Royalty Review 0815 BMO (00000002)

This report was prepared by an analyst(s) employed by BMO Nesbitt Burns Inc., and who is (are) not registered as a research analyst(s) under FINRA rules. For disclosure statements, including the Analyst's Certification, please refer to pages 24 to 25.

Alberta Oil & Gas Review

Royalty Review: Alberta Needs a Hand, Not a Hammer

September 10, 2015 Randy Ollenberger 403-515-1502BMO Nesbitt Burns Inc. [email protected]

Jared Dziuba, CFA 403-515-3672BMO Nesbitt Burns Inc. [email protected]

Associate: Matthew Murphy 403-515-1571

The Alberta NDP government has appointed a panel to review the Province’s

royalty system and plans to release recommendations by year-end 2015. Our

assessment of the competitiveness of the Alberta oil and gas industry suggests

that the industry is not positioned to bear the burden of higher royalties and/or

environmental charges at current commodity price levels. Indeed, based on

the relatively weaker competitive position of the Alberta industry, a reduction

in charges may be warranted to incentivize activity, at least in the short term.

Summary

The rapid development of shale oil and gas in

the United States over the last several years has

left the Alberta oil and gas industry in a

precarious competitive position, in our view,

due to the relatively smaller scale resource,

distance to market and higher cost structure.

Given the current commodity price backdrop

and low profitability of the Alberta oil and gas

industry, investors are right to be concerned

about the potential for higher royalty rates.

Alberta’s current royalty and fiscal system is

arguably high considering the low level of

underlying returns on capital compared to

competing jurisdictions. Returns on capital in

Alberta are below 4% compared to roughly

11% in Saskatchewan and 9% offshore east

coast, while recycle ratios are only 0.6x versus

1.2x in Saskatchewan and 1.7x offshore.

Alberta’s economic returns are also weak

relative to its primary U.S. competition.

Not surprisingly, lower profitability has

translated to lower valuation multiples for

Alberta oil and gas companies. Alberta’s

conventional producers trade at a median

2016E EV/EBITDA multiple of 6.8x versus

the U.S. peer median of 8.5x. On current

production, Alberta producers trade at an

enterprise value of approximately $35,000 per

flowing boe compared to nearly $50,000 per

boe/d for U.S. producers.

We continue to recommend a cautious

investment posture given the prospect on

ongoing volatility in commodity prices.

The rapid development of shale oil and gas in the United States has

dramatically reshaped the North American oil and gas market and has left

Alberta in a precarious competitive position, in our opinion. Alberta’s

unconventional resource opportunity is relatively small scale and the industry

is burdened with a higher cost structure and greater distance to market than

most competing jurisdictions. This has translated to lower returns on capital

employed (ROCE) in Alberta compared to the United States and other

provinces. For example, the median ROCE for Alberta natural gas and tight

oil producers is only 2% compared to 8% and 11% for U.S. peers,

respectively. Alberta’s returns on capital have been sub-4% since 2011, which

is similar to B.C. but well below ~11% in Saskatchewan and 9% offshore east

coast. It is also noteworthy that the Canadian oil and gas industry generated

the lowest ROCE of any major industry in Canada in 2013 when crude oil

prices were over $100/bbl. Alberta’s current royalty system and rates are

arguably high considering the low level of underlying returns on capital

compared to competing jurisdictions.

The relatively poor economic returns generated by Alberta producers has had

a negative impact on investment in the province and has generally translated

to lower equity valuations for Canadian oil and gas producers. Alberta’s

conventional producers trade at a median 2016E EV/EBITDA multiple of

6.8x versus the U.S. peer median of 8.5x. On the basis of current production,

Alberta producers trade at an enterprise value of approximately $35,000 per

flowing boe compared to nearly $50,000 per boe/d for U.S. producers. Oil

sands focused companies have generated returns on capital that are similar to

U.S. tight oil companies and trade at similar or higher valuation multiples.

However, in our view the valuation premium should be larger due to the

significantly longer reserve life and minimal production decline.

Sector Comment

Déjà Vu All Over Again

The Alberta government has appointed an expert panel to review the Province’s royalty system, with plans to release recommendations by year-end 2015. We have completed a review of our own and the conclusions are not pretty. The advancement of shale oil and gas technology has dramatically reshaped the North American oil and gas industry and has left Alberta in a precarious position, in our opinion, due to its relatively smaller resource opportunity, distance to markets and higher cost structure in comparison to many U.S. plays as well as those in the neighbouring provinces of Saskatchewan and British Columbia. Given the current commodity price backdrop, what Alberta producers may require is a royalty incentive scheme, not a higher fiscal burden.

History Lesson

The royalty regime in Alberta is more than seven decades old and change is not new. The Province gained resource ownership in 1930 with the Natural Resources Transfer Act and initially enacted a flat royalty rate at 5%. With rising commodity prices, the royalty was progressively increased to 25% by 1972. Price sensitivity features were introduced to counter commodity price fluctuations through the 1970–1980 period and in 1993 distinction was made between market values for heavy and light oil. In 1997, a separate Oil Sands Royalty Regulation came into effect. The most recent major overhaul, top of mind for most investors, was proposed in early 2007 and the New Royalty Framework (NRF) was set for January 1, 2009. This program would be ‘tweaked’ several times before reaching its current manifestation as the government responded to a dramatic reduction in investment by industry and the global economic crisis.

Figure 1: Alberta’s Royalty Framework History

Evolution of royalties in Alberta

1930/01:

AB gains

resource

ownership;

Royalties

at 5% flat

rate

1935/6: Flat

rate royalty at

10%; NGLs

at flexible rate

1941: Flexible

oil royalty

option; Flat

12.5% or 5‐

15%

production

based

1943: Gas

royalty

increased

to 15%

1951: Royalty

rates based

on

production,

ranging from

5% to 16.67%

1962: Gas

royalty

increased

to 16.67%

1974:

Price

sensitive

royalty

rates

1978: Low

productivi

ty feature

for gas

royalty

1993: Increased

price sensitivity,

price inflation

indexing.

Separate vintage

for heavy/ light

oil

1980:

Incentive

programs

1997:

Generic

oil sands

royalty

regime

2002: NGLs

royalties

linked to

royalty

curves

2007: New

Royalty

Framework

(NRF)

announced

2008:

Transitional

royalties

2009: NRF/

Bitumen

valuation

methodology

(BMV)

implemented

2010:

Royalty

framework

competitiven

ess review

2011: New well/project based Royalty rates

2015:

New

Royalty

review

Source: BMO Capital Markets, Company Reports

In February 2007, the Alberta conservative government appointed a panel to review Alberta’s royalty and tax regime to address concerns that the Province was not getting its ‘fair share’ of oil and gas revenues. This review provided for the first major overhaul of Alberta’s royalty system since 1997. The panel recommended significant changes that would increase royalty payments by up to 20% with the government take increasing to 64% from 47% in the oil sands, 49% from 44% for conventional crude oil, and to 63% from 58% for natural gas. The Canadian

Page 2 September 10, 2015

Sector Comment


oil and gas industry strongly criticized the report due to flawed data and lack of consideration for how industry activity influenced broader economic prosperity. Several major companies stated that they would significantly reduce investment in the Province if the report’s recommendations were implemented. In October, 2007, the New Royalty Framework (NRF) was introduced after considering the Panel’s recommendations. Broadly viewed as a questionable compromise, the NRF included both higher royalty rates and more sensitivity to commodity prices. Oil sands programs were tempered but the rules proposed for conventional oil and gas were largely adopted and were punitive to high productivity oil wells, a potential driver of growth:

Conventional crude oil royalties moved to a sliding-scale system based on both oil prices and production rates, ranging from 30–50% and capped at C$120/bbl oil compared to the previous max rate of 35% at $30/bbl;

Natural gas royalties would also be tied to prices and production, with rates ranging 5–50% from 5–35% previously, with the price cap of $17.28/Mcf;

Oil sands royalties would also be linked to crude oil prices and retain pre- and post-payout tiers to incentivize investment. Rates range from 1–9% on pre-payout and 25–40% post-payout, based on oil prices of C$55–120/bbl.

The global economic crisis in 2008 caused a major slowdown in oil and gas activity before the NRF became effective in January 2009. In response, Alberta introduced ‘transitional’ rates to spur investment – all wells drilled between 2009 and 2013 to a depth of 1,000–3,500 metres could opt for transitional rates effective until January 1, 2014. The peak rate for natural gas was reset to ~30% from 50% under the NRF. The program’s impact on conventional oil, particularly high rate wells, was slightly less compelling with maximum royalty rates unchanged at 50%, although transitional rates were 10–15% lower within certain commodity price and production ranges. The Alberta government estimated that the transitional rates could potentially reduce royalties collected by $172 million in 2009 and $512 million in 2013.

Alberta performed an industry competitiveness review in 2010 before the NRF rates came back into effect and subsequently made minor changes to the royalty system to come into effect in early 2011. Normalized royalty rates applied to natural gas wells would decrease to 5–36% from 5–50% based on the 2009 framework, while post-payout royalties for conventional oil decreased to 0–40% from 0–50%. Minor changes were also made to the Natural Gas Deep Drilling Program. Oil sands royalties were maintained from the prior framework, with Tier 1 and Tier 2 royalties of 1–9% and 25–40%, respectively for oil prices of C$55–120/bbl.1

The Costs of Uncertainty

The political uncertainty created by the various royalty reviews and changes since 2007 has had a meaningful impact on the competitiveness of Alberta oil and gas industry and has negatively impacted Alberta’s reputation as a ‘safe’ place to invest, in our opinion. Alberta’s oil and gas industry responded to the uncertainties of the royalty review process over the 2007–2009 period by reducing activity; Alberta’s rig utilization fell from approximately 60% in 2006 to 40% in 2007 and metres drilled decreased from 22,000 to 16,000 metres despite relatively strong pricing environments for both crude oil and natural gas (Chart 1). Corresponding investment decreased 21% in 2007 to $18 billion and remained at a depressed level through 2008,

1 A summary of Alberta’s current drilling incentives and credits are outlined in the Appendix.

Sector Comment

representing a cumulative loss of investment of nearly $10 billion leading up to the global financial crisis. The combination of several reactive ‘fixes’ to the royalty system along higher oil prices eventually drove investment back to pre-2007 levels (Chart 2).

Chart 1: Alberta Drilling Activity (# Wells and Metres Drilled) Chart 2: Alberta Capital Spending – Conventional Oil & Gas (C$ Billion)

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Source: CAPP, BMO Capital Markets Source: CAPP, BMO Capital Markets

Many of the investment dollars displaced from Alberta were immediately redeployed in adjacent jurisdictions including British Columbia and Saskatchewan given their proximity and geological connection to many prolific Alberta plays (ex Montney, Horn River, Viking, Bakken, conventional heavy oil, etc.). Total capital expenditure in B.C. and Saskatchewan increased roughly 40–60% through 2008, while drilling-specific capital fell by only half the amount as in Alberta during the 2009 downturn – a reflection of how relative economics shifted in response to the royalty changes (Charts 3–4). It took modifications to the royalty system in 2010 to attract capital back to Alberta.

Chart 3: Year-Over-Year Change in Total Capital Expenditure Chart 4: Year-Over-Year Change in Drilling Capital

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Alberta Saskatchewan British Columbia


Natural gas drilling decreased 31% in 2007 in response to the royalty review process despite relatively strong AECO gas prices in the $6–7/mcf range (Chart 5), while conventional crude


Sector Comment

oil activity declined 35% despite an increase in crude oil prices from $70/bbl to $80/bbl (Chart 6). We note that oil sands growth spending did not decline materially in 2007, as the long lead-time nature of development makes near-term construction activity less reactive, developers did place longer-term project planning on hold.

Chart 5: Alberta Gas Drilling Activity vs. Gas Price (# Wells) Chart 6: Alberta Crude Oil Drilling Activity vs. Oil Price (# Wells)

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Lessons Learned?

In June 2015, the Province announced a formal review of the existing royalty framework by an expert panel led by Dave Mowat, President and CEO of ATB Financial. The panel is expected to submit its report and recommendations to the Province by the end of 2015. While the market has broadly expressed concern over the royalty review process, we believe some encouraging developments have emerged recently, in contrast to the 2007 process. Importantly, the government’s appointed panel represents a good mix of relevant members that understand the economics and challenges of industry, as well as the possible unintended impacts of policy changes. The other members of the panel are Peter Tertzakian, Chief Energy Economist and Managing Director of ARC Financial, and Leona Hanson, Mayor of the Town of Beaverlodge, Alberta, in the heart of the province’s ‘small town oil and gas’. The Alberta Energy Minister has also acknowledged the challenges currently facing industry, and clarified that any changes to the royalty program, if any, would not be enacted until 2017. Furthermore, it was suggested that the review would focus specifically on how royalty rates adjust to the upside in oil prices, so as not to unduly harm the industry during the bottom of the cycle.

Canada’s Industry Needs All the Help It Can Get

The emergence of shale oil and gas and technological breakthrough in hydraulic fracturing has dramatically changed the dynamics of North American supply and relative economics. From a high level perspective, the relative resource scale in these emerging plays between the U.S. and Canada already has Alberta at a major disadvantage. The incredible growth and scale of U.S. shale oil and gas resource potential dwarfs that of Canada and Alberta (Charts 7–8). In response, investment dollars have flowed toward the U.S. and away from Western Canada in


Sector Comment

recent years as investors chase companies with better opportunities for growth and stronger economics. Not surprisingly, this has contributed to lagging tight oil and gas resource development in Western Canada relative to the U.S. (see also our September 2014 research report, “Keeping It Tight – Emerging Opportunities in Canadian Tight Oil”). We suspect that the weaker commodity price outlook could further hamper opportunities for advancement in the basin and divert additional focus toward U.S. producers, particularly in the event of further regulatory upset or uncertainty.

Chart 7: North America Tight Oil Recoverable Resource (Billion Bbls) Chart 8: North America Shale Gas Recoverable Resource (Bcf)

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2010 2011 2012 2013 US Tight Oil Alberta/Canada

Permian Eagle Ford Bakken Austin Chalk Niobrara/Rockies Buda TMS

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100

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500

600

700

800

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1000

US Tight Oil Alberta/Other Canada

Gulf Coast Appalachia/East Rocky Mountain Southwest

Mid‐Con West Coast Alberta B.C./Other

Source: EIA, BMO Capital Markets, Company Reports Source: EIA, BMO Capital Markets, Company Reports

Although there are pockets of strength within the basin (high quality producers), we believe that Alberta oil and gas producers on average are already not competitive with their major North American peers from an economics perspective, particularly U.S. tight oil/gas producers because of their superior resource scale and improving well economics. As noted, investment dollars have already been displaced toward U.S. producers in recent years as demonstrated by the country’s immense contribution to North American crude oil and natural gas production growth since 2010 (Charts 9–10). The U.S. has added crude oil production of roughly 5 million b/d since 2011, making up 88% of North America’s growth over that time frame and representing an annual growth rate of 12%. In contrast, Canada has contributed growth of just 0.6 million b/d or 4% CAGR from the oil sands while conventional oil has declined by 1%. Similarly, the U.S. accounts for nearly all of North America’s natural gas production growth since 2010, adding 18 bcf/d while Alberta’s production has slipped by 5 bcf/d, or 6%, annually.


http://research-ca.bmocapitalmarkets.com/documents/39A3A08F-4FB6-4415-A8DE-38F284EA20D8.PDF

Sector Comment

Chart 9: North America Oil Production by Region (Million b/d) Chart 10: North America Natural Gas Production by Region (Bcf/d)

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2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

2010 2011 2012 2013 2014 2015

U.S. Oil & Liquids Alberta Oil & Liquids Other Canada

+12% CAGR

4% CAGR

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10

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2010 2011 2012 2013 2014 2015

U.S. Gas Production Alberta Other Canada

‐6% CAGR

+5% CAGR

Source: EIA, NEB, BMO Capital Markets Source: EIA, NEB, BMO Capital Markets

Based on findings from our 2014 Global Cost Study, implied supply costs for Canadian tight oil producers are above that of major competing U.S. peers. We believe this will become even more apparent in corporate results in the coming years as the oil price downturn and relative advancement in operations lead to a widening spread between development costs in the two regions, as represented by our model supply cost estimates in Chart 11. In the Permian, median supply cost estimates of only $52/bbl have been implied by recent drilling results in the Delaware Basin. Development of the Marcellus and Utica gas plays in the U.S. are also dramatically altering North American gas supply economics and we believe are serious threats to Western Canadian gas producers. We currently estimate gas supply costs of only $2.50–3/mcfe compared to average Canadian gas supply costs of roughly $5/mcf. Midstream infrastructure additions could bring more than 16 bcf/d of additional gas supply from the eastern U.S. to western regions in the coming years and will play head-on competition with Alberta (Chart 12).

Chart 11: Implied Crude Oil Supply Costs by Region (US$/boe, Brent) Chart 12: Implied Natural Gas Supply Costs by Region (US$/mcfe)

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1‐Year 3‐Year Average Model Supply Cost Range

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Global Gas Canada North America U.S. Shale Marcellus/UticaModel Range

1‐Year 3‐Year Average

Source: BMO Capital Markets 2014 Global Cost Study, Company Reports Notes: Supply costs represented on a Brent oil equivalent basis

Source: BMO Capital Markets 2014 Global Cost Study, Company Reports


Sector Comment

Alberta’s royalty rates had declined from a peak of roughly 17% in 2005 to 12% in 2013, which is partly a reflection of lower commodity prices and weakening economics in the basin. Compared to other competing Canadian jurisdictions Alberta’s average royalty rates have in fact risen and notably decoupled from British Columbia since 2010, even though cash flows, returns on capital, and recycle ratios have deteriorated in similar fashion for both Provinces, as illustrated in Charts 13–15.

Chart 13: Royalty Rate History by Province (% Gross Revenue)

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Alberta Conventional Saskatchewan British Columbia

East Coast Offshore AB Oil Sands

Source: CAPP, BMO Capital Markets

We highlight the widening gap in economic returns and funding efficiency for Alberta (and B.C.) producers compared to other Canadian jurisdictions in Charts 14–15. Alberta’s cash flow as a percent of cumulative capital (our proxy here for ROCE) has been sub-4% since 2011, comparable to B.C. but well below ~11% in Saskatchewan and 9% offshore the east coast. Recycle ratios, which reflect a more current measure of capital cost coverage have similarly declined, with Alberta’s industry generating cash flow of only 0.6x capital costs over the past three years (0.5x for non-oil sands production), compared to healthy recycle ratios of 1.2x in Saskatchewan and 1.7x offshore. Oil sands producers do generate apparently solid cash recoveries on vintage capital investment (much of which was installed in the 60’s and 70’s) as suggested in Chart 14; however, returns on new investment are significantly lower as illustrated by the declining industry recycle ratio in Chart 15.


Sector Comment

Chart 14: Estimated Cash Flow ‘Returns’ on Capital Chart 15: Cash Flow ‘Recycle Ratio’ by Province

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3.5x



Source: CAPP, BMO Capital Markets Note: reflects estimated cash flow over cumulative, undepreciated capital, as a proxy for comparable returns; does not consider depreciation, amortization or other corporate non-cash charges.

Source: CAPP, BMO Capital Markets Note: recycle ratio calculated as annual cash flow over capital spending

We believe that royalty rates should generally be correlated with underlying economics in order to properly promote industry competitiveness. This relationship is generally apparent when comparing average royalty rates to the returns and recycle ratios noted above and is illustrated in Chart 16. This would suggest that Alberta’s royalty rates, which are higher than B.C. but lower than Saskatchewan/east coast, are reasonable at best considering relative economics and arguably could be lower.

Chart 16: Estimated Royalty Rates vs Recycle Ratio by Region

AB Conventional

Saskatchewan

Alberta Avg

East Coast Offshore

British Columbia

AB Oil Sands

U.S. Shale Gas

Canada Tight Oil

U.S. Tight Oil

Canada Gas

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3-Y

ear

Re

cycl

e R

ati

o

3-Yr Avg Royalty Rate

Source: CAPP, BMO Capital Markets Notes: recycle ratio calculated as operating cash flow over investment ex-corporate items; may not compare to corporate level metrics in this report

Canada’s oil and gas business, despite media hype and common belief to the contrary, generates lower returns on capital than nearly any other major industry in Canada. Chart 17 illustrates this


Sector Comment

fact based on Statistics Canada data, which suggests Canada’s industry generated ROCE of only ~1% in 2013 despite US$100/bbl oil prices.

Chart 17: 2013 Returns on Capital Employed – Top 20 Canadian Industries by Total Revenue

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Source: Statistics Canada, BMO Capital Markets

In a recent comment entitled “Back to Basics: Returns Matter”, we discussed in detail how industry returns on capital in general have declined since 2006 and that only select jurisdictions and companies have been able to generate adequate returns for investors. Independent U.S. producers are improving returns while other global producers including Canadian companies are losing ground (Chart 18). We expect returns for our coverage group to decrease to nil in 2015E/2016E and only 1.5% in 2017E assuming moderate cost improvements and only 2–4% with more significant cost reductions.

Chart 18: Three-Year Average ROCE by Peer Group Chart 19: Forecast ROCE vs. 20% Cost Reduction Scenario

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Integrated/Majors Cdn Seniors US Seniors

Cdn Small Cap US Small Cap Global Average

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2014 2015E 2016E 2017E

Group Median 20% Cost Reduction

Source: BMO Capital Markets, Company Reports Source: BMO Capital Markets, Company Reports Notes: 20% cost reduction scenario assumes forward strip pricing


http://research-ca.bmocapitalmarkets.com/documents/C26F5197-6317-4DC8-B936-A116469995FA.PDF

Sector Comment

Comparing Supply Costs, Returns and Resulting Valuations

We believe that Alberta producers generally are at a disadvantage relative to their peers based on returns and supply costs, which has translated to lower valuations. With the exception of the oil sands, which is less comparable to the conventional oil and gas business, Alberta’s oil and gas producers trade at a median 2016E EV/EBITDA multiple of 6.8x versus the U.S. peer median of 8.5x (Chart 20).

Chart 20: Alberta Producers - 2016E EV/EBITDA vs. ROCE Chart 21: Historical Average Forward EV/EBITDA Multiples

International

AB Gas

U.S. Gas

AB Tight Oil

U.S. Tight Oil

Oil Sands

Alberta Average

U.S. Average

Alberta Ex‐Oil Sands

4x

5x

6x

7x

8x

9x

10x

0.0% 2.0% 4.0% 6.0% 8.0% 10.0% 12.0%

2016E EV

/EBITDA

ROCE

4x

5x

6x

7x

8x

9x

10x

11x

12x

Oil Sands AB Conventional US Avg.

Source: Company reports, BMO Capital Markets, Bloomberg Source: BMO Capital Markets, Bloomberg

Alberta producers tend to have higher supply costs on average as shown in Chart 22. We estimate average supply costs of $106/boe for Alberta conventional production, which is in line with the U.S. average and below international operations; however, key growth areas, tight oil and shale gas, are higher in Alberta than comparable U.S. peers, especially for natural gas. Higher finding and development costs (F&D) are partly to blame, as shown in Chart 23.

Chart 22: Alberta Producers’ Average Supply Costs (US$/boe) Chart 23: Alberta Producers’ F&D Costs (US$/boe)

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Source: Company reports, BMO Capital Markets Source: Company reports, BMO Capital Markets


Sector Comment

Net price realizations are also lower compared to global peers, reflecting quality and transportation differentials due lower crude quality (heavy grades) and market access challenges. Given both lower pricing and higher costs, Alberta producers generate lower average recycle ratios.

Chart 24: Alberta Producers Realized Pricing (US$/ boe) Chart 25: Alberta Producers Average Recycle Ratios

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Charts 26–27 outline relative valuation metrics on production and reserves and highlight that there tends to be a valuation discount for Alberta producers to reflect the lower cash flow and returns per unit. Alberta conventional producers trade at a median 2016E EV/Production of ~$35,000/boe/d compared to nearly $50,000/boe/d for U.S. and international peers. While Oil sands producers fetch decent valuations on production given the industry’s cash flow generating ability, the abundant reserves garner a heavily discounted valuation to reflect the high cost of future development and deteriorating returns.

Chart 26: 2016E EV/Production Metrics (US$/boe/d) Chart 27: EV/Net Proved Reserves (US$/boe)

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Source: Company reports, BMO Capital Markets, Bloomberg Source: Company reports, BMO Capital Markets, Bloomberg


Sector Comment

Alberta Shale Gas

Alberta gas producers earn noticeably below-average returns as compared to U.S. peers in the competing Marcellus, Utica, Rockies, and ArkLaTex plays, which has translated to lower average valuations as illustrated by forward EV/EBITDA in Charts 28–29. We estimate Alberta gas producers generated median returns on capital of only 1.8% in 2014, well below 11% generated by competing U.S. gas producers. Valuation multiples have trended noticeably higher for U.S. versus Canadian gas producers in recent years to reflect this.

Chart 28: Competing Gas Producers – 2016E EV/EBITDA vs. ROCE Chart 29: Gas Producers Historical Forward EV/EBITDA

AAVBIR VII

NVADEE

TET

BXELRE

POU TOU

PEY

RRC

EQT

COG

REXX

ECR

AR

RICE

SWNGST

PDCEUPL

QEP

MRD

XCO

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‐30% ‐20% ‐10% 0% 10% 20% 30%

2016E EV

/EBITDA

ROCE

AB Median: 1.8%

U.S. Median: 11.0%

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AB Avg. US Avg.

Source: Company reports, BMO Capital Markets, Bloomberg Note: Alberta producers highlighted by pink markers

Source: BMO Capital Markets, Bloomberg

Chart 30 illustrates that Alberta’s gas production has average supply costs slightly above U.S. peers, including highlighting prolific competing plays like the Marcellus where supply costs continue to improve. Much of this cost variance is driven by higher F&D costs in regions aside from the Rockies.

Chart 30: Gas Producers Supply Costs (US$/mcfe) Chart 31: Gas Producers F&D Cost (US$/mcfe)

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Sector Comment

Alberta gas producers on average have achieved higher realized pricing for natural gas, partly as a result of a strong domestic market for natural gas liquids; however, higher costs still drive lower average cash flow relative to capital costs as reflects in lower recycle ratios (Chart 33).

Chart 32: Gas Producers Realized Pricing (US$/mcfe) Chart 33: Gas Producers Recycle Ratio (US$/mcfe)

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As a result of weaker economics, Alberta gas producers trade at a discounted valuation to U.S. competitors, reflecting $5,900/mcfe/d of production and $1.35/mcfe of proved reserves compared to ~$6500/mcfe/d and $1.50/mcfe for U.S. peers.

Chart 34: Gas Producers 2016E EV/Production (US$/mcfe/d) Chart 35: Gas Producers EV/Net Proved Reserves (US$/mcfe)

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Table 1 provides economic and valuation comparables for natural gas producers in Alberta and the U.S. by major producing region.


Sector Comment

Table 1: Natural Gas Producers – Alberta Focused vs. U.S.

Implied Supply Cost 2014 Average EV/Boe$/boe $/mcfe F&D Price ROCE Recyc EV/EBITDA EV/mcfe/d Proved

Ticker 2014 3-Year 2014 3-Year ($/mcfe) ($/mcfe) % Ratio 2015 2016 2015 2016 2014Montney-Focus:

Advantage AAV $238.57 $166.58 $11.71 $6.00 nm $3.80 1.8% 0.9x 10.1x 7.1x $8,305 $6,111 $1.06Birchcliff* BIR $73.52 $100.99 $3.86 $4.12 $0.85 $4.44 8.4% 4.0x 8.5x 6.4x $6,009 $5,402 $0.84Delphi* DEE $74.22 $88.26 $5.04 $4.38 $1.17 $4.34 0.2% 1.7x 4.9x 4.0x $3,740 $3,560 $0.87Seven Generations VII $67.57 $73.15 $4.93 $5.17 $0.34 $4.22 12.3% 7.5x 15.4x 6.5x $9,545 $5,416 $1.29Nuvista NVA $84.67 $94.73 $5.22 $4.46 $0.98 $3.96 -6.3% 2.0x 8.9x 5.3x $6,246 $5,297 $1.27Trilogy TET $74.63 $94.65 $4.89 $4.59 $1.62 $4.77 -8.5% 2.0x 8.4x 7.1x $6,179 $7,019 $1.94

Deep Basin/Other:Bellatrix* BXE $90.08 $78.78 $6.37 $4.28 $2.00 $4.50 10.8% 1.5x 8.5x 6.2x $4,388 $4,471 $1.12Long Run* LRE $75.58 $80.87 $4.33 $3.71 $1.00 $4.36 -13.4% 2.6x 4.5x 4.8x $2,859 $3,291 $0.90Paramount POU $79.95 $100.08 $5.55 $5.30 $0.65 $5.20 -1.7% 2.4x 17.8x 8.2x $8,728 $6,709 $1.83Peyto PEY $56.06 $85.86 $3.69 $4.62 $1.48 $4.18 12.0% 2.4x 10.7x 9.4x $9,108 $7,937 $2.21Tourmaline TOU $61.80 $89.00 $4.12 $4.55 $1.36 $5.32 10.1% 2.8x 9.8x 8.0x $7,079 $5,361 $2.43Alberta Median $80.14 $101.08 $5.27 $5.01 $1.35 $4.39 1.8% 2.2x 8.9x 6.5x $6,246 $5,402 $1.27

Marcellus/Utica:Range RRC $61.74 $61.15 $7.39 $5.18 $0.60 $4.00 11.8% 3.9x 11.2x 13.6x $6,486 $5,341 $0.87EQT EQT $50.43 $47.82 $5.00 $4.10 $0.76 $3.12 6.6% 3.5x 12.1x 12.0x $7,880 $6,853 $1.23Cabot COG $87.69 $84.64 $3.41 $2.96 $0.57 $3.12 9.3% 2.8x 13.4x 15.1x $6,941 $7,048 $1.53REXX REXX $93.63 $91.95 $5.12 $4.60 $0.60 $3.11 -2.4% 2.5x 9.8x 9.9x $4,512 $4,152 $0.68Eclipse ECR $147.90 $223.89 $8.59 $12.67 $1.92 $3.51 -7.8% 0.4x 9.6x 14.7x $4,467 $3,211 $2.39Antero AR $63.70 $79.27 $5.05 $6.02 $0.48 $4.34 10.6% 4.4x 9.6x 9.4x $7,192 $6,017 $0.84RICE RICE $64.76 $55.92 $5.13 $5.99 $1.38 $3.68 16.8% 1.4x 10.6x 11.7x $6,113 $4,770 $2.47Southwestern SWN $60.17 $92.11 $4.68 $4.30 $1.29 $3.71 11.3% 1.4x 5.4x 7.0x $2,933 $2,668 $0.73Gastar GST $60.35 $69.28 $4.23 $4.28 $0.40 $4.11 11.7% 7.5x 8.5x 7.0x $8,223 $7,895 $1.09PDC Energy PETD $123.60 $95.49 $7.33 $4.30 $1.40 $4.07 11.7% 1.4x 6.0x 5.2x $10,891 $8,100 $1.81Marcellus/Utica $64.23 $81.96 $5.08 $4.45 $0.68 $3.69 10.9% 2.6x 9.7x 10.8x $6,713 $5,679 $1.16

RockiesUltra UPL $53.59 $77.60 $2.98 $3.29 $0.51 $4.24 22.1% 4.2x 7.3x 5.4x $5,769 $5,402 $0.83QEP QEP $115.12 $121.69 $7.49 $6.38 $2.02 $4.34 14.6% 0.7x 4.2x 7.8x $4,031 $4,383 $0.88Rockies $84.36 $99.65 $5.23 $4.84 $1.26 $4.29 18.3% 2.5x 5.8x 6.6x $4,900 $4,893 $0.86

ArkLaTexMemorial MRD $66.18 $83.25 $4.51 $5.29 $0.62 $3.67 -27.0% 6.7x 19.3x 15.7x $17,172 $11,261 $3.79Exco XCO $62.21 $110.59 $2.87 $4.48 $0.74 $3.79 10.6% 2.4x 6.2x 8.6x $4,587 $4,674 $1.25ArkLaTex $64.20 $96.92 $3.69 $4.88 $0.68 $3.73 -8.2% 4.5x 12.8x 12.1x $10,879 $7,968 $2.52U.S. Median $64.23 $83.95 $5.02 $4.54 $0.68 $3.75 11.0% 2.6x 9.6x 9.6x $6,943 $5,841 $1.46

Source: Company Reports, BMO Capital Markets estimates, FirstCall Consensus Estimates Note: * Valuation metrics for companies not under coverage are based on consensus estimates

Alberta Tight Oil

Similar to shale gas, Alberta ‘tight oil’ producers earn below-average returns compared to leading resource plays such as the Bakken, Eagle Ford, Permian, and Niobrara. Median returns for Alberta companies were only 1.7% in 2014. This has translated into discounted valuations, with Alberta producers reflecting a median 2016E EV/EBITDA multiple of 6.4x versus 7.2x for U.S. peers. Historical valuation trends have reversed, and U.S. peers have garnered premium valuations in recent years as a result of superior resource scale and economics.


Sector Comment

Chart 36: Competing Tight Oil Producers - 2016E EV/EBITDA vs. ROCE Chart 37: Tight Oil Producers Historical Forward EV/EBITDA

WCP

PWT

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ARX

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Alberta tight oil producers have higher average supply costs to major U.S. plays, averaging $111/boe compared to $100/boe for U.S. peers based on three-year average results. As mentioned, we expect supply costs for key plays like the Permian to improve materially in coming years relative to Canadian plays. F&D costs are a primary contributor to the higher supply costs for Alberta producers.

Chart 38: Tight Oil Producers’ Supply Costs (US$/boe) Chart 39: Tight Oil Producers’ F&D Costs (US$/ boe)

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Alberta oil producers tend to receive lower value for their product sales because of quality and transportation cost differentials, which puts them at an economic disadvantage to competing U.S. peers. Chart 41 illustrates how Alberta tight oil producers on average generate lower cash flows relative to capital costs compared to most competing plays.


Sector Comment

Chart 40: Tight Oil Producers’ Realized Pricing (US$/ boe) Chart 41: Tight Oil Producers’ Recycle Ratio

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On average, Alberta oil producers trade at a discount relative to U.S. peers on 2016E flowing barrel and 2014 net proved reserves as a reflection of the relative economics (Charts 42–43).

Chart 42: Tight Oil Producers’ 2016E EV/Production (US$/boe/d) Chart 43: Tight Oil Producers’ EV/Net Proved Reserves (US$/boe)

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Table 2 provides economic and valuation comparables for Alberta-focused light oil producers and competing U.S. producers by region.


Sector Comment

Table 2: ‘Tight Oil’ Focused Producers – Alberta vs. U.S.

Supply Cost ($/boe) F&D Price ROCE Recyc EV/EBITDA EV/boe/d EV/BoeAlberta Producers: Ticker 2014 3-Year $/boe $/boe % Ratio 2015 2016 2015 2016 2014Cardium Focus:

Bonterra BNE $69.16 $64.89 $16.27 $80.35 4.7% 3.9x 8.3x 6.3x $60,803 $60,297 $12.39Pennwest PWT $75.95 $94.23 $14.78 $86.22 -16.5% 2.2x 6.5x 6.5x $29,277 $31,063 $7.00Whitecap* WCP $93.65 $104.04 $27.56 $77.93 19.1% 1.8x 7.9x 7.3x $90,705 $83,605 $23.62

Deep Basin/Other:Arc Resources ARX $120.54 $121.80 $47.52 $77.63 8.8% 1.3x 8.5x 7.9x $58,612 $56,564 $17.64Cardinal* CJ $106.41 $134.56 $23.40 $67.79 10.2% 1.5x 5.9x 7.3x $43,856 $42,003 $15.31Journey* JOY $87.40 $94.62 $21.78 $72.23 -24.2% 1.8x 2.6x 1.9x $14,435 $13,984 $5.19Long Run* LRE $75.58 $80.87 $17.36 $76.09 -13.4% 2.6x 4.5x 4.8x $17,153 $19,745 $5.42Pengrowth PGF $131.69 $126.84 $38.02 $67.02 -9.8% 0.6x 5.5x 5.0x $35,600 $34,111 $8.15RMP* RMP $88.09 $112.84 $41.64 $80.92 10.6% 0.7x 3.1x 3.2x $24,175 $22,230 $11.33Surge* SGY $104.23 $118.39 $26.67 $67.11 -1.4% 1.6x 9.5x 10.1x $71,459 $82,157 $17.18Alberta Median $106.03 $111.21 $27.53 $76.86 1.7% 1.7x 6.2x 6.4x $39,728 $38,057 $11.86ers

Bakken:Whiting WLL $100.39 $105.18 $17.74 $77.72 1.6% 2.8x 5.7x 6.6x $47,789 $53,932 $10.02Oasis OAS $96.16 $99.04 $23.49 $82.73 14.1% 2.1x 4.3x 7.2x $76,105 $78,010 $13.82Northern* NOG $104.95 $108.82 $26.53 $79.13 13.0% 2.0x 4.2x 6.1x $69,968 $70,842 $11.25Continental CLR $107.39 $95.78 $21.04 $80.63 11.3% 3.7x 9.4x 8.7x $76,518 $75,655 $12.84Bakken $95.93 $98.70 $21.69 $79.88 7.8% 2.5x 5.0x 6.9x $73,036 $73,249 $12.05

Permian:Approach* AREX $100.84 $116.87 $14.32 $61.60 6.4% 3.1x 4.4x 5.8x $37,882 $42,091 $3.89Concho CXO $105.24 $110.07 $24.00 $83.18 8.1% 2.5x 8.8x 9.3x $105,468 $101,746 $23.59Laredo LPI $171.69 $121.90 $29.79 $83.07 12.0% 1.4x 6.8x 9.3x $95,628 $108,590 $13.02Pioneer PXD $112.02 $124.61 $29.06 $62.02 10.9% 1.2x 11.6x 10.9x $93,499 $84,525 $23.45Cimarex XEC $78.42 $90.25 $18.05 $62.68 10.1% 2.5x 13.2x 11.6x $64,884 $57,733 $20.05Resolute* REN $84.45 $144.28 $8.65 $83.49 0.4% 3.1x 5.5x 7.0x $56,529 $65,527 $9.83Energen EGN $136.92 $138.20 $41.92 $82.48 13.3% 0.9x 6.1x 9.6x $74,564 $62,050 $12.59Permian $104.40 $112.67 $24.49 $82.48 9.9% 2.5x 6.8x 9.3x $74,564 $65,527 $13.02

Eagle Ford:Carrizo CRZO $93.58 $111.16 $20.83 $81.32 11.9% 2.0x 9.8x 8.5x $86,188 $85,061 $20.10Comstock CRK $150.49 $136.22 $63.10 $92.01 -0.8% 1.1x 8.3x 10.4x $39,546 $38,462 $11.99SM SM $91.36 $88.00 $19.77 $60.02 18.9% 1.7x 4.2x 5.7x $27,473 $30,050 $8.83EP Energy EPE $110.86 $103.04 $28.13 $86.71 11.4% 3.1x 4.0x 5.6x $58,134 $58,469 $9.98Matador MTDR $42.30 $41.34 $7.67 $87.35 10.9% 8.6x 8.9x 11.5x $72,081 $69,068 $26.49Penn Virginia* PVA $96.74 $116.67 $27.12 $79.04 -18.9% 0.0x 5.0x 6.1x $66,757 $80,542 $12.74Sanchez SN $92.89 $124.71 $21.23 $69.88 0.2% 2.2x 5.4x 6.6x $32,106 $32,419 $11.70Newfield NFX $92.48 $107.05 $20.66 $64.09 9.0% 1.7x 6.4x 6.3x $50,261 $46,899 $11.53Eagle Ford $91.34 $92.49 $26.43 $80.18 7.2% 1.9x 5.9x 6.5x $54,197 $52,684 $11.85

Niobrara:Noble NBL $201.39 $130.65 $68.95 $76.73 9.4% 0.9x 7.4x 8.1x $50,329 $45,248 $12.19PDC PETD $123.60 $95.49 $23.65 $68.62 11.7% 1.4x 6.0x 5.2x $65,344 $48,599 $10.69Bonanza Creek BCEI $145.77 $127.93 $41.49 $81.21 3.7% 1.2x 4.4x 6.9x $40,918 $39,714 $12.74Carrizo CRZO $93.58 $111.16 $20.83 $81.32 11.9% 2.0x 9.8x 8.5x $86,188 $85,061 $20.10Niobrara $119.78 $102.30 $27.29 $78.97 8.5% 1.3x 6.7x 7.5x $57,837 $46,924 $12.47U.S. Median $106.59 $100.64 $25.51 $80.63 8.4% 2.4x 6.1x 7.2x $65,344 $62,050 $12.59


Oil Sands

Oil Sands producers have generated median returns roughly in line with competing U.S. tight oil producers in recent years. This said, it is important to recognize that the oil sands industry is dominated by large cap, integrated oil companies that generate outsized returns from the downstream refining business that supplement upstream results. Small pure-play oil sands producers, like Connacher (not included here) have in contrast reported losses on capital in


Sector Comment

recent years. The group has historically traded at a slight discount to U.S. tight oil producers, with the notable exception of 2015, as low oil prices have been much more impactful on earnings and cash flow to oil sands producers than conventional peers.

Chart 44: Oil Sands/U.S. Tight Oil – 2016E EV/EBITDA vs. ROCE

Chart 45: Oil Sands / U.S. Tight Oil Historical Forward EV/EBITDA

CVECOS

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AB Median: 8.7%

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Implied supply costs to oil sands producers have also been higher than U.S. tight oil plays, despite materially lower upfront F&D costs.

Chart 46: Oil Sands / U.S. Tight Oil Supply Costs (US$/boe) Chart 47: Oil Sands / U.S. Tight Oil F&D Costs (US$/ boe)

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Oil sands F&D costs tend to be materially lower than competing projects due to the large resource scale; however, the long-lead nature of oil sands projects, pricing discounts and higher operating costs generally offset this on bottom line results as indicated by a lower average recycle ratio (Charts 48–49).


Sector Comment

Chart 48: Oil Sands Realized Pricing vs. U.S. (US$/ boe) Chart 49: Oil Sands Recycle Ratio vs. U.S. Peers

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Oil sands producers trade at a premium valuation to average U.S. peers on production given the industry’s very low decline rate; however, reserves values are heavily discounted due to higher future costs and deteriorating economics.

Chart 50: Oil Sands 2016E EV/Production (US$/boe/d) Chart 51: Tight Oil Producers EV/Net Proved Reserves (US$/boe)

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Table 1 provides economic and valuation comparables for Alberta focused light oil producers and competing U.S. producers by region.


Sector Comment

Table 3: Oil Sands vs. U.S. Tight Oil Producers

Supply Cost ($/boe) F&D Price ROCE Recyc EV/EBITDA EV/boe/d EV/BoeCAD Ticker 2014 3-Year $/boe $/boe % Ratio 2015 2016 2015 2016 2014

Cenovus CVE $109.70 $111.98 $16.90 $72.09 8.7% 2.3x 7.6x 7.4x $61,563 $58,397 $7.22Canadian Oil Sands COS $95.29 $92.59 $15.30 $95.20 7.6% 2.2x 62.5x 7.3x $49,660 $43,087 $6.70Connacher* CLL $104.28 $101.97 $6.74 $65.04 -10.1% 2.1x na na na na naSuncor SU $112.24 $115.65 $27.50 $97.04 7.0% 1.6x 6.9x 5.9x $87,771 $87,679 $11.01MEG MEG $126.37 $90.12 $23.04 $58.96 10.7% 1.3x R R R R RImperial IMO $84.30 $112.32 $10.34 $84.19 12.9% 3.8x 15.1x 10.0x $105,941 $96,368 $10.60Canadian Natural CNQ $99.18 $110.11 $15.13 $69.18 10.0% 2.9x 12.7x 7.8x $48,257 $47,847 $7.52Oil Sands $104.28 $110.11 $15.30 $72.09 8.7% 2.2x 12.7x 7.4x $61,563 $58,397 $7.52Bakken $95.93 $98.70 $21.69 $79.88 7.8% 2.5x 5.0x 6.9x $73,036 $73,249 $12.05Permian $104.40 $112.67 $24.49 $82.48 9.9% 2.5x 6.8x 9.3x $74,564 $65,527 $13.02Eagle Ford $91.34 $92.49 $26.43 $80.18 7.2% 1.9x 5.9x 6.5x $54,197 $52,684 $11.85Niobrara $119.78 $102.30 $27.29 $78.97 8.5% 1.3x 6.7x 7.5x $57,837 $46,924 $12.47U.S. Median $106.59 $100.64 $25.51 $80.63 8.4% 2.4x 6.1x 7.2x $65,344 $62,050 $12.59


Conclusion

Our conclusion is that oil and gas investors and Alberta focussed companies are right to be concerned about the potential for higher royalty rates and environmental charges. The Alberta industry has generally delivered weaker investment returns than competing jurisdictions under the current royalty scheme. Any changes that lead to higher royalties could further weaken the competitive position of Alberta focussed companies and make it increasingly difficult to attract capital. We continue to recommend that investors remain cautious on the oil and gas space overall and focus on companies that have strong balance sheets and the capability to deliver growth in economic value within cash flow.


Sector Comment

Appendix A: Alberta Gas and Oil Royalty Credits

Alberta Natural Gas Royalty Programs

Key incentives to the existing natural gas royalty program in Alberta include the Horizontal New Well Royalty Rate, Natural Gas Deep Drilling Program (NGDDP) and the Shale Gas New Wells program. For new horizontal wells, the royalty rate is a maximum of 5% for all products for the first 12 production months subject to a 500 Mmcfe volume cap. The NGDDP was introduced in 2009 to encourage drilling of deeper and higher-cost natural gas wells. The NGDDP applies to the wells spud or deepened on or after May 1, 2010 with total vertical depth of 2,000+ metres. For a qualified NGDDP well, the royalty rate is 5% for a period of five years after the drilling date subject to a value cap of $8 million for development wells and $10 million for exploration wells. If a well qualifies for a 5% royalty rate outside of the scope of the NGDDP, the 5% rate is applied first, and the NGDDP benefits are applied following the expiration of the 5% rate to a maximum of five years from drill date.

The Shale Gas New Wells program applies a royalty of up to 5% for 36 producing months with no volume cap on shale gas wells drilled on or after May 1, 2010. Similarly, wells commencing production on or after May 1, 2010 may adopt the Coalbed Methane New Wells program, receiving a royalty rate of up to 5% for 36 producing months with a volume cap of 750 Mmcfe. Additional programs include the Otherwise Flared Solution Gas Royalty Waiver Program (OFSG), wherein a royalty may be waived on solution gas and gas by-products that are uneconomic to conserve, and the Innovative Energy Technologies Program.

Conventional Crude Oil Royalty Programs

Effective January 2011, the royalty rate range for existing conventional oil wells was reset lower to 0–40% from 0–50% in the original 2009 framework. A New Well Royalty Rate was implemented whereby new oil wells and some wells recommencing production are subject to a maximum 5% royalty rate for all products for 12 production months with a cap of 50 Mboe. Similar to natural gas, the Horizontal Oil Royalty Rate program stipulates that horizontal oil wells spud on or after May 2010 are subject to a maximum 5% rate for all products until time or volume limits are reached (as shown in Figure 2).

Figure 2: Horizontal Oil Royalty Rate Program Thresholds

Measured Depth (metres) Maximum eligibility (months) Volume cap (Boe)

Less than 2,500 18 50,000

2,500 up to 3,000 24 60,000

3,000 up to 3,500 30 70,000

3,500 up to 4,000 36 80,000

4,000 up to 4,500 42 90,000

More than 4,500 48 1,00,000

Source: BMO Capital Markets, Company Reports

Other royalty programs include the Deep Oil Exploration Well Program, and Enhanced Recovery of Oil Royalty Reduction. The Deep Oil program provides a royalty holiday of up to $1 million per well on wildcat and deep pool exploration tests with vertical depths of 2,000+ metres. Under the program, royalties are not payable on oil produced for the first 12 months, until the cumulative value of the payable royalty equals $1 million or five years from the finished drilling date. The Enhanced Recovery of Oil Royalty Reduction program provides for sharing with the Crown the incremental costs of enhanced oil recovery via a reduction in


Sector Comment

royalties on incremental, tertiary recovery production. Similar to the natural gas framework, crude oil pilot and demonstration projects approved under the Innovative Energy Technologies Program are eligible to receive royalty adjustments.


Sector Comment

IMPORTANT DISCLOSURES Analyst's Certification I, Randy Ollenberger / Jared Dziuba, CFA, hereby certify that the views expressed in this report accurately reflect my personal views about the subject securities or issuers. I also certify that no part of my compensation was, is, or will be, directly or indirectly, related to the specific recommendations or views expressed in this report. Analysts who prepared this report are compensated based upon (among other factors) the overall profitability of BMO Capital Markets and their affiliates, which includes the overall profitability of investment banking services. Compensation for research is based on effectiveness in generating new ideas and in communication of ideas to clients, performance of recommendations, accuracy of earnings estimates, and service to clients. Analysts employed by BMO Nesbitt Burns Inc. and/or BMO Capital Markets Limited are not registered as research analysts with FINRA (exceptions: Alex Arfaei and Brodie Woods). These analysts may not be associated persons of BMO Capital Markets Corp. and therefore may not be subject to the NASD Rule 2711 and NYSE Rule 472 restrictions on communications with a subject company, public appearances and trading securities held by a research analyst account. Company Specific Disclosures For Important Disclosures on the stocks discussed in this report, please go to http://researchglobal.bmocapitalmarkets.com/Public/Company_Disclosure_Public.aspx. Distribution of Ratings (June 30, 2015)

Rating Category

BMO Rating

BMOCM US Universe*

BMOCM USIB Clients**

BMOCM USIB Clients***

BMOCM Universe****

BMOCM IB Clients*****

Starmine Universe

Buy Outperform 42.0% 21.9% 53.3% 41.9% 54.3% 54.6% Hold Market Perform 53.5% 14.4% 44.8% 53.3% 44.4% 40.0% Sell Underperform 4.4% 7.4% 1.9% 4.7% 1.3% 5.4%

* Reflects rating distribution of all companies covered by BMO Capital Markets Corp. equity research analysts. ** Reflects rating distribution of all companies from which BMO Capital Markets Corp. has received compensation for Investment Banking services as

percentage within ratings category. *** Reflects rating distribution of all companies from which BMO Capital Markets Corp. has received compensation for Investment Banking

services as percentage of Investment Banking clients. **** Reflects rating distribution of all companies covered by BMO Capital Markets equity research analysts. ***** Reflects rating distribution of all companies from which BMO Capital Markets has received compensation for Investment Banking services as

percentage of Investment Banking clients. Rating and Sector Key (as of April 5, 2013): We use the following ratings system definitions: OP = Outperform - Forecast to outperform the analyst’s coverage universe on a total return basis Mkt = Market Perform - Forecast to perform roughly in line with the analyst’s coverage universe on a total return basis Und = Underperform - Forecast to underperform the analyst’s coverage universe on a total return basis (S) = speculative investment; NR = No rating at this time; R = Restricted – Dissemination of research is currently restricted.

BMO Capital Markets' seven Top 15 lists guide investors to our best ideas according to different objectives (CDN Large Cap, CDN Small Cap, US Large Cap, US Small cap, Income, CDN Quant, and US Quant have replaced the Top Pick rating). Prior BMO Capital Markets Ratings System (January 4, 2010–April 4, 2013): http://researchglobal.bmocapitalmarkets.com/documents/2013/prior_rating_system.pdf Other Important Disclosures For Other Important Disclosures on the stocks discussed in this report, please go to http://researchglobal.bmocapitalmarkets.com/Public/Company_Disclosure_Public.aspx or write to Editorial Department, BMO Capital Markets, 3 Times Square, New York, NY 10036 or Editorial Department, BMO Capital Markets, 1 First Canadian Place, Toronto, Ontario, M5X 1H3.

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Sector Comment

lending arrangements with, or provide other remunerated services to, many issuers covered by BMO Capital Markets. The opinions, estimates and projections contained in this report are those of BMO Capital Markets as of the date of this report and are subject to change without notice. BMO Capital Markets endeavours to ensure that the contents have been compiled or derived from sources that we believe are reliable and contain information and opinions that are accurate and complete. However, BMO Capital Markets makes no representation or warranty, express or implied, in respect thereof, takes no responsibility for any errors and omissions contained herein and accepts no liability whatsoever for any loss arising from any use of, or reliance on, this report or its contents. Information may be available to BMO Capital Markets or its affiliates that is not reflected in this report. The information in this report is not intended to be used as the primary basis of investment decisions, and because of individual client objectives, should not be construed as advice designed to meet the particular investment needs of any investor. This material is for information purposes only and is not an offer to sell or the solicitation of an offer to buy any security. BMO Capital Markets or its affiliates will buy from or sell to customers the securities of issuers mentioned in this report on a principal basis. BMO Capital Markets or its affiliates, officers, directors or employees have a long or short position in many of the securities discussed herein, related securities or in options, futures or other derivative instruments based thereon. The reader should assume that BMO Capital Markets or its affiliates may have a conflict of interest and should not rely solely on this report in evaluating whether or not to buy or sell securities of issuers discussed herein.

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Documents

Royalty Review 0815 BMO (00000002)