share, basic)Cash Flow from Operations

Per Share Growth

52-Week

Notes: Shares outstanding, net debt, and convertible debentures are based on most recent information adjusted for any equity issues or acquisitions. Debt-to-cash flow (D/CF) ratios are based on estimated 2012E year-end debt and 2012E cash flow. Ratio of enterprise value to proved plus probable (P+P) reserves based on YE/11 reserve estimates adjusted for 2012 acquisitions YTD. Ratio of enterprise value to daily production is based on 2012E estimated production. Total debt includes convertible debentures as debt. Cash dividends per share are based on the actual shares outstanding at the time of each dividend. Cash flow from operations per share is based on the weighted average of shares outstanding during the fiscal year. Core NAV is based on a blowdown analysis of P+P reserves, using a 9% after-tax discount rate, and is net of G&A, mgmt. fees, and abandonment costs. Risked NAV= Core NAV + Risked Unbooked Value. Bluesky NAV = Core NAV + Unrisked Unbooked Value. Ratings: SO=Sector Outperformer, SP=Sector Performer, SU=Sector Underperformer, R=Restricted. Source: Company reports; CIBC estimates.



VET

Exhibit 61. Intermediate E&Ps – Key Operating Statistics Netback Analysis ($/boe) - 2012E 2012E Hedging

Gross Operating Operating Oil Gas FX % Total Gain/ Oil Nat. Gas Dev. % of Revenue Hedging Royalties Costs Netback (US$5.00 (C$1.00 (US/CAD Volume Loss % Vol Avg Flr. % Vol Avg Flr. CapEx Cash Cash Equity Bank Total

($/boe) ($/boe) ($/boe) (%) ($/boe) ($/boe) /bbl) /mcf) $0.05) Hedged (% of CF) Hedged (US$/Bbl) Hedged (C$/Mcf) ($M) Flow Flow (DRIP) Debt Basic Total (incl. DRIP) Sustainable

ARC R R R R R R R R R R R R R R R R R R R R R R R RBaytex $46.76 $3.54 ($9.41) 20% ($12.06) $28.83 3.7% 1.1% 6.0% 29% 59% 31% $97.97 21% $5.18 $400 79% 49% 21% 30% 63% 138% 118% 39%Bonavista $30.89 $0.22 ($5.07) 16% ($9.14) $16.90 3.5% 6.8% 4.3% 36% 3% 47% $83.41 29% $2.93 $375 104% 39% 20% 41% 53% 140% 118% 12%Bonterra $57.45 $0.00 ($5.75) 10% ($15.30) $36.40 4.9% 3.0% 5.4% 0% 0% 0% --- 0% --- $65 82% 28% 0% 72% 65% 134% 134% 47%Crescent Point R R R R R R R R R R R R R R R R R R R R R R R REagle $84.19 $1.08 ($23.60) 28% ($12.95) $48.72 26.4% 0.0% 26.6% 20% 5% 40% n.a. 0% n.a. $42 98% 41% 42% 16% 60% 145% 107% 77%Enerplus $42.27 $1.29 ($8.59) 20% ($10.31) $24.65 2.4% 6.4% 6.7% 33% 20% 45% $96.22 21% --- $850 137% 38% 4% 58% 28% 127% 122% 0%Freehold $46.71 $0.00 ($1.89) 4% ($4.17) $40.65 13.7% 5.3% 13.8% 0% 0% 0% n.a. 0% n.a. $30 36% -63% 101% 62% 110% 145% 112% 98%Longview $58.57 $0.46 ($11.83) 20% ($19.50) $27.70 n.a. n.a. n.a. 0% 2% 0% n.a. 0% n.a. $46 80% 64% 0% 36% 46% 128% 128% 13%Parallel $34.53 $2.83 ($6.87) 20% ($7.11) $23.38 43.7% 17.1% 44.0% 18% 13% 157% n.a. 5% n.a. $24 66% -25% 110% 15% 78% 120% 99% 77%Perpetual $22.71 $3.43 ($1.74) 8% ($10.80) $13.60 3.6% 2.0% 4.2% 72% 18% 56% $84.25 75% $3.31 $65 119% 84% 0% 16% 0% 95% 95% 0%Pengrowth $43.91 $1.75 ($9.08) 21% ($14.21) $22.37 2.4% 5.6% 2.4% 28% 13% 45% $93.40 8% $4.26 $525 96% 48% 23% 29% 36% 112% 98% 8%Penn West $51.05 $0.76 ($9.56) 19% ($17.27) $24.98 1.3% 3.9% 2.5% 41% 10% 56% $85.53 14% $4.30 $1,525 133% 42% 7% 51% 39% 156% 143% 0%PetroBakken $67.45 $0.02 ($9.90) 15% ($12.31) $45.25 6.2% 1.0% 6.1% 46% 0% 53% --- 0% --- $875 150% 46% 13% 41% 26% 148% 124% 2%Peyto $21.92 $3.13 ($2.11) 10% ($1.94) $21.00 1.8% 9.8% 2.8% 38% 37% 0% --- 43% $3.86 $450 140% 49% 0% 51% 22% 106% 106% 26%Progress $19.06 ($0.03) ($1.73) 9% ($5.79) $11.51 2.5% 19.9% 4.7% 45% 0% 0% --- 52% $4.00 $270 176% 22% 15% 63% 41% 199% 171% 0%Trilogy $35.45 ($0.02) ($5.07) 14% ($7.76) $22.60 6.5% 14.2% 9.9% 10% 0% 24% $90.66 0% --- $300 112% 73% 0% 27% 12% 83% 83% 46%Twin Butte $48.76 $6.99 ($10.97) 22% ($18.50) $26.28 9.3% 4.5% 9.4% 25% 18% 30% $83.83 0% --- $70 60% 100% 0% 0% 36% 106% 106% 27%Vermilion $73.61 ($0.55) ($3.96) 5% ($12.71) $56.40 4.7% 1.5% 6.2% 33% -8% 44% $83.16 7% $2.74 $450 86% 66% 17% 17% 41% 123% 107% 46%

INTERMEDIATES $42.71 $1.13 ($6.00) 14% ($10.80) $27.04 3.6% 6.3% 5.1% 34% 13% 33% $89.32 23% $3.82 $6,150 118% 49% 10% 41% 36% 130% 118% 19%JUNIORS $54.55 $2.27 ($11.03) 19% ($12.45) $33.34 23.3% 6.7% 23.5% 13% 8% 45% $83.83 1% n.a. $212 68% 23% 51% 26% 66% 129% 110% 58%Total/Average $1.46 ($7.48) 15% ($11.28) $28.89 8.5% 6.4% 9.7% 28% 11% 37% $88.71 16% $3.82 $6,362 103% 41% 22% 37% 45% 130% 116% 31%

P+P Reserve Reconciliation (mmboe) - 2011A2013E Production Production Growth Opening Develop. Closing Reserve Life Index (Years)

Oil Gas Total Oil Gas Total Gross Production Prod. Per Share (PPS) PPS + Dist. Reinvested PPS + Dist + Debt Adj'd Balance Net Drilling Balance Proved Proved(bbl/d) (mmcf/d) (boe/d) (% Gas) (bbl/d) (mmcf/d) (boe/d) (% Gas) 2012E 2013E 2012E 2013E 2012E 2013E 2012E 2013E YE/09A Acq's & Rev. Prod'n YE/10A Devp'd Proved + Prob.

ARC R R R R R R R R R R R R R R R R 485.1 (14.6) 132.0 (30.1) 572.4 R R RBaytex 46,432 45.4 54,000 14% 50,000 45.0 57,500 13% 8% 6% 5% 4% 10% 9% 15% 8% 229.0 11.4 30.0 (18.3) 252.2 3.2 8.1 13.0Bonavista 27,757 246.0 68,750 60% 28,503 240.0 68,500 58% -1% 0% -6% -4% 2% 3% 2% 2% 310.7 22.4 33.3 (25.1) 341.4 5.4 8.7 12.7Bonterra 4,694 12.3 6,750 30% 5,522 12.5 7,600 27% 7% 13% 5% 12% 12% 19% 8% 16% 39.4 - 4.1 (2.3) 41.1 8.2 11.5 16.9Crescent Point R R R R R R R R R R R R R R R R 379.5 5.3 66.9 (26.9) 424.8 R R REagle 2,865 0.2 2,900 1% 3,533 1.1 3,710 5% 111% 28% 54% 7% 70% 17% 62% 17% 7.1 - 1.1 (0.5) 7.7 3.0 5.0 10.4Enerplus 41,046 253.2 83,250 51% 45,500 258.0 88,500 49% 11% 6% 2% 4% 10% 9% 4% 4% 306.2 (5.1) 48.2 (27.5) 321.9 6.2 7.8 11.4Freehold 5,273 18.2 8,300 36% 5,056 17.1 7,900 36% 11% -5% 3% -7% 12% 0% 13% 0% 23.6 0.2 1.0 (2.6) 22.2 4.9 5.0 7.8Longview 4,890 8.8 6,350 23% 5,000 9.0 6,500 23% 1% 2% -28% 2% -23% 8% -19% 5% n.a n.a n.a n.a 37.9 6.4 9.1 16.5Parallel 4,070 12.5 6,151 34% 5,025 14.9 7,500 33% 86% 22% 26% 16% -37% -150% -41% -150% 29.4 4.6 (2.2) (1.0) 31.0 13.7 19.3 22.4Perpetual 3,565 106.1 21,250 83% 4,000 97.5 20,250 80% -10% -5% -10% -5% -10% -5% 126% -6% 80.9 (2.0) 10.1 (8.5) 80.4 3.4 4.5 9.0Pengrowth 47,377 239.2 87,250 46% 54,050 263.7 98,000 45% 18% 12% -12% -3% -6% 2% -8% 4% 317.5 (0.2) 39.3 (26.8) 329.7 6.7 8.4 11.8Penn West 107,851 354.9 171,500 35% 116,982 339.1 177,500 32% 2% 4% 1% 2% 10% 7% 3% 2% 661.0 (5.3) 123.3 (59.3) 719.0 6.2 8.1 11.7PetroBakken 38,292 38.7 45,250 14% 45,131 41.2 52,000 13% 9% 16% 8% 11% 16% 18% 29% 12% 169.8 (0.9) 47.8 (14.8) 201.9 4.2 6.8 11.5Peyto 5,477 241.6 45,750 88% 8,602 305.4 59,500 86% 29% 30% 22% 27% 27% 32% 18% 32% 259.7 2.2 73.5 (12.9) 322.4 8.9 15.7 22.4Progress 6,705 237.3 46,250 86% 6,750 262.5 50,500 87% 6% 9% 4% 8% 8% 11% 1% 4% 253.4 (8.8) 94.6 (15.9) 323.4 5.5 11.3 19.4Trilogy 15,516 128.9 37,000 58% 21,000 141.0 48,000 53% 32% 20% 31% 19% 33% 21% 30% 25% 78.2 - 20.6 (10.2) 88.6 5.5 6.2 8.6Twin Butte 11,625 15.5 14,208 18% 13,300 15.0 15,800 16% 87% 11% 26% 2% 35% 9% 21% 11% - - - - 35.6 4.2 6.3 10.8Vermilion 25,964 72.2 39,000 32% 29,800 71.7 42,750 29% 8% 10% 0% 7% 6% 12% -1% 12% 142.3 (0.2) 17.0 (12.8) 146.2 4.7 7.2 10.9

INTERMEDIATES 370,677 1,976 705,999 50% 415,840 2,078 770,600 48% 10% 10% 4% 7% 10% 12% 19% 9% 3,713 4 741 (292) 4,165 5.7 8.7 13.3JUNIORS 28,722 55 37,910 23% 31,914 57 41,410 23% 59% 12% 16% 4% 11% -23% 7% -23% 60 5 (0) (4) 134 6.4 8.9 13.6Total/Average 399,399 2,031 743,909 42% 447,753 2,135 812,010 40% 24% 11% 8% 6% 10% 1% 15% 0% 3,773 9 741 (296) 4,300 5.9 8.8 13.4

2012E Production

CFPS Sensitivity (2012E) Capital Expenditure Analysis (2012E) 2013E Payout RatiosCapEx Funded Via

Notes: Per share cash flow sensitivities are based on 2011 estimates and include the impact of hedging activity. Reserve Life Index is calculated using estimated year-end 2011 reserves divided by estimated Q4/11 production (adjusted for 2012 acquisitions YTD). Basic payout ratio is defined as cash dividends divided by cash flow from operations. Total payout ratio is defined as cash dividends plus development capital expenditures divided by each company's cash flow from operations. Total payout ratio (including the DRIP) is defined as cash dividends plus development capital expenditures divided by each company's cash flow from operations plus proceeds from the company's dividend reinvestment program (DRIP). Sustainable payout ratio is defined as a theoretical payout ratio which would yield flat production and be financially self-sustaining (i.e., fund 100% of capex from cash flow while spending sufficient capital to replace 100% of annual production declines). CFPS: Cash flow per share; CF: Cash flow. R=Restricted. Source: Company reports; CIBC estimates.



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Exhibit 62. Intermediate E&Ps – Base Versus Forward Data A. Base Pricing Assumptions Most Recent Dist./Div.

Share Net Asset Value (NAV) Total Bank Line 1-Yr.Price ($) Per Share Growth 2011A 2012E 2013E P/CF (x) EV/DACF (x) Cash Yield Core Risked P/Core P/Risked 2012E Payout Ratio Debt/CF Drawn Target Expected ($ per Share) Running08/13/12 2011A 2012E 2013E 2012E 2013E CDPS CDPS CDPS 2012E 2013E 2012E 2013E 2012E 2013E NAV ($) NAV ($) NAV NAV Basic Total 2012E 2012E Price Return Current Annualized Yield

ARC $23.27 R R R R R R R R R R R R R R R R R R R R R R R R $0.10 R RBaytex $44.09 $4.79 $4.26 $4.17 -11.0% -2.2% $2.42 $2.64 $2.64 10.3x 10.6x 10.7x 11.4x 6.0% 6.0% $14.96 $42.73 295% 103% 63% 138% 0.8x -7% $46.00 10% $0.22 $2.64 6.0%Bonavista $17.06 $3.44 $2.13 $2.36 -38.2% 11.1% $1.44 $1.44 $1.44 8.0x 7.2x 10.0x 9.2x 8.4% 8.4% $9.00 $22.45 190% 76% 53% 140% 3.0x 55% $22.00 37% $0.12 $1.44 8.4%Bonterra $47.20 $5.27 $4.04 $4.80 -23.4% 18.8% $3.06 $3.12 $3.12 11.7x 9.8x 13.1x 11.3x 6.6% 6.6% $15.00 $46.01 315% 103% 65% 134% 2.1x 93% $49.00 10% $0.26 $3.12 6.6%Crescent Point $41.10 R R R R R R R R R R R R R R R R R R R R R R R R $0.23 R REagle $9.73 $1.11 $1.76 $1.76 58.7% 0.0% $1.05 $1.05 $1.05 5.5x 5.5x 6.5x 6.5x 10.8% 10.8% $9.02 $11.95 108% 81% 60% 145% 1.0x 41% $12.00 34% $0.09 $1.05 10.8%Enerplus $14.49 $3.19 $3.17 $3.79 -0.7% 19.8% $2.16 $1.53 $1.08 4.6x 3.8x 6.5x 5.5x 10.6% 7.5% $10.44 $16.54 139% 88% 28% 127% 2.5x 31% $14.50 8% $0.09 $1.08 7.5%Freehold $19.30 $2.14 $1.29 $1.31 -40.0% 1.6% $1.68 $1.58 $1.44 15.0x 14.8x 15.1x 15.0x 8.2% 7.5% $7.69 n.a. 251% n.a. 110% 145% 0.4x 15% $20.00 10% $0.10 $1.16 6.0%Longview $6.35 $1.60 $1.24 $1.30 -22.4% 4.9% $0.49 $0.60 $0.60 5.1x 4.9x 6.7x 6.6x 9.4% 9.4% $8.03 $9.24 79% 69% 46% 128% 2.0x 57% $9.00 51% $0.05 $0.60 9.4%Parallel $6.26 $0.67 $0.76 $0.92 12.9% 21.5% $0.63 $0.89 $0.72 8.3x 6.8x 11.5x 9.2x 14.1% 11.5% $8.54 $7.09 73% 88% 78% 120% 5.6x 75% $6.25 14% $0.07 $0.89 14.1%Perpetual $1.13 $0.52 $0.37 $0.46 -28.6% 24.9% $0.20 $0.00 $0.00 3.0x 2.4x 6.1x 5.5x 0.0% 0.0% $2.03 $2.72 56% 42% 0% 95% 6.6x 45% $2.00 77% $0.00 $0.00 0.0%Pengrowth $6.76 $1.87 $1.23 $1.35 -34.3% 9.8% $0.84 $0.66 $0.48 5.5x 5.0x 6.9x 6.1x 9.8% 7.1% $4.32 $8.33 156% 81% 36% 112% 3.9x 15% $8.00 25% $0.04 $0.48 7.1%Penn West $14.14 $3.29 $2.41 $2.74 -26.7% 13.7% $1.08 $1.08 $1.08 5.9x 5.2x 8.1x 7.4x 7.6% 7.6% $6.64 $22.06 213% 64% 39% 156% 3.7x 68% $18.50 38% $0.09 $1.08 7.6%PetroBakken $12.72 $3.79 $3.14 $3.66 -17.1% 16.5% $0.96 $0.96 $0.96 4.0x 3.5x 6.1x 5.4x 7.5% 7.5% $8.13 $23.79 156% 53% 26% 148% 2.9x 33% $18.00 49% $0.08 $0.96 7.5%Peyto $20.76 $2.36 $2.27 $3.27 -4.0% 44.3% $0.72 $0.72 $0.72 9.2x 6.3x 10.7x 7.5x 3.5% 3.5% $9.32 $25.36 223% 82% 22% 106% 2.4x 96% $26.00 29% $0.06 $0.72 3.5%Progress $22.33 $0.99 $0.65 $0.97 -34.0% 48.5% $0.40 $0.40 $0.40 34.1x 23.0x 32.3x 23.2x 1.8% 1.8% $2.08 $11.54 1075% 193% 41% 199% 3.9x 27% $22.00 0% $0.03 $0.40 1.8%Trilogy $23.79 $1.89 $2.75 $4.23 45.6% 53.7% $0.42 $0.42 $0.42 8.6x 5.6x 11.3x 7.1x 1.8% 1.8% $6.44 $31.49 369% 76% 12% 83% 1.5x 71% $34.00 45% $0.04 $0.42 1.8%Twin Butte $2.56 $0.44 $0.59 $0.50 33.1% -15.6% $0.00 $0.16 $0.18 4.4x 5.2x 5.5x 6.4x 6.2% 7.0% $1.73 $2.46 148% 104% 36% 106% 1.5x 73% $2.65 14% $0.02 $0.27 10.5%Vermilion $46.00 $5.22 $5.23 $5.59 0.1% 6.9% $2.28 $2.28 $2.28 8.8x 8.2x 9.4x 8.9x 5.0% 5.0% $28.43 $40.73 162% 113% 41% 123% 1.2x 52% $48.00 9% $0.19 $2.28 5.0%Total/Average - INTERMEDIATES -14.4% 22.1% 9.5x 7.6x 10.9x 9.0x 5.7% 5.2% 279% 89% 36% 130% 2.9x 48% 28% 5.2%Total/Average - JUNIORS 8.5% 2.5% 7.7x 7.4x 9.0x 8.7x 9.8% 9.2% 132% 86% 66% 129% 2.1x 52% 25% 10.2%Total/Average -7.6% 16.4% 8.9x 7.5x 10.4x 9.0x 6.9% 6.4% 236% 88% 45% 130% 2.6x 49% 27% 6.7%

B. Forward Strip Pricing Assumptions (as at 08/10/12)Most Recent Dist./Div.

Share Net Asset Value (NAV) Total Bank Line ImpliedPrice ($) Per Share Growth 2011A 2012E 2013E P/CF (x) EV/DACF (x) Cash Yield Core Risked P/Core P/Risked 2012E Payout Ratio Debt/CF Drawn Target Potential ($ per Share) Running08/13/12 2011A 2012E 2013E 2012E 2013E CDPS CDPS CDPS 2012E 2013E 2012E 2013E 2012E 2013E NAV ($) NAV ($) NAV NAV Basic Total 2012E 2012E Price Return Current Annualized Yield

ARC $23.27 $2.95 R R R R $1.20 R R R R R R R R R R R R R R R R R R R R RBaytex $44.09 $4.79 $4.52 $4.71 -5.6% 4.2% $2.42 $2.64 $2.64 9.7x 9.4x 11.5x 11.2x 6.0% 6.0% $16.59 $44.21 266% 100% 58% 132% 0.7x -12% $46.00 10% $0.22 $2.64 6.0%Bonavista $17.06 $3.44 $2.29 $2.51 -33.3% 9.4% $1.44 $1.44 $1.44 7.4x 6.8x 10.2x 9.4x 8.4% 8.4% $8.08 $19.72 211% 87% 55% 152% 2.9x 53% $22.00 37% $0.12 $1.44 8.4%Bonterra $47.20 $5.27 $4.46 $5.37 -15.4% 20.3% $3.06 $3.12 $3.12 10.6x 8.8x 12.0x 10.3x 6.6% 6.6% $16.11 $53.83 293% 88% 70% 144% 1.8x 86% $49.00 10% $0.26 $3.12 6.6%Crescent Point $41.10 R R R R R R R R R R R R R R R R R R R R R R R R R R REagle $9.73 $1.11 $1.88 $1.69 70.2% -10.4% $1.05 $1.05 $1.05 5.2x 5.8x 6.1x 7.1x 10.8% 10.8% $9.84 $12.96 99% 75% 56% 125% 0.6x 32% $12.00 34% $0.09 $1.05 10.8%Enerplus $14.49 $3.19 $3.30 $3.94 3.6% 19.2% $2.16 $1.53 $1.08 4.4x 3.7x 7.2x 6.2x 10.6% 7.5% $10.32 $16.56 140% 87% 46% 178% 2.4x 28% $14.50 8% $0.09 $1.08 7.5%Freehold $19.30 $2.14 $1.42 $1.31 -33.8% -7.3% $1.68 $1.56 $1.44 13.6x 14.7x 14.6x 15.7x 8.1% 7.5% $8.48 n.a. 228% n.a. 110% 143% 0.4x 14% $20.00 10% $0.10 $1.16 6.0%Longview $6.35 $1.60 $1.48 $1.39 -7.2% -6.1% $0.49 $0.60 $0.60 4.3x 4.6x 8.4x 8.9x 9.4% 9.4% $8.75 $10.07 73% 63% 41% 109% 1.6x 56% $9.00 51% $0.05 $0.60 9.4%Parallel $6.26 $0.67 $0.81 $1.00 21.0% 23.9% $0.63 $0.83 $0.72 7.7x 6.2x 10.9x 9.7x 13.2% 11.5% $6.85 $7.29 91% 86% 101% 174% 5.3x 80% $6.25 14% $0.07 $0.89 14.1%Perpetual $1.13 $0.52 $0.41 $0.45 -21.7% 11.5% $0.20 $0.00 $0.00 2.8x 2.5x 6.0x 5.1x 0.0% 0.0% $0.33 $1.02 347% 111% 0% 108% 6.0x 42% $2.00 77% $0.00 $0.00 0.0%Pengrowth $6.76 $1.87 $1.25 $1.51 -33.0% 20.5% $0.84 $0.66 $0.48 5.4x 4.5x 8.3x 7.2x 9.8% 7.1% $5.81 $10.58 116% 64% 53% 165% 3.5x 68% $8.00 25% $0.04 $0.48 7.1%Penn West $14.14 $3.29 $2.72 $3.05 -17.3% 12.3% $1.08 $1.08 $1.08 5.2x 4.6x 8.2x 7.4x 7.6% 7.6% $7.35 $24.23 192% 58% 40% 158% 3.2x 55% $18.50 38% $0.09 $1.08 7.6%PetroBakken $12.72 $3.79 $3.46 $4.14 -8.8% 19.6% $0.96 $0.96 $0.96 3.7x 3.1x 5.9x 4.8x 7.5% 7.5% $9.33 $26.24 136% 48% 28% 161% 2.5x 35% $18.00 49% $0.08 $0.96 7.5%Peyto $20.76 $2.36 $2.34 $3.26 -1.1% 39.4% $0.72 $0.72 $0.72 8.9x 6.4x 9.2x 6.9x 3.5% 3.5% $7.06 $22.00 294% 94% 31% 167% 2.3x 94% $26.00 29% $0.06 $0.72 3.5%Progress $22.33 $0.99 $0.68 $0.92 -31.3% 35.5% $0.40 $0.40 $0.40 32.8x 24.2x 18.9x 14.9x 1.8% 1.8% $0.58 $6.53 3874% 342% 59% 228% 3.4x 26% $22.00 0% $0.03 $0.40 1.8%Trilogy $23.79 $1.89 $2.44 $3.78 28.8% 55.3% $0.42 $0.42 $0.42 9.8x 6.3x 12.0x 7.9x 1.8% 1.8% $5.64 $32.57 422% 73% 17% 123% 1.9x 78% $34.00 45% $0.04 $0.42 1.8%Twin Butte $2.56 $0.44 $0.58 $0.53 30.9% -7.8% $0.00 $0.16 $0.18 4.4x 4.8x 5.1x 5.8x 6.2% 7.0% $1.87 $2.69 137% 95% 28% 89% 1.5x 74% $2.65 14% $0.02 $0.27 10.5%Vermilion $46.00 $5.22 $5.77 $5.93 10.6% 2.8% $2.28 $2.28 $2.28 8.0x 7.8x 8.3x 8.2x 5.0% 5.0% $27.02 $39.88 170% 115% 39% 119% 1.1x 46% $48.00 9% $0.19 $2.28 5.0%Total/Average - INTERMEDIATES -10.4% 20.8% 9.0x 7.3x 9.8x 8.3x 5.7% 5.2% 539% 106% 41% 153% 2.6x 50% 28% 5.2%Total/Average - JUNIORS 16.2% -1.5% 7.0x 7.2x 9.0x 9.4x 9.5% 9.2% 125% 80% 67% 128% 1.9x 51% 25% 10.2%Total/Average -2.6% 14.3% 8.5x 7.3x 9.6x 8.6x 6.8% 6.4% 417% 99% 49% 146% 2.4x 50% 27% 6.7%Pricing Assumptions:

CIBC Base Assumptions Forward Strip2011A 2012E 2013E 2014E LT 2011A 2012E 2013E 2014E

Crude Oil (US$/bbl) $95.05 $90.00 $87.50 $85.00 $85.00 Crude Oil (US$/bbl) $95.05 $95.30 $94.70 $91.50Ed. Par (C$/bbl) $95.25 $81.82 $80.36 $82.40 $83.27 Ed. Par (C$/bbl) $95.25 $88.09 $87.82 $87.11Natural Gas (US$/mcf) $4.03 $2.70 $3.75 $4.50 $4.75 Natural Gas (US$/mcf) $4.03 $2.71 $3.57 $3.98Natural Gas (C$/mcf) $3.66 $2.39 $3.43 $4.08 $4.34 Natural Gas (C$/mcf) $3.65 $2.30 $3.13 $3.58F/X (US$/C$) $1.01 $0.99 $0.98 $0.98 $0.98 F/X (US$/C$) $1.01 $1.00 $1.00 $1.00

($ per Share, basic)Cash Flow from Operations

Cash Flow from Operations($ per Share, basic)

Notes: R=Restricted. Source: Bloomberg; Company Reports; CIBC World Markets



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Price Target Calculations

Exhibit 63. Risked NAV Simplified

Source: Company reports and CIB C World Markets Inc.

As illustrated above, our NAV valuation can be broken into three distinct

stages (or wedges):

1. Core NAV: The wedge is our Core after-tax NAV, which includes our 2P reserve valuation. We utilize a 9% discount rate.

2. Risked NAV: The second stage is our Risked NAV, which includes our Core NAV (2P reserve valuation) as well as the portion of unbooked resource potential that we believe investors should consider paying for today.

3. Bluesky NAV: The third stage is our Bluesky NAV (or Unrisked NAV), which includes our Risked NAV in addition to the incremental valuation that we believe is realistically obtainable by the company, but not yet concrete enough for investors to pay for today.

Tempering Our Risked NAVs And Setting Our Price Targets

While our price targets are generally in line with our Risked NAVs, in

some cases, we have applied a slight premium or a discount to our

Risked NAVs, which we view as justifiable by one of three key considerations:

1. Outlook for near-term production per unit growth.

2. Management’s track record for positive surprises.

3. Additional prospective plays on the horizon: do we see the potential for other plays with significant unbooked upside to “break into” our Risked NAV?

Key Risks To Price Targets The primary risks to the E&P companies achieving our price targets include commodity price volatility, rising operating costs, and execution on key growth projects. In addition to the aforementioned company-specific and commodity macros risks, there is risk around greenhouse gas (GHG) legislation, in particular for the oil sands due to the relatively high GHG emission intensity. The rig fire and oil spill in the Gulf of Mexico raise risk as to tighter offshore drilling legislation, costs, and potentially longer cycle times. Unconventional gas projects are heavily reliant on fraccing, which uses various fluid types to promote flow rates. There are emerging concerns around the safety of such frac fluids and, as such, there is growing risk of greater regulation of unconventional gas growth.


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IMPORTANT DISCLOSURES:

Analyst Certification: Each CIBC World Markets research analyst named on the front page of this research report, or at the beginning of any subsection hereof, hereby certifies that (i) the recommendations and opinions expressed herein accurately reflect such research analyst's personal views about the company and securities that are the subject of this report and all other companies and securities mentioned in this report that are covered by such research analyst and (ii) no part of the research analyst's compensation was, is, or will be, directly or indirectly, related to the specific recommendations or views expressed by such research analyst in this report.

Potential Conflicts of Interest: Equity research analysts employed by CIBC World Markets are compensated from revenues generated by various CIBC World Markets businesses, including the CIBC World Markets Investment Banking Department. Research analysts do not receive compensation based upon revenues from specific investment banking transactions. CIBC World Markets generally prohibits any research analyst and any member of his or her household from executing trades in the securities of a company that such research analyst covers. Additionally, CIBC World Markets generally prohibits any research analyst from serving as an officer, director or advisory board member of a company that such analyst covers.

In addition to 1% ownership positions in covered companies that are required to be specifically disclosed in this report, CIBC World Markets may have a long position of less than 1% or a short position or deal as principal in the securities discussed herein, related securities or in options, futures or other derivative instruments based thereon.

Recipients of this report are advised that any or all of the foregoing arrangements, as well as more specific disclosures set forth below, may at times give rise to potential conflicts of interest.


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Important Disclosure Footnotes for Companies Mentioned in this Report that Are Covered by CIBC World Markets Inc.: Stock Prices as of 08/15/2012: Advantage Oil & Gas Ltd. (2g) (AAV-TSX, C$3.26, Sector Performer) Anderson Energy Ltd. (2g) (AXL-TSX, C$0.29, Sector Underperformer) Angle Energy Inc. (2a, 2c, 2e, 2g, 7) (NGL-TSX, C$3.67, Sector Outperformer) ARC Resources Ltd. (2g, 7) (ARX-TSX, C$23.26, Restricted) Arcan Resources Ltd. (2a, 2c, 2e, 2g) (ARN-V, C$1.49, Sector Outperformer) Athabasca Oil Corp. (2g) (ATH-TSX, C$13.05, Sector Outperformer) Baytex Energy Corp. (2a, 2c, 2e, 2g, 7) (BTE-TSX, C$44.88, Sector Performer) Bellatrix Exploration Ltd. (2g) (BXE-TSX, C$3.24, Sector Outperformer) Birchcliff Energy Ltd. (2a, 2c, 2e, 2g) (BIR-TSX, C$7.09, Sector Performer) Bonavista Energy Corporation (2a, 2c, 2e, 2g) (BNP-TSX, C$16.91, Sector Outperformer) Bonterra Energy Corp. (2g) (BNE-TSX, C$45.33, Sector Performer) Canadian Natural Resources Ltd. (2a, 2c, 2d, 2e, 2g, 7, 9) (CNQ-TSX, C$30.56, Sector Outperformer) Canadian Oil Sands Limited (2a, 2b, 2d, 2e, 2g, 7) (COS-TSX, C$21.18, Sector Underperformer) Celtic Exploration Ltd. (2a, 2c, 2e, 2g) (CLT-TSX, C$17.17, Sector Outperformer) Cenovus Energy Inc. (2g, 7, 9) (CVE-TSX, C$32.59, Sector Outperformer) Cequence Energy Ltd. (2a, 2c, 2e, 2g) (CQE-TSX, C$1.24, Sector Performer) Coastal Energy Company (2g) (CEN-TSX, C$14.66, Sector Outperformer) Connacher Oil & Gas Limited (2g) (CLL-TSX, C$0.36, Sector Performer - Speculative) Crescent Point Energy Corp. (2a, 2c, 2e, 2g, 7) (CPG-TSX, C$41.00, Restricted) Crew Energy Inc. (2g) (CR-TSX, C$6.75, Sector Outperformer) Delphi Energy Corp. (2a, 2c, 2e, 2g) (DEE-TSX, C$1.28, Sector Performer) Eagle Energy Trust (2a, 2c, 2e, 2g) (EGL.UN-TSX, C$9.64, Sector Outperformer) Enbridge Inc. (2a, 2c, 2e, 2g, 7, 9) (ENB-TSX, C$39.50, Sector Outperformer) Encana Corporation (2a, 2c, 2d, 2e, 2g, 7, 9) (ECA-NYSE, US$22.42, Sector Performer) Enerplus Corporation (2a, 2c, 2e, 2g, 7) (ERF-TSX, C$14.76, Sector Underperformer) Fairborne Energy Ltd. (2g) (FEL-TSX, C$1.63, Sector Performer) Freehold Royalties Ltd. (2a, 2c, 2e, 2g) (FRU-TSX, C$19.27, Sector Performer) Gran Tierra Energy Inc. (2g) (GTE-TSX, C$4.81, Sector Outperformer) Husky Energy Inc. (2a, 2c, 2e, 2g) (HSE-TSX, C$26.87, Sector Performer) Imperial Oil Limited (2g) (IMO-TSX, C$45.88, Sector Underperformer) Legacy Oil + Gas Inc. (2g, 7) (LEG-TSX, C$6.76, Sector Outperformer) Longview Oil Corp. (2a, 2c, 2e, 2g) (LNV-TSX, C$6.33, Sector Performer) MEG Energy Corp. (2a, 2e, 2g) (MEG-TSX, C$39.48, Sector Outperformer) Nexen Inc. (2a, 2c, 2e, 2g, 7) (NXY-TSX, C$25.40, Sector Underperformer) NuVista Energy Ltd. (2g) (NVA-TSX, C$4.40, Sector Outperformer) Painted Pony Petroleum Ltd. (2a, 2c, 2e, 2g) (PPY-V, C$10.11, Sector Outperformer) Parallel Energy Trust (2a, 2c, 2e, 2g) (PLT.UN-TSX, C$5.75, Sector Outperformer) Paramount Resources Ltd. (2a, 2c, 2e, 2g) (POU-TSX, C$25.24, Sector Performer) Pembina Pipeline Corporation (2g, 7) (PPL-TSX, C$27.05, Sector Outperformer) Pengrowth Energy Corporation (2a, 2c, 2e, 2g) (PGF-TSX, C$6.94, Sector Performer) Penn West Petroleum Ltd. (2g, 7) (PWT-TSX, C$14.04, Sector Outperformer) Perpetual Energy Inc. (2g) (PMT-TSX, C$1.18, Sector Outperformer) PetroBakken Energy Ltd. (2a, 2e, 2g) (PBN-TSX, C$13.01, Sector Outperformer) Petrobank Energy And Resources Ltd. (2g) (PBG-TSX, C$12.16, Sector Outperformer) Peyto Exploration & Development Corp. (2a, 2c, 2e, 2g) (PEY-TSX, C$21.21, Sector Outperformer) Pinecrest Energy Inc. (2g, 7) (PRY-V, C$1.87, Sector Outperformer) Progress Energy Resources Corp. (2g) (PRQ-TSX, C$22.32, Sector Performer)


263

Important Disclosure Footnotes for Companies Mentioned in this Report that Are Covered by CIBC World Markets Inc.: (Continued) Stock Prices as of 08/15/2012: RMP Energy Inc. (2a, 2c, 2e, 2g) (RMP-TSX, C$1.76, Sector Performer) Suncor Energy Inc. (2g, 3a, 3c, 7, 9) (SU-TSX, C$31.59, Sector Outperformer) Surge Energy Inc. (2a, 2c, 2e, 2g) (SGY-TSX, C$8.12, Sector Outperformer) Talisman Energy Inc. (2a, 2c, 2e, 2g, 7) (TLM-NYSE, US$13.40, Sector Outperformer) Tourmaline Oil Corp. (2a, 2c, 2e, 2g) (TOU-TSX, C$28.62, Restricted) TransCanada Corp. (2g, 7) (TRP-TSX, C$45.25, Sector Performer) Trilogy Energy Corp. (2a, 2c, 2e, 2g) (TET-TSX, C$24.10, Sector Outperformer) Twin Butte Energy Ltd. (2g, 7) (TBE-TSX, C$2.67, Sector Performer) Vermilion Energy Inc. (2a, 2c, 2e, 2g, 7) (VET-TSX, C$45.89, Sector Performer) Vero Energy Inc. (2g) (VRO-TSX, C$1.87, Sector Performer) WestFire Energy Ltd. (2g) (WFE-TSX, C$3.89, Sector Performer) Whitecap Resources Inc. (2g) (WCP-TSX, C$7.39, Sector Outperformer)

Companies Mentioned in this Report that Are Not Covered by CIBC World Markets Inc.: Stock Prices as of 08/15/2012: Abu Dhabi National Energy Company (TAQA-DU, [AED]1.24, Not Rated) American Capital Ltd. (ACAS-NASDAQ, US$11.03, Not Rated) Anadarko Petroleum Corp. (APC-NYSE, US$69.29, Not Rated) Apache Corp. (APA-NYSE, US$87.68, Not Rated) Argosy Energy Inc. (GSY-TSX, C$0.24, Not Rated) Arsenal Energy Inc. (AEI-TSX, C$0.46, Not Rated) Artek Exploration Ltd. (RTK-TSX, C$2.00, Not Rated) Atikwa Resources Inc. (ATK-V, C$0.03, Not Rated) Atlas Energy Inc. (ATLS-NYSE, US$34.02, Not Rated) AvenEx Energy Corp. (AVF-TSX, C$2.75, Not Rated) Barnwell Industries, Inc. (BRN-NASDAQ, US$2.99, Not Rated) BG Group PLC (BG-L, p13.23, Not Rated) BHP Billiton (BHP-NYSE, US$68.24, Not Rated) Bill Barrett Corporation (BBG-NYSE, US$22.67, Not Rated) BlackPearl Resources Inc. (PXX-TSX, C$3.31, Not Rated) BNK Petroleum Inc. (BKX-TSX, C$1.06, Not Rated) Border Petroleum Corp. (BOR-V, C$0.16, Not Rated) Bowood Energy Inc. (BWD-V, C$0.06, Not Rated) BP p.l.c. (BP-NYSE, US$42.44, Not Rated) Cabot Oil & Gas Corp. (COG-NYSE, US$42.42, Not Rated) Carrizo Oil & Gas Inc. (CRZO-NASDAQ, US$25.24, Not Rated) Charger Energy Corp. (CHX-V, C$0.57, Not Rated) Cheniere Energy Inc. (LNG-AMEX, US$14.48, Not Rated) Chesapeake Energy Corporation (CHK-NYSE, US$18.87, Not Rated) Chevron Corporation (CVX-NYSE, US$112.49, Not Rated) China Petroleum And Chemical Corporation (SNP-NYSE, US$95.91, Not Rated) Chinook Energy Inc. (CKE-TSX, C$1.48, Not Rated) Chubu Electric Power Company Inc. (9502-T, ¥986.00, Not Rated) Cimarex Energy Co. (XEC-NYSE, US$61.98, Not Rated)


264

Companies Mentioned in this Report that Are Not Covered by CIBC World Markets Inc.: (Continued) Stock Prices as of 08/15/2012: CNOOC Ltd. (CEO-NYSE, US$200.41, Not Rated) Compton Petroleum Corporation (CMT-TSX, C$1.24, Not Rated) Comstock Resources, Inc. (CRK-NYSE, US$17.35, Not Rated) Concho Resources Inc. (CXO-NYSE, US$95.60, Not Rated) ConocoPhillips (COP-NYSE, US$57.14, Not Rated) Continental Resources, Inc. (CLR-NYSE, US$72.61, Not Rated) Crocotta Energy Inc. (CTA-TSX, C$2.77, Not Rated) Crosstex Energy LP (XTEX-NASDAQ, US$15.60, Not Rated) DCP MIDSTREAM LP (DPM-NYSE, US$43.08, Not Rated) Deethree Exploration Ltd. (DTX-TSX, C$4.67, Not Rated) Denbury Resources Inc (DNR-NYSE, US$15.44, Not Rated) Devon Energy Corp. (DVN-NYSE, US$58.38, Not Rated) Dow Chemical (DOW-NYSE, US$29.52, Not Rated) DTE Energy Company (DTE-NYSE, US$60.10, Not Rated) Enbridge Energy Partners, L.P. (EEP-NYSE, US$29.61, Not Rated) Energen Corporation (EGN-NYSE, US$52.31, Not Rated) Energy Transfer Partners LP (ETP-NYSE, US$43.75, Not Rated) Eni S.p.A. (E-NYSE, US$43.98, Not Rated) Enterprise Products Partners L (EPD-NYSE, US$52.40, Not Rated) EOG Resources, Inc. (EOG-NYSE, US$110.58, Not Rated) EQT Corp. (EQT-NYSE, US$55.08, Not Rated) Equal Energy Ltd. (EQU-TSX, C$3.31, Not Rated) EXCO Resources, Inc. (XCO-NYSE, US$7.41, Not Rated) ExxonMobil Corporation (XOM-NYSE, US$88.00, Not Rated) Forest Oil Corporation (FST-NYSE, US$7.25, Not Rated) Formosa Plastics Group (1301-TW, [TWD]84.60, Not Rated) GAIL India Ltd. (GAIL-BO, [INR]375.00, Not Rated) GMX Resources Inc. (GMXR-NYSE, US$0.82, Not Rated) Goodrich Petroleum (GDP-NYSE, US$12.82, Not Rated) Guide Exploration Ltd. (GO-TSX, C$1.70, Not Rated) Gulfport Energy Corporation (GPOR-NASDAQ, US$25.55, Not Rated) Harvest Operations Corp. (HTE.DB.G-TSX, C$104.00, Not Rated) Hess (HES-NYSE, US$49.42, Not Rated) Inpex Corp. (1605-T, ¥472500.00, Not Rated) Insignia Energy Ltd. (ISN-TSX, C$0.70, Not Rated) Kinder Morgan Energy Partners (KMP-NYSE, US$82.41, Not Rated) Kinder Morgan, Inc. (KMI-NYSE, US$34.87, Not Rated) Kodiak Oil & Gas Corp. (KOG-NYSE, US$8.94, Not Rated) Korea Gas Corporation (036460-KS, [KRW]51600.00, Not Rated) Linn Energy, LLC (LINE-NASDAQ, US$39.28, Not Rated) Lone Pine Resources Inc. (LPR-TSX, C$1.34, Not Rated) LyondellBasell Industries NV (LYB-NYSE, US$47.50, Not Rated) Mako Energy Ltd. (MKE-AUS, A$0.06, Not Rated) Manitok Energy Inc. (MEI-V, C$1.86, Not Rated) Marathon Oil Corp. (MRO-NYSE, US$27.25, Not Rated) MarkWest Energy Partners, LP (MWE-AMEX, US$48.70, Not Rated) Mitsubishi Corp (8058-T, ¥1555.00, Not Rated)


265

Companies Mentioned in this Report that Are Not Covered by CIBC World Markets Inc.: (Continued) Stock Prices as of 08/15/2012: Murphy Oil (MUR-NYSE, US$54.13, Not Rated) National Fuel Gas (NFG-NYSE, US$50.67, Not Rated) Noble Energy Inc. (NBL-NYSE, US$89.71, Not Rated) Oasis Petroleum Inc. (OAS-NYSE, US$30.43, Not Rated) Occidental Petroleum (OXY-NYSE, US$88.99, Not Rated) Oneok Partners LP (OKS-NYSE, US$56.70, Not Rated) Open Range Energy Corporation (ONR-TSX, C$1.53, Not Rated) Osaka Gas Co Ltd (9532-T, ¥338.00, Not Rated) Pace Oil & Gas Limited (PCE-TSX, C$2.86, Not Rated) PDC Energy Inc. (PDCE-NASDAQ, US$26.63, Not Rated) Penn Virginia Corporation (PVA-NYSE, US$7.41, Not Rated) Petro-Reef Resources Ltd. (PER-TSX, C$0.16, Not Rated) Petronas Gas (PGAS-KL, [MYR]19.92, Not Rated) PetroQuest Energy, Inc. (PQ-NYSE, US$6.46, Not Rated) Pioneer Natural Resources (PXD-NYSE, US$98.01, Not Rated) Plains Exploration & Production Co. (PXP-NYSE, US$40.97, Not Rated) QEP Resources, Inc. (QEP-NYSE, US$26.64, Not Rated) Questerre Energy Corp. (QEC-TSX, C$0.67, Not Rated) Quicksilver Resources Inc. (KWK-NYSE, US$4.08, Not Rated) Range Resources Corp (RRC-NYSE, US$66.75, Not Rated) Redwater Energy Corp. (RED-TSX, C$0.19, Not Rated) Regency Energy Partners LP (RGP-NYSE, US$22.94, Not Rated) Reliance Industries Limited (500325-BO, [INR]780.30, Not Rated) Renegade Petroleum Ltd. (RPL-V, C$2.72, Not Rated) Rosetta Resouces Inc. (ROSE-NASDAQ, US$44.67, Not Rated) Royal Dutch Shell (RDS.A-NYSE, US$70.93, Not Rated) Sandridge Energy (SD-NYSE, US$6.43, Not Rated) Sasol (SSL-NYSE, US$42.30, Not Rated) Second Wave Petroleum Inc. (SCS-TSX, C$0.92, Not Rated) SM Energy Co. (SM-NYSE, US$47.58, Not Rated) Sonde Resources Corp. (SOQ-TSX, C$0.91, Not Rated) Southwestern Energy Co. (SWN-NYSE, US$31.99, Not Rated) Spartan Oil Corp. (STO-TSX, C$3.70, Not Rated) Statoil ASA (STO-NYSE, US$25.18, Not Rated) Storm Resources Ltd. (SRX-V, C$1.70, Not Rated) Sunoco Inc. (SUN-NYSE, US$47.50, Not Rated) Sunoco Logistics Partners LP (SXL-NYSE, US$42.52, Not Rated) Sure Energy Inc. (SHR-TSX, C$0.71, Not Rated) Targa Resources Corp. (TRGP-NYSE, US$42.61, Not Rated) Terra Energy Corp (TT-TSX, C$0.27, Not Rated) Torquay Oil Corp. (TOC.A-V, C$0.18, Not Rated) Total S.A. (TOT-NYSE, US$49.19, Not Rated) Transmontaigne Inc (TLP-NYSE, US$36.82, Not Rated) TriOil Resources Ltd. (TOL-V, C$1.96, Not Rated) Unit Corporation (UNT-NYSE, US$41.20, Not Rated) Waldron Energy Corporation (WDN-TSX, C$0.59, Not Rated) WESTLAKE CHEMICAL CORP (WLK-NYSE, US$66.69, Not Rated)


266

Companies Mentioned in this Report that Are Not Covered by CIBC World Markets Inc.: (Continued) Stock Prices as of 08/15/2012: Whiting Petroleum Corporation (WLL-NYSE, US$44.61, Not Rated) Williams Partners LP (WPZ-NYSE, US$51.04, Not Rated) WPX Energy Inc. (WPX-NYSE, US$14.83, Not Rated) Yangarra Resources Ltd. (YGR-V, C$0.32, Not Rated) Yoho Resources Inc. (YO-V, C$1.83, Not Rated) Zargon Oil & Gas Ltd. (ZAR-TSX, C$8.85, Not Rated) Important disclosure footnotes that correspond to the footnotes in this table may be found in the "Key to Important Disclosure Footnotes" section of this report.


267

Key to Important Disclosure Footnotes: 1 CIBC World Markets Corp. makes a market in the securities of this company. 2a This company is a client for which a CIBC World Markets company has performed investment banking services

in the past 12 months. 2b CIBC World Markets Corp. has managed or co-managed a public offering of securities for this company in the

past 12 months. 2c CIBC World Markets Inc. has managed or co-managed a public offering of securities for this company in the

past 12 months. 2d CIBC World Markets Corp. has received compensation for investment banking services from this company in

the past 12 months. 2e CIBC World Markets Inc. has received compensation for investment banking services from this company in the

past 12 months. 2f CIBC World Markets Corp. expects to receive or intends to seek compensation for investment banking services

from this company in the next 3 months. 2g CIBC World Markets Inc. expects to receive or intends to seek compensation for investment banking services

from this company in the next 3 months. 3a This company is a client for which a CIBC World Markets company has performed non-investment banking,

securities-related services in the past 12 months. 3b CIBC World Markets Corp. has received compensation for non-investment banking, securities-related services

from this company in the past 12 months. 3c CIBC World Markets Inc. has received compensation for non-investment banking, securities-related services

from this company in the past 12 months. 4a This company is a client for which a CIBC World Markets company has performed non-investment banking,

non-securities-related services in the past 12 months. 4b CIBC World Markets Corp. has received compensation for non-investment banking, non-securities-related

services from this company in the past 12 months. 4c CIBC World Markets Inc. has received compensation for non-investment banking, non-securities-related

services from this company in the past 12 months. 5a The CIBC World Markets Corp. analyst(s) who covers this company also has a long position in its common

equity securities. 5b A member of the household of a CIBC World Markets Corp. research analyst who covers this company has a

long position in the common equity securities of this company. 6a The CIBC World Markets Inc. fundamental analyst(s) who covers this company also has a long position in its

common equity securities. 6b A member of the household of a CIBC World Markets Inc. fundamental research analyst who covers this

company has a long position in the common equity securities of this company. 7 CIBC World Markets Corp., CIBC World Markets Inc., and their affiliates, in the aggregate, beneficially own 1%

or more of a class of equity securities issued by this company. 8 An executive of CIBC World Markets Inc. or any analyst involved in the preparation of this research report has

provided services to this company for remuneration in the past 12 months. 9 A senior executive member or director of Canadian Imperial Bank of Commerce ("CIBC"), the parent company

to CIBC World Markets Inc. and CIBC World Markets Corp., or a member of his/her household is an officer, director or advisory board member of this company or one of its subsidiaries.

10 Canadian Imperial Bank of Commerce ("CIBC"), the parent company to CIBC World Markets Inc. and CIBC World Markets Corp., has a significant credit relationship with this company.

11 The equity securities of this company are restricted voting shares. 12 The equity securities of this company are subordinate voting shares. 13 The equity securities of this company are non-voting shares. 14 The equity securities of this company are limited voting shares.


268

CIBC World Markets Inc. Price Chart

For price and performance information charts required under NYSE and NASD rules, please visit CIBC on the web at http://apps.cibcwm.com/sec2711 or write to CIBC World Markets Inc., Brookfield Place, 161 Bay Street, 4th Floor, Toronto, Ontario M5J 2S8, Attn: Research Disclosure Chart Request.

CIBC World Markets Inc. Stock Rating System

Abbreviation Rati ng Description

Stock Ratings

SO Sector Outperformer Stock is expected to outperform the sector during the next 12-18 months.

SP Sector Performer Stock is expected to perform in line with the sector during the next 12-18 months.

SU Sector Underperformer Stock is expected to underperform the sector during the next 12-18 months.

NR Not Rated CIBC World Markets does not maintain an investment recommendation on the stock.

R Restricted CIBC World Markets is restricted*** from rating the stock.

Sector Weightings**

O Overweight Sector is expected to outperform the broader market averages.

M Market Weight Sector is expected to equal the performance of the broader market averages.

U Underweight Sector is expected to underperform the broader market averages.

NA None Sector rating is not applicable.

**Broader market averages refer to the S&P 500 in the U.S. and the S&P/TSX Composite in Canada. "Speculative" indicates that an investment in this security involves a high amount of risk due to volatility and/or liquidity issues. ***Restricted due to a potential conflict of interest.

Ratings Distribution*: CIBC World Markets Inc. Coverage Universe

(as of 15 Aug 2012) Count Percent Inv. Banking Relationships Count Percent

Sector Outperformer (Buy) 147 41.6% Sector Outperformer (Buy) 145 98.6%

Sector Performer (Hold/Neutral) 161 45.6% Sector Performer (Hold/Neutral) 159 98.8%

Sector Underperformer (Sell) 29 8.2% Sector Underperformer (Sell) 27 93.1%

Restricted 15 4.2% Restricted 15 100.0%

Ratings Distribution: Oil & Gas - Large Cap Coverage Universe

(as of 15 Aug 2012) Count Percent Inv. Banking Relationships Count Percent

Sector Outperformer (Buy) 7 53.8% Sector Outperformer (Buy) 7 100.0%

Sector Performer (Hold/Neutral) 3 23.1% Sector Performer (Hold/Neutral) 3 100.0%

Sector Underperformer (Sell) 3 23.1% Sector Underperformer (Sell) 3 100.0%

Restricted 0 0.0% Restricted 0 0.0%

Oil & Gas - Large Cap Sector includes the following tickers: ATH, CLL, CNQ, COS, CVE, ECA, HSE, IMO, MEG, NXY, PBG, SU, TLM.

*Although the investment recommendations within the three-tiered, relative stock rating system utilized by CIBC World Markets Inc. do not correlate to buy, hold and sell recommendations, for the purposes of complying with NYSE and NASD rules, CIBC World Markets Inc. has assigned buy ratings to securities rated Sector Outperformer, hold ratings to securities rated Sector Performer, and sell ratings to securities rated Sector Underperformer without taking into consideration the analyst's sector weighting.

Important disclosures required by IIROC Rule 3400, including potential conflicts of interest information, our system for rating investment opportunities and our dissemination policy can be obtained by visiting CIBC World Markets on the web at http://researchcentral.cibcwm.com under 'Quick Links' or by writing to CIBC World Markets Inc., Brookfield Place, 161 Bay Street, 4th Floor, Toronto, Ontario M5J 2S8, Attention: Research Disclosures Request.


269

Legal Disclaimer

This report is issued and approved for distribution by (a) in Canada, CIBC World Markets Inc., a member of the Investment Industry Regulatory Organization of Canada (“IIROC”), the Toronto Stock Exchange, the TSX Venture Exchange and a Member of the Canadian Investor Protection Fund, (b) in the United Kingdom, CIBC World Markets plc, which is regulated by the Financial Services Authority ("FSA"), and (c) in Australia, CIBC Australia Limited, a member of the Australian Stock Exchange and regulated by the ASIC (collectively, "CIBC World Markets") and (d) in the United States either by (i) CIBC World Markets Inc. for distribution only to U.S. Major Institutional Investors (“MII”) (as such term is defined in SEC Rule 15a-6) or (ii) CIBC World Markets Corp., a member of the Financial Industry Regulatory Authority (“FINRA”). U.S. MIIs receiving this report from CIBC World Markets Inc. (the Canadian broker-dealer) are required to effect transactions (other than negotiating their terms) in securities discussed in the report through CIBC World Markets Corp. (the U.S. broker-dealer). This report is provided, for informational purposes only, to institutional investor and retail clients of CIBC World Markets in Canada, and does not constitute an offer or solicitation to buy or sell any securities discussed herein in any jurisdiction where such offer or solicitation would be prohibited. This document and any of the products and information contained herein are not intended for the use of private investors in the United Kingdom. Such investors will not be able to enter into agreements or purchase products mentioned herein from CIBC World Markets plc. The comments and views expressed in this document are meant for the general interests of wholesale clients of CIBC Australia Limited. The securities mentioned in this report may not be suitable for all types of investors. This report does not take into account the investment objectives, financial situation or specific needs of any particular client of CIBC World Markets. Recipients should consider this report as only a single factor in making an investment decision and should not rely solely on investment recommendations contained herein, if any, as a substitution for the exercise of independent judgment of the merits and risks of investments. The analyst writing the report is not a person or company with actual, implied or apparent authority to act on behalf of any issuer mentioned in the report. Before making an investment decision with respect to any security recommended in this report, the recipient should consider whether such recommendation is appropriate given the recipient's particular investment needs, objectives and financial circumstances. CIBC World Markets suggests that, prior to acting on any of the recommendations herein, Canadian retail clients of CIBC World Markets contact one of our client advisers in your jurisdiction to discuss your particular circumstances. Non-client recipients of this report who are not institutional investor clients of CIBC World Markets should consult with an independent financial advisor prior to making any investment decision based on this report or for any necessary explanation of its contents. CIBC World Markets will not treat non-client recipients as its clients solely by virtue of their receiving this report. Past performance is not a guarantee of future results, and no representation or warranty, express or implied, is made regarding future performance of any security mentioned in this report. The price of the securities mentioned in this report and the income they produce may fluctuate and/or be adversely affected by exchange rates, and investors may realize losses on investments in such securities, including the loss of investment principal. CIBC World Markets accepts no liability for any loss arising from the use of information contained in this report, except to the extent that liability may arise under specific statutes or regulations applicable to CIBC World Markets. Information, opinions and statistical data contained in this report were obtained or derived from sources believed to be reliable, but CIBC World Markets does not represent that any such information, opinion or statistical data is accurate or complete (with the exception of information contained in the Important Disclosures section of this report provided by CIBC World Markets or individual research analysts), and they should not be relied upon as such. All estimates, opinions and recommendations expressed herein constitute judgments as of the date of this report and are subject to change without notice. Nothing in this report constitutes legal, accounting or tax advice. Since the levels and bases of taxation can change, any reference in this report to the impact of taxation should not be construed as offering tax advice on the tax consequences of investments. As with any investment having potential tax implications, clients should consult with their own independent tax adviser. This report may provide addresses of, or contain hyperlinks to, Internet web sites. CIBC World Markets has not reviewed the linked Internet web site of any third party and takes no responsibility for the contents thereof. Each such address or hyperlink is provided solely for the recipient's convenience and information, and the content of linked third-party web sites is not in any way incorporated into this document. Recipients who choose to access such third-party web sites or follow such hyperlinks do so at their own risk. Although each company issuing this report is a wholly owned subsidiary of Canadian Imperial Bank of Commerce ("CIBC"), each is solely responsible for its contractual obligations and commitments, and any securities products offered or recommended to or purchased or sold in any client accounts (i) will not be insured by the Federal Deposit Insurance Corporation ("FDIC"), the Canada Deposit Insurance Corporation or other similar deposit insurance, (ii) will not be deposits or other obligations of CIBC, (iii) will not be endorsed or guaranteed by CIBC, and (iv) will be subject to investment risks, including possible loss of the principal invested. The CIBC trademark is used under license. © 2012 CIBC World Markets Inc. All rights reserved. Unauthorized use, distribution, duplication or disclosure without the prior written permission of CIBC World Markets is prohibited by law and may result in prosecution.

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