Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
March 16, 2015
Canadian Energy
MORGAN STANLEY & CO. LLC
Benny Wong
Benny.Wong@morganstanley.com
+1 212 761-9626
Evan Calio
2015 Calgary Energy Summit: Looking To
Push The Cost Curve Down
Evan.Calio@morganstanley.com
+1 212 761-6472
Ole Slorer
Ole.Slorer@morganstanley.com
+1 212 761-6198
Brian Lasky
CDN companies are preparing for a lower-for-longer crude price
scenario. Expect spring break-up to trigger further service cost
deflation while producers look internally for sustainable efficiencies.
Our 2015 Calgary Energy Summit on March 9-11th provided significant color
on the state of the Canadian E&P, service, and midstream markets. We
highlight key takeaways below, with company-specific highlights within the
report.
Canadian Producers: Companies are preparing for a lower-for-longer crude
price scenario. Many believe there is a real chance of more near-term pain in
commodity prices and a few expressed views that long-term crude prices will
be in the range of ~US$60-70/bbl. As such, our roundtable discussions were
dominated by the topics of: (1) the expectation for service cost reductions &
efficiencies (20-30% in E&P and 5-10% in oil sands by YE’15) with the majority
to materialize after spring break-up; (2) the need to attack internal cost
structures and rethink development/construction to further realize efficiencies
that are sustainable beyond pure services pricing, which is largely cyclical; (3)
the continued focus on capital preservation through reduced spend and
dividends; and (4) discussed ways to improve liquidity through the equity and
debt markets (ie. ARX, ECA, BTE, CVE, HSE) and non-core asset monetization (ie.
CNQ, CVE, ERF). Amongst E&Ps we see a bifurcation of companies that can
continue investment profitably and those that need to pare back spending as
much as possible. In the oil sands, with near-term investment being difficult to
stop, the focus is on cost and balance sheet management while being price
takers. For those that can afford it, companies that invest through the
downturn will coming out the other side with improved cost structures and
project economics.
Oil Field Services: Canadian services pricing looks somewhat more resilient
than US services, though visibility on activity and pricing trajectory beyond
breakup is virtually nonexistent. General consensus among Canadian E&Ps
and TCW/CFW was that 10% pricing declines have already occurred and an
additional 5-10% service cost reductions seemed reasonable by year-end.
However, overall E&P cost reduction targets of 20-30% assume meaningful
efficiency gains, so service companies/drillers may face more pricing pressure
in 2H15 if efficiencies do not materialize. Interestingly, Canadian E&Ps
generally see larger opportunity for savings on completions costs vs. the US
where we believe drillers have seen and will continue to see larger rate
reductions due to higher peak margins. Service intensity, however, seems
likely to remain high if not trend higher throughout 2015 as E&Ps continue to
believe that high stage counts and proppant loadings improve well economics.
Visibility beyond spring break-up for all parties was extremely limited, and
Brian.Lasky@morganstanley.com
+1 212 761-7249
Drew Venker, CFA
Drew.Venker@morganstanley.com
+1 212 761-3729
Connor Lynagh
Connor.Lynagh@morganstanley.com
+1 212 296-8145
Canadian Energy
North America
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Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
CFW, TCW and PDS are already seeing an early break-up underway without a
clear path for a rebound in 2H15.
Midstream & Pipelines: We continue to see significant long-term
opportunity in Canada (both oil and gas), but near-term headwinds prevail for
new outlets for hydrocarbons due to low commodity prices and delayed
project approvals. Meanwhile, near-term bottlenecks have become less
pressing given a slowdown in drilling. While producers noted current
midstream contracts remain untouchable, they have seen the competitive
dynamics heat up for new business, pressuring incremental risk-adjusted
returns. Oil: Increased rail continues to debottleneck capacity while producers
await additional pipeline capacity coming online. The near-term startup of
Alberta Clipper should help alleviate the current apportionment at PADD II, but
further debottlenecking of the Enbridge system (with downstream investment)
and Keystone XL remain the ultimate market clearing mechanisms. Most
producers expect Keystone to get done with only three out of the four major
pipelines (Keystone, TMX, Gateway, and Energy East) needed for now (until the
post 2021 timeframe) with Keystone, TMX and Energy East most likely.
Natural Gas: Natural gas takeaway is getting tight as the TransCanada
mainline is getting contracted up along with Alliance (some producers
effectively giving liquids away for free). Producers have been liquids
constrained to get out of the Montney/Duvernay until Pembina’s expansion
comes online in the 2017 time frame. The Montney/Duvernay regions will
require significant G&P infrastructure as producers ramp production, but nearterm needs are more muted given the slowdown in drilling.
US E&P Comparison and Read-through: Canadian E&Ps differ primarily
from those in the US due to a preference for more conservative balance sheets
and a greater focus on returning cash to shareholders. However, the current
message from the Canadian E&Ps has many similarities to those in the US: (1)
many are deferring completions due to low commodity prices, (2) most prefer
to wait until commodity prices rebound before accelerating activity, and (3)
bid-ask spreads still remain relatively wide (although converging given recent
deals in Canada) for both asset and corporate level transactions. One of the
most significant takeaways from the US perspective is that the economics of
the Montney remain compelling even at today’s commodity prices. The
Montney’s returns of 50%+ at 2015 strip prices are generally in excess of the
Marcellus-Utica at 15% on average. Because of the wide gap in IRRs, Montney
volume growth is less likely to be impacted by lower oil gas prices than in the
Marcellus and Utica, two plays that have been allocated significantly less
capital in 2015.
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Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
Company Highlights
Athabasca Oil Corp.
Rob Broen, President & COO
Key Takeaways:
1. Anticipating service costs to come down after spring break-up with savings in the Duvernay further
driven by pad drilling
Currently able to negotiate slightly lower service rates but expect further cost reductions and
improvements in efficiencies in the summer with access to better crews and equipment.
ATH has not locked in rig costs so will be able to take advantage of the deflation
The company sees more potential for cost to come down further on the completions side especially
with multi-well pad development
As such ATH is deferring C$58mm in capita (4 completions and one hz drill) into 2H15 to optimize
economics
The industry has repeatedly proven that pad drilling in development provides a step change in play
costs and economics. ATH believes the Duvernay is on the same path as peers like Encana/Petrochina
and Shell are all moving towards pad drilling.
ATH is targeting long term Duvernay D&C costs to be sub C$10mln in the shallower window (Kaybob
East), ~C$10mm at Kaybob West and in the low teens at Simonette/Saxon (deepest and most over
pressure part of the play).
2. ATH has confidence in Hangingstone success
Have confidence in the success of the SAGD project as ATH has drilled approximately 1 vertical
delineation well for every producer (3x regulatory requirement). Extra SAGD well pairs (25 wells pairs
vs. 18 required) and overbuilt steam capacity provide operating cushion as well.
Potential for a Phase 2 (8 mbbl/d) debottleneck expansion. Investment decision will be made in 2016
but to compete with Duvernay economics.
ATH expects to have regulatory approval for 40 mbbl/d capacity by year end.
3. Montney offers optionality
ATH is working to delineate the Placid asset which is near where industry peers have experienced
success drilling in the Montney with extended long laterals and multi-staged fracing.
ATH has drilled two wells to test the area and believe there 100 potential locations in the Montney C &
D intervalls
Have received inbound calls with interest to participate
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Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
Calfrac Well Services
Mick McNulty, CFO
Key Takeaways:
1. Fleet idling to commence in both Canada and the US
Calfrac has kept its fleets working in both the US and Canada since the start of the downturn, but would
rather stack equipment than continue operate poorly-utilized equipment
CFW expects to idle most of its horsepower in Canada as breakup continues - expects to keep only 3-4
spreads working beyond the end of March
US stacking is likely to occur shortly as CFW finishes up currently-planned work as it will look to
remove fleets from service rather than work at a loss (see below)
2. Canadian pricing environment more favorable than US
Pricing gains in Canada that were realized in 2H14 have already been given back (~10%); CFW expects
another 5-10% throughout the year
CFW indicated that it has lost bids vs. competitors in the US for which it was bidding with single-digit
margins - given that CFW is one of the best-performing small cap servicers, it is possible some peers
are bidding at an outright cash loss in order to stay working
3. Service intensity robust
Canadian E&Ps are continuing to use high stage counts and high proppant loadings, which will provide
somewhat of a cushion in terms of CFW's Y/Y activity declines
Sand cost savings and efficiencies will be key - CFW has currently gotten ~10-15% price declines and is
targeting further price reductions.
Efficiency in delivering higher service intensity will likely dictate which service cos work vs. which do
not - CFW's large, footprint and efficient operations should help it remain a preferred supplier.
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Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
Canadian Natural Resources Ltd.
Steve Laut, President & CEO
Key Takeaways:
1. See cost deflation in the oil sands but still proactively attacking costs
Labour and regulatory costs are coming down and seeing a lot of creativity in cost reductions
Still see lots of opportunity to drive down opcost, particularly at Horizon
To keep costs savings beyond general service cost deflation, execution and the right sizing of projects
are important.
CNQ is currently cost-driven at the Horizon expansion and not schedule-driven
Targeting to have 60-70% of savings to be structural that is sustainable even when industry activity
picks up again.
Do not anticipate in building the uncompleted well inventory but just waiting for costs to come down to
complete to maximize returns
There is technological advancements in the oil sands but it will be more focused on operating
efficiencies and cost savings vs. shale development which will likely be more on increased productivity
and recoveries.
2. Confidence that the delayed turnaround at Horizon will not be an issue
CNQ has confidence in its delayed turnaround strategy at Horizon
6 days are still being taken to shut down to address critical work on assets and integrated items. The
work that is delayed is not critical
The project is mining more selectively and not extracting as much clay to put through the system. This
results in less stress on the equipment and leads to less required maintenance.
3. Change in Long term crude price view
Management believes crude prices will come back but not at the same level as before
Anticipates production growth in the industry will not be the same either
Anticipates that crude oil prices will balance out at US$60-70/bbl given the marginal supply cost
Within North America, there is more risk to light oil prices vs. heavy oil prices given the US shale boom,
so the key is to get to tidewater
The USGC still needs heavy oil with increased pipeline capacity now to get there. Any production that
can't get through pipe will go by rail.
4. Diverging strategies in international assets
Cote d'lvoire is one of the highest return of capital projects for CNQ
The North Sea is challenged due to the tax rate being too high. The strategy there is largely to avoid any
major capital investment even if it leads production decline in some cases.
5. Priorities of future FCF
The priorities of future FCF has changed given the recent fall in commodity prices. Coming out of the
downturn CNQ expects the order of priorities to be: (1) deleveraging balance sheet; (2) dividends and
buybacks; and (3) incremental resource development
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Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
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Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
Canadian Oil Sands Ltd.
Ryan Kubik, President & CEO and Rob Dawson, CFO
Key Takeaways:
1. Potential for further cost reductions:
Management expects cost reductions of ~15% in 2015 and believes the industry cost structure will
respond even further if crude prices stay low and results in a lack of investment in the space
Capital cost reduction in 2015 capex driven mostly by supply cost reductions and deferrals of future
projects. Of the C$300mm in reduction announced, C$100mm in capex (deferral of future projects),
and $200mm in operating costs (50% is from deferrals and will likely creep back into the system, and
the other 50% is stemmed from increased efficiencies, reduced scopes, optimization of supply and
labour costs)
Management believes there is upside potential in additional cost savings
2. Syncrude project reliability is the #1 priority:
The Syncrude partners believe that project utilization can improve to 90% (currently below ~80%) over
time.
The people factor was the largest underestimated aspect in the past when trying to improve project
reliability. The partnership is looking to put in place systems and adequate staff resources.
Large train mines have recently been rebuilt and COS expects the redundancies in extraction ability will
improve utilization as the project can run harder to make up for unexpected outages.
Operating break-even at C$55/bbl WTI
Believes delinking the plant from mining in current operations would likely be too expensive and would
destroy value. However, will look at delinking in greenfield expansions and produce bitumen only.
3. Free cash flow and dividends:
Priorities of free cash flow in the future (with crude price rebound) are: 1) de-lever the balance sheet
back within the targeted net debt range of C$1-2 billion, and then 2) raise the dividend.
Estimates that a $10/bbl change in oil prices = 80% change in cash flow
Favors dividends more than share buybacks and believes the only time a buyback makes sense is if the
company is sitting on excess cash.
Don't believe hedging crude or currency is the right strategy as investors look to COS for clear
exposure. Also believe hedging is an expensive way of controlling risk and a cheaper and more effective
way is to maintain a strong balance sheet.
4. Marketing
Sees the need to secure longer term market access given growing North American light crude
production and sees the best opportunities to move production to East and West Coast Canada
Have entered into take or pay commitments to various pipelines to be able to move volumes to the
coast in the future (specifics not disclosed) and commitments for storage ability.
COS is trying to be conservative with commitments in positioning longer term for 50% take-or-pay and
50% of common carrier (Currently 100% common carrier as sold intra-Alberta)
5. Expansions will be used to extend mine life:
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Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
The decision to develop MLX earlier to provide production growth requires unanimous decision
amongst the partners while developing it later as an extension to mine life requires 51% vote (as
considered to be sustaining capital).
Mildred Lake Extension (MLX) would add another 10 years of productive life
The estimated cost of MLX is C$3billion gross with the potential decision to sanction by the partners in
2017-2018, start construction in 2019 and complete in 2024
MLX break-even price is below today’s crude price
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Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
Cenovus Energy Inc.
Harbir Chhina, Executive Vice-President, Oil Sands
Key Takeaways:
1. Focused on current costs and believe oil sands cost curve can continue to come down:
CVE is actively talking to vendors to look for areas to reduce cost and sees potential for 5-10% in
savings.
Internal goal of coming in below '15 opcost guidance (C$14.75-17.75/bbl at Foster Creek and C$1113.00/bbl at Christina Lake)
On the G&A side, CVE is looking to do things more efficiently and because of the slower pace
development pace there is more staff capacity to cover the responsibilities of contractors. Therefore, a
savings is anticipated on the G&A side.
Also experiencing an upgrade of staff performance in both the field and headquarters
Still moving forward with Christina Lake Phase F (2H16) and Foster Creek Phase G (1H16) as the
projects are over 2/3 done. Stoping and restarting could potentially double the remaining costs. If
projects were less than 30% done, there is the potential to stop and renegotiate.
There are minor cost inefficiencies by deferring some longer dated projects, but believe it is more
important in keep the near-term phases in construction moving forward.
Looking to use the Nisku facility to build sustaining pads.
Believes if current environment persists, we could see 10-15% in capital savings for future projects.
In this pricing environment, Narrows Lake activity has been shut down and used as an opportunity to
do engineering work to look for ways to do things more efficiently
CVE is experimenting in the field to reduce diluent usage and looking at ways to increase steam output
from boilers.
With advancement in technology, we could see 20-25% cost reductions in the oil sands cost curve
longer term. The target is to be below the world average cost curve.
2. Expansion are path dependant on crude prices:
Will look to continue Christina Lake and Foster Creek expansions with crude prices even in the US$5060/bbl range
Emerging projects, namely Narrows Lake, Telephone Lake, and Grand Rapids will require CVE's
confidence that oil prices will be stable and higher for at least a few years. WTI price would need to
generate 15% IRR before CVE moves forward with it.
3. Dividend continues to be assessed
Still have the option to reassess the dividend if environment worsens - the decision is made every three
months.
CVE is interested in seeing how the DRIP program works out.
4. Royalty Monetization
Busy moving forward and looking at opportunities as the recent secondary financing had no impact on
intent or pace.
CVE is trying to think outside the box regarding the monetization and could look at the potential of
including additional assets. CVE also does not need to monetize 100% of the royalty revenue and fee
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Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
lands, as they have the flexibility over the next few years following their secondary offering.
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Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
Devon Energy Corp.
Rob Dutton, Senior Vice President, Canadian Division
Key Takeaways:
1. Seeing some cost deflation in the oil sands:
The 2015 budget has already seen ~10% deflation on average, and DVN expect another 10-15% by
year end
Seeing ~10-15% decline in operations expenses
On the capital side, seeing reduced rates for sustaining drilling
US$250-300mm in annual maintenance capital
2. Pike development still being evaluated
Pike can be broken down into smaller phases of development.
Anticipates to have more information available towards the end of the year.
Pike reservoir quality is very similar (even slightly better) to Jackfish
Have greater understanding Pike vs. Jackfish at the same point in time.
3. Other items
Oil sands operating cash flow neutral at US$45 WTI (assuming 30% heavy oil differential).
Lloydminster assets are similar
oil sands return vs. funding in a more difficult environment
May see opportunities for acquisitions
Long term view on crude oil prices have not changed and believes long term US$60/bbl is not
sustainable.
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Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
Precision Drilling
Kevin Neveu, President & CEO
Key Takeaways:
1. PDS highlighted key lessons learned from the 2008-09 downcycle, including:
Keeping high balance sheet quality: PDS has $1.3bn in available liquidity ($500mm of which is cash on
balance sheet).
Maintaining rig performance through the cycle: PDS is not planning to cut wages in the downcycle and
plans to retain its best employees from rigs going idle
Holding market share: PDS has 17 newbuilds slated for delivery in 2015, none of which are being built
on spec.
2. SLB alliance has opportunity to help PDS gain share during downcycle:
Efficiency was a key theme for E&Ps, who are targeting meaningful cost savings beyond service price
reductions - PDS's performance thus far with the SLB directional drilling partnership indicates that
E&Ps could easily realize 10%+ cost & performance efficiencies through the bundled service offering.
3. Capital return, delevering, or growth potential as trough comes into sight:
PDS indicated that it will maintain a policy of “cash is king” while the market continues to drop rapidly;
however, we could see the $500mm of cash being used for accretive M&A, delevering, buybacks, etc. in
late 2015/early 2016.
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Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
MEG Energy Corp.
Helen Kelly, Director, Investor Relations
Key Takeaways:
1. Oil sands costs are still largely sticky
Starting to see some service cost reductions in the oil sands space but still a fairly tight labour market.
2. Opportunity for lower sustaining capex:
2015 capex of C$305mm includes ~C$235mm (or ~C$8/bbl) in sustaining spend with the majority
towards well pads. The remainder will be spent towards maintenance which includes two scheduled
turnarounds. The '15 budget also includes ~C$70mm that includes the wind down of growth spend.
Beyond that, MEG is looking for ways to further trim costs.
At the current strip, MEG's operating cash flow can cover all operating costs, G&A and part of capex
3. Midstream continues to be strategic:
MEG's hub and spoke infrastructure provides MEG with the flexibility to work around anticipated
pipeline curtailments, particularly from upcoming Enbridge maintenance work in 2Q15.
The diluent recovery facility (DRF) could be back on the table given the boost to netbacks it would
provide.
MEG is cognizant of DVN's intention of dropping its respective interest into EnLink (MLP) and
recognizes the intrinsic value of its share of the Access pipeline. However, right now the pipeline
continues to be a very good asset to own and is key pieces of MEG's strategy going forward.
We note that EnLink has indicated there is the potential of US$150mm of net EBITDA associated with
the Devon's Access interest but it includes the Pike project which DVN has not sanctioned yet.
4. Future growth is path dependant on crude prices:
At US$70-80/bbl WTI, we can expect to see 10-15% p.a. growth for several years.
However, MEG is looking into its operations and looking for ways to growth with little to low capital
spend.
Near-term if crude prices are in the US$60-70/bbl range, we could see some growth, particularly from
the excess capacity tested at the 2B plant (tested at 55 mbbl/d vs. 35 mbbl/d name plate capacity),
which requires additional well pairs, water handling and steam generation capacity to add volumes.
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Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
Suncor Energy Inc.
Mark Little, Executive Vice President, Upstream
Key Takeaways:
1. Looking internally to further drive cost down and efficiencies further
SU believes costs can come down lower on both the constructing and operating sides. The company is
getting better (more productive) labour in the current market and continues to see world wide
suppliers interested in competing for market share
Believes right now is a great time to be doing work if one can afford to do it.
Cost can be further driven down internally with standardization and efficiencies
Suncor has reorganized internally its upstream divisions to streamline operations and staff
Productivity gains are starting to be seen at Fort Hills with suppliers having incentives within
agreements to drive costs down.
2. Operations
Starting to staff up operational personnel at Fort Hills
No plans to materially invest in the downstream . Will continue to look at debottlenecking
opportunities that feeds into the 1-2% capacity creep per year that the industry averages.
Montreal is the next opportunity which is contingent on Line 9B reversal. The project is moving forward
but unlikely to occur before 2017.
Oil sands is a fixed cost business and SU essentially do not see themselves shutting in production
Believes Syncrude has a lot of potential through increased utilization. Beyond production and cash flow,
another advantage of holding Syncrude interest is gaining insight and learning from other owners
Beyond Fort Hills, oil sands growth will be driven by the development of the replication strategy to
developed the nine identified in situ resource pockets with similar characteristics. Will look to develop
them in 40 mbbl/d phases that can reach up to 360 mbbl/d.
Don't see themselves moving into unconventional shale as US shale plays look overbid and a deal
would not be accretive to SU shareholders.
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Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
Trican Well Services
Dale Dusterhoft, CEO
Key Takeaways:
1. Cost savings and efficiencies will be key:
TCW has already idled ~280khp, and will likely be idling more as breakup in Canada progresses and
US activity continues to drop
TCW has received ~10% input cost reductions, but will be targeting more - we see efficiencies or
outright cost reductions as necessary in the US, where TCW will likely be nearing zero/negative EBITDA
margins as soon as 1Q15
2. Focusing on the balance sheet:
TCW is looking to pay down debt in 2015 despite macro headwinds: TCW had ~$80mm of cash on the
balance sheet as of Dec. 31 and is expecting ~$200mm in working capital release, which should help
offset the ~$50mm in capex requirements and ~$120mm in debt repayments required in 2016.
Dividend may be a target for spending reductions: TCW opted to keep its dividend as of its 4Q call, but
we believe it is considering a reduction to this payout in light of challenging macro conditions.
3. Looking to diversify out of the downcycle:
TCW indicated a desire to diversify away from its heavy focus on fracturing; of current business lines,
cementing looks to be a potential area for growth as demand returns
15
Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
2015 Calgary Energy Summit Participants
Morgan Stanley thanks the following companies for helping to make the 2015 Calgary Energy Summit a
successful event:
Athabasca Oil Corp.
Calfrac Well Services Ltd.
Canadian Oil Sands Ltd
Canadian Natural Resource Ltd.
Cenovus Energy Inc.
Crescent Point Energy Corp.
Devon Energy Corp.
Enbridge Inc.
Enerplus Corp.
MEG Energy Corp.
Paramount Resources Ltd.
Pengrowth Energy Corp.
PrairieSky Royalty Ltd.
Precision Drilling Corp.
Peyto Exploration & Development Corp.
Suncor Energy Inc.
Trican Well Service Ltd.
Trilogy Energy Corp.
ARC Resource Ltd. (Dinner Host)
Seven Generations Energy Ltd. (Dinner Host)
Rystad Energy (Economics & Growth Presentation)
16
Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
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Important US Regulatory Disclosures on Subject Companies
As of February 27, 2015, Morgan Stanley beneficially owned 1% or more of a class of common equity securities of the following companies covered in
Morgan Stanley Research: Athabasca Oil Corp..
Within the last 12 months, Morgan Stanley managed or co-managed a public offering (or 144A offering) of securities of Cenovus Energy Inc, Encana Corp.,
Husky Energy Inc, Suncor Energy Inc.
Within the last 12 months, Morgan Stanley has received compensation for investment banking services from Cenovus Energy Inc, Encana Corp., Suncor
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Canadian Natural Resources Ltd, Cenovus Energy Inc, Encana Corp., Husky Energy Inc, MEG Energy Corp, Suncor Energy Inc.
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Global Stock Ratings Distribution
(as of February 28, 2015)
For disclosure purposes only (in accordance with NASD and NYSE requirements), we include the category headings of Buy, Hold, and Sell alongside our
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Equal-weight and Not-Rated to hold and Underweight to sell recommendations, respectively.
17
Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
COVERAGE UNIVERSE
STOCK RATING CATEGORY
Overweight/Buy
Equal-weight/Hold
Not-Rated/Hold
Underweight/Sell
TOTAL
INVESTMENT BANKING CLIENTS (IBC)
COUNT
% OF TOTAL
COUNT
% OF TOTAL
IBC
% OF RATING
CATEGORY
1161
1459
101
609
35%
44%
3%
18%
321
370
10
88
41%
47%
1%
11%
28%
25%
10%
14%
3,330
789
Data include common stock and ADRs currently assigned ratings. Investment Banking Clients are companies from whom Morgan Stanley received
investment banking compensation in the last 12 months.
Analyst Stock Ratings
Overweight (O). The stock's total return is expected to exceed the average total return of the analyst's industry (or industry team's) coverage universe, on a
risk-adjusted basis, over the next 12-18 months.
Equal-weight (E). The stock's total return is expected to be in line with the average total return of the analyst's industry (or industry team's) coverage
universe, on a risk-adjusted basis, over the next 12-18 months.
Not-Rated (NR). Currently the analyst does not have adequate conviction about the stock's total return relative to the average total return of the analyst's
industry (or industry team's) coverage universe, on a risk-adjusted basis, over the next 12-18 months.
Underweight (U). The stock's total return is expected to be below the average total return of the analyst's industry (or industry team's) coverage universe, on
a risk-adjusted basis, over the next 12-18 months.
Unless otherwise specified, the time frame for price targets included in Morgan Stanley Research is 12 to 18 months.
Analyst Industry Views
Attractive (A): The analyst expects the performance of his or her industry coverage universe over the next 12-18 months to be attractive vs. the relevant
broad market benchmark, as indicated below.
In-Line (I): The analyst expects the performance of his or her industry coverage universe over the next 12-18 months to be in line with the relevant broad
market benchmark, as indicated below.
Cautious (C): The analyst views the performance of his or her industry coverage universe over the next 12-18 months with caution vs. the relevant broad
market benchmark, as indicated below.
Benchmarks for each region are as follows: North America - S&P 500; Latin America - relevant MSCI country index or MSCI Latin America Index; Europe MSCI Europe; Japan - TOPIX; Asia - relevant MSCI country index or MSCI sub-regional index or MSCI AC Asia Pacific ex Japan Index.
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18
Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
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19
Canadian Energy | March 16, 2015
MORGAN STANLEY RESEARCH
INDUSTRY COVERAGE: Canadian Energy
COMPANY (TICKER)
RATING (AS OF)
PRICE* (03/13/2015)
O (03/19/2014)
E (03/19/2014)
E (03/19/2014)
C$36.48
C$21.28
C$35.34
E (07/22/2014)
U (07/22/2014)
E (01/22/2015)
E (01/22/2015)
E (12/19/2014)
C$1.79
C$9.48
$10.80
C$25.02
C$18.39
Calio, Evan
Canadian Natural Resources Ltd (CNQ.TO)
Cenovus Energy Inc (CVE.TO)
Suncor Energy Inc (SU.TO)
Wong, Benny
Athabasca Oil Corp. (ATH.TO)
Canadian Oil Sands Ltd (COS.TO)
Encana Corp. (ECA.N)
Husky Energy Inc (HSE.TO)
MEG Energy Corp (MEG.TO)
Stock Ratings are subject to change. Please see latest research for each company.
* Historical prices are not split adjusted.
© 2015 Morgan Stanley
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