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EQUITY RESEARCH | DAILY EDGEFriday, July 15, 2016, Pre-market

For Reg AC Certification and important disclosures see Appendix A of this report. Analysts employed by non-U.S. affiliates arenot registered/qualified as research analysts with FINRA in the U.S.

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Time of dissemination: July 15, 2016, 05:02 ET.

Oil & Gas - E&PRoyalty Review Roundup: Understanding the Overlays

OUR TAKE: The Alberta Department of Energy held a Technical Session in Calgaryon July 14 to discuss the details of two strategic programs recommended by theAlberta Royalty Review Advisory Panel’s Report as the Modernized Royalty Framework(MRF) replaces the current Alberta Royalty Framework (ARF) in the New Year. Theseinitiatives include the Enhanced Hydrocarbon Recovery Program (EHRP) and theEmerging Resources Program (ERP). We do not expect these programs to materiallyimpact the market in the near term but we detail the strategies of both and discusslonger term implications in our overview and analysis below.

KEY POINTS

Emerging Resource Program (ERP). We view the ERP as a positive program forthe industry, but do not believe it will have a material impact on aggregate capitalinvestment over the near-term. While an early stage royalty incentive will act as asweetener, we continue to believe that exploration projects will make the cut basedon their longer-term economic potential. Our analysis of two type wells for early stageresource plays (with drill and complete costs adjusted to meet the 150% of C* hurdlefor the program) suggest that the program will only moderately shift the returns ofhigher cost early life of project wells, with the most significant benefit coming at highercommodity prices (see Exhibit 3). Ultimately, the economic impact of the ERP willdepend on the productivity and economic characteristics of the play within a givenproject. We do note that the program should prove most beneficial to producers in caseswhere they are able to quickly improve efficiencies in an exploration play and increasethe economic returns of their wells early on in the program (thereby maximizing theroyalty incentive benefit). We also believe that the ERP should provide more benefit tolarger exploration programs where the first 15% of wells in the project represent a largerproportion of the drilling inventory compared to the higher cost early experimental wells.

Enhanced Hydrocarbon Recovery Program (EHRP). As a policy overlay, in our viewthe EHRP makes sense as it was not captured in the initial roll-out of the MRF andtherefor endeavours to respect that increased hydrocarbon recovery schemes requireincremental up-front capital, longer response times, and the ability to shoulder higheroperating costs. The Alberta Government estimates 22% of the province’s conventionalcrude oil has been recovered to date. The opportunity to increase recoveries over timeoffers both industry and the province opportunities for further economic benefits. In ourview, the prize in many cases could be substantial with respect to not only traditionalhigh permeability and porosity reservoirs, but also in regard to further opportunitiesthat have yet to play out but could be upon us in the near to medium term. Suchopportunities could include sequestration of CO2, plus the potential to more optimallyexploit tight oil reservoirs in some cases, through GOR suppression from vertical andhorizontal injectors. In this regard, we continue to generally favour businesses that havecaptured large oil in place resources given the option value incremental recoveriescould represent.

ANALYST TEAM Link to ScotiaView

Cameron Bean | Analyst403-218-6786Scotia Capital Inc. - Canada

Patrick Bryden, CFA | Analyst403-213-7750Scotia Capital Inc. - Canada

Riley Hicks, CA, MBA | Associate403-213-7760Scotia Capital Inc. - Canada

Erik Kuhn, CFA | Associate403-213-7349Scotia Capital Inc. - Canada

Justin Strong, MBA, CFA | Associate403-213-7328Scotia Capital Inc. - Canada

https://www.scotiaview.com/authors/cbean

mailto:[email protected]





Emerging Resource Program

The Emerging Resource Program (ERP) is one of two strategic overlays recommended by the Royalty

Review Advisory Panel. The ERP is intended to promote the exploration and delineation of higher-cost and

higher-risk areas that have the potential to deliver significant resource, with a view toward increasing the

province’s royalty revenue over the longer-term. The program will come into effect on January 1, 2017 with a

planned 10 year term. Industry participants will have eight years from the program’s inception to apply for

acceptance into the ERP.

Applicants to the ERP (note: a single application may include more than one leaseholder) must define a

Project Area (PA) consisting of 18 to 144 sections of held rights within a single development interval. The

leases need not be contiguous; however, non-contiguous sections may result in a larger Project Evaluation

Boundary (PEB) being applied.

The PEB includes the PA and a buffer around the PA of a minimum of two sections or half the number of

section between the most distant non-contiguous sections in the PA (see Exhibit 1).

To be approved, the project must meet several criteria, including:

Large resource in place with the potential for longer-term commercial development (the steps to

commercialty must be provided in the application).

Early stage in its development lifecycle – defined as having less than 10% the inventory (with a base

rate of four wells per section; includes producing and abandoned wells, dry holes and the applicant’s

Exhibit 1: Project Area and Project Evaluation Boundary

Source: Government of Alberta; Scotiabank GBM.

Two Sections

Two Sections

Eight Sections

Four Sections

Four Sections

Four Sections

Four Sections


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confidential wells) within the PEB and less than 15% of the inventory (producing wells only) within the

PA drilled.

Forecast peak production of at least 5,000 boe/d.

High cost wells that are unlikely to lead to commercial development without the program. The initial

drilling and completion cost threhold for wells will be set at least 150% of the C* value that would be

applied to the well.

Life of project royalties of at least 150% of those that would be paid without the ERP.

Projects may be amended subject to certain rules; however expansion to project boundaries that would

increase the number of eligible wells or a decrease of more than 20% to the initial project size will require

the submission of a new program application. Also, land removed from an ERP project cannot be reused

and added to a different project application.

Projects accepted into the ERP will receive a C* multiplier benefit of 1.5x - 2.0x the typical C* (defined as

C*ERP) value on up to 15% of the inventory within the PA over a drilling period of up to 10 years (the benefit

may be pooled across the planned project wells within the other constraints of the program; eligible wells

within a project will receive a five year run-off period at the end of the 10 years to draw down any remaining

benefit). The amount of time the applicant will have to drill beneficial wells under the program and the initial

C* multiplier benefit will be based on the percentage of inventory drilled within the PEB (see Exhibit 2).

Exhibit 2: Emerging Resource Program Time and Benefit Scale


012345678910

1.00

1.25

1.50

1.75

2.00

2.25

0 1 2 3 4 5 6 7 8 9 10

Years in Program

C*

Mu

ltip

lier

Years

Total Project Evaluation Boundary Inventory Previously Drilled

0.00% -

4.99%

5.00% -

5.99%

6.00% -

6.99%

7.00% -

7.99%

8.00% -

8.99%

9.00% -

10.00%


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Our Take. We view the ERP as a positive program for the industry, but do not believe it will have a material

impact on aggregate capital investment over the near-term. While an early stage royalty incentive will act as

a sweetener, we continue to believe that exploration projects will make the cut based on their longer-term

economic potential. Our analysis of two type wells for early stage resource plays (with drill and complete

costs adjusted to meet the 150% of C* hurdle for the program) suggest that the program will only moderately

shift the returns of higher cost early life of project wells, with the most significant benefit coming at higher

commodity prices (see Exhibit 3). Ultimately, the economic impact of the ERP will depend on the productivity

and economic characteristics of the play within a given project. We do note that the program should prove

most beneficial to producers in cases where they are able to quickly improve efficiencies in an exploration

play and increase the economic returns of their wells early on in the program (thereby maximizing the royalty

incentive benefit). We also believe that the ERP should provide more benefit to larger exploration programs

where the first 15% of wells in the project represent a larger proportion of the drilling inventory compared to

the higher cost early experimental wells.

We will continue to watch for clarification on detail of the ERP (e.g. Will the Lower Montney D1 be treated as

a separate interval from the Middle Montney D2 for the classification of drilling inventory and project

maturity) and update our analysis as the program is implemented and utilized by industry participants.

Exhibit 3: Well Economic Sensitivities to ERP C* Benefit Multipliers


Edmonton Par [C$/bbl] $50.00 $68.75 $81.18 $95.00 $116.52 Edmonton Par [C$/bbl] $50.00 $68.75 $81.18 $95.00 $116.52

AECO [C$/mcf] $2.20 $2.90 $3.60 $4.30 $5.00 AECO [C$/mcf] $2.20 $2.90 $3.60 $4.30 $5.00

1.0 x C* [$000] $7,500 1.0 x C* [$000] $13,143

NPV (after-tax) [$000] -$5,676 -$2,905 -$1,402 $84 $2,031 NPV (after-tax) [$000] -$11,900 -$6,676 -$2,965 $378 $3,814

PIR (after-tax) [x] 0.6x 0.8x 0.9x 1.0x 1.2x PIR (after-tax) [x] 0.5x 0.7x 0.9x 1.0x 1.2x

IRR (after-tax) [%] -5% 2% 5% 9% 16% IRR (after-tax) [%] -5% 1% 5% 10% 15%

Payback [months] 841 199 118 75 42 Payback [months] 841 236 115 76 54

1.5 x C* [$000] $11,250 1.5 x C* [$000] $19,714

NPV (after-tax) [$000] -$5,657 -$2,524 -$872 $698 $2,763 NPV (after-tax) [$000] -$11,691 -$6,224 -$2,381 $1,064 $4,778




1.75 x C* [$000] $13,124 1.75 x C* [$000] $22,999

NPV (after-tax) [$000] -$5,657 -$2,524 -$692 $949 $3,067 NPV (after-tax) [$000] -$11,595 -$6,040 -$2,123 $1,409 $5,145




2.0 x C* [$000] $14,999 2.0 x C* [$000] $26,285

NPV (after-tax) [$000] -$5,657 -$2,524 -$692 $1,177 $3,393 NPV (after-tax) [$000] -$11,507 -$5,863 -$1,907 $1,696 $5,551




Hz. Gas Well: 3,470m TVD; 4,770 TMD; 20 stages and 90t/stage; $20.2M DC&T Cost;

9.0 Bcfe EUR (84% gas)

Hz. Oil Well: 2,300m TVD; 4,400 TMD; 30 stages and 60t/stage; $11.8M DC&T Cost;

330 mboe EUR (7% gas)

Note: Economics based on 1) 9% (after-tax) discount rate; 2) 2%/yr commodity price and cost inflation; and 3) +5% C5+, -30% C4, -75% C3 and -75% C2 NGL differentials. Midcycle Capital includes drilling,

completion and tie-in (DC&T), go-forward infrastructure and dry hole costs.


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Enhanced Hydrocarbon Recovery Program

What is the big picture? The adage ‘if you want to find oil, go to where it has already been found’ rings

true for increased and enhanced oil recovery opportunities in Alberta. Exhibit 4 features an overview of key

enhanced hydrocarbon areas in Canada. The simple point to make is that there are material amounts of

known hydrocarbons yet to be exploited that represent significant option value for both the Crown in Alberta

and the shareholders in equities exposed to these large oil in place assets.

Out with the old and in with the new (the old helps us understand the new). The EHRP will replace the

current Enhanced Oil Recovery Program (EORP) effective January 1, 2017. The soon to be old program

(EORP) applied to previously producing reservoirs and tertiary recovery methods for oil through injectants

such as hydrocarbons, CO2, nitrogen, chemicals, or other Department of Energy approved agents. The

EORP did not include secondary recovery methods (water injection) for oil.

Exhibit 4: WCSB Enhanced Hydrocarbon Recovery Areas – Long Term Opportunity

Source: Company reports; Scotiabank GBM; CAPP, Statistical Handbook for Canada’s Upstream Oil and Gas Industry, November 2011;

Zargon Oil & Gas.


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Key details of EHRP. The new plan will not only apply to oil but also to natural gas and NGLs. The

Department of Energy will evaluate applications, based on technical and economic merit, and the Alberta

Energy Regulator will provide approvals post January 1, 2017. For both secondary and tertiary recovery

projects, a 5% flat royalty applies for a limited benefit period, which once exhausted will see royalties kick up

to the royalty rates applicable under MRF. For secondary recovery projects (water, gas, and polymer), the

benefit period will be at the discretion of the province. For tertiary projects (CO2, nitrogen, or other Minister

approved agents) the benefit period is set at 75% of the benefit period that would otherwise have been

calculable in the ARF’s old EORP program. The intention behind the one-quarter reduction in benefit period

is solve for return neutrality versus the prior royalty framework. In other words, the MRF tail royalty rate is

expected to be lower, which means the new up front benefit period permitted is correspondently shorter. In

all cases, the maximum benefit period is 90 months (7.5 years), with specific timeframes dependent on

recovery schemes and expected incremental recoverable hydrocarbons.

Key criteria to be eligible. Projects must feature:

Technical and economic merit.

Injectants of water, hydrocarbons, CO2, nitrogen, chemicals, or other Minister approved agents.

Recover more hydrocarbon than base recovery scheme.

Provide the Crown with a net royalty benefit over the life of the scheme.

New water or gas schemes must occur in areas not previously exploited in this manner.

In effect, a piloting phase to ultimately transition to a permanent MRF-style structure. Given the

Department of Energy’s EORP did not include waterfloods, the Province does not have cost experience with

these kinds of exploitation projects, with respect to royalty processes, as it transitions to EHRP. As such,

the Department of Energy expects to build these programs over two years in order to develop appropriate

structures that would equate more to an R-C* (i.e.: revenue minus cost) model inherent in the MRF, similar

to how the Emerging Resources Program (ERP) is structured, as detailed in this publication. The

determination of what the appropriate benefit period is for each style of recovery method is the key task for

the Department of Energy over the next couple years.

Bottom line for secondary and tertiary recovery in Alberta remains option value on resources. As a

policy overlay, in our view the EHRP makes sense as it was not captured in the initial roll-out of the MRF

and therefore endeavours to respect that increased hydrocarbon recovery schemes require incremental up-

front capital, longer response times, and the ability to shoulder higher operating costs. The Alberta

Government estimates 22% of the province’s conventional crude oil has been recovered to date. The

opportunity to increase recoveries over time offers both industry and the province opportunities for further

economic benefits. In our view, the prize in many cases could be substantial with respect to not only

traditional high permeability and porosity reservoirs, but also in regard to further opportunities that have yet

to play out but could be upon us in the near to medium term. Such opportunities could include sequestration

of CO2, plus the potential to more optimally exploit tight oil reservoirs in some cases, through GOR

suppression from vertical and horizontal injectors. In this regard, we continue to generally favour

businesses that have captured large oil in place resources given the option value incremental recoveries

could represent.

Key enhanced oil recovery areas in Alberta. Exhibit 5 features the top waterflooded pools in the

province. A typical expected ultimate recovery for a waterflood pool is approximately one-third of original oil

in place but the recovery factor can clearly vary by pool given differences in geological, reservoir, and

hydrocarbon characteristics. The WF/Primary ratio in the table can provide a sense for secondary and/or

tertiary recovery potential.


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Exhibit 6 further provides an overview of key characteristics for top pools in Alberta and includes the voidage

replacement ratio (VRR), which over time needs to be a minimum of 1.0x to maintain reservoir pressure,

which is fundamental to enhanced recoveries.

Companies in our coverage universe with exposure to key Alberta enhanced oil recovery areas include:

Cardium: ARX, BNE, BNP, PWT, PGF, VET and WCP

Swan Hills: ARX, CPG, PGF and PWT

Other (Mitsue, Chauvin, Wainwright, Montney): CJ, EGL, RMP, SGY

Exhibit 5: Top Waterflooded Pools in Alberta

Source: GeoScout; ERCB; Scotiabank GBM estimates.

Exhibit 6: Characteristics of Top Waterflooded Pools in Alberta

Source: GeoScout; ERCB; Scotiabank GBM estimates.


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Early Opt-In to the Modernized Royalty Framework (MRF)

The government of Alberta recently announced that companies can apply to have the MRF framework

applied to wells (non-oilsand wells) early so that as companies allocate capital to drilling programs they can

drill a well today that would have not been drilled under the Alberta Royalty Framework. The company needs

to demonstrate that the wells under consideration would otherwise not have been drilled at all (companies

planning on drilling wells in 2017 cannot elect to speed up the drill time and drill in 2H16). A well accepted in

the early adoption program will continue to pay the existing royalty rates until 2017, at which time the

royalties will be recalculated in accordance with the MRF formulas.

Well Interventions (Deepening, Lengthening and Re-Fracs)

The Province expects to release details of the treatment of well interventions such as deepening,

lengthening and re-fracs under the MRF over the near-term. At this time the details are unclear, however we

expect that C* will be allocated to wells that receive qualifying interventions (e.g. use of $50,000 of sand in a

re-frac). We will watch for details on these aspects of the MRF and provide analysis in due course.


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Appendix A: Important Disclosures

Company Disclosures (see legend below)*

ARC Resources Ltd. HH, I, VS269Bonavista Energy Corporation G, I, UCardinal Energy Ltd. G, I, UCrescent Point Energy Corp. IEagle Energy Inc. VS270Pengrowth Energy Corporation I, VS028RMP Energy Inc. G, IStone Energy Corp V19Whitecap Resources Inc. G, I, U

We, Patrick Bryden and Cameron Bean, certify that (1) the views expressed in this report in connection with securities or issuers thatwe analyze accurately reflect our personal views and (2) no part of our compensation was, is, or will be directly or indirectly, related tothe specific recommendations or views expressed by us in this report.

This research report was prepared by employees of Scotia Capital Inc. and/or its affiliates who have the title of Analyst.

All pricing of securities in reports is based on the closing price of the securities’ principal marketplace on the night before the publicationdate, unless otherwise explicitly stated.

All Equity Research Analysts report to the Head of Equity Research. The Head of Equity Research reports to the Managing Directorand Co-Head, Global Capital Markets, who is not and does not report to the Head of the Investment Banking Department. Scotiabank,Global Banking and Markets has policies that are reasonably designed to prevent or control the sharing of material non-publicinformation across internal information barriers, such as between Investment Banking and Research.

The compensation of the research analyst who prepared this report is based on several factors, including but not limited to, the overallprofitability of Scotiabank, Global Banking and Markets, and the revenues generated from its various departments, including investmentbanking, trading fees and other types of transactions. Furthermore, the research analyst’s compensation is charged as an expenseto various Scotiabank, Global Banking and Markets departments, including investment banking. Research Analysts may not receivecompensation from the companies they cover.

Non-U.S. analysts may not be associated persons of Scotia Capital (USA) Inc. and therefore may not be subject to FINRA Rule 2241restrictions on communications with subject company, public appearances and trading securities held by the analysts.

For Scotiabank, Global Banking and Markets Research analyst standards and disclosure policies, please visit gbm.scotiabank.com/disclosures.

Scotiabank, Global Banking and Markets Research, 40 King Street West, 33rd Floor, Toronto, Ontario, M5H 1H1.

Time of dissemination: July 15, 2016, 05:02 ET.

*Legend

G Scotia Capital (USA) Inc. or its affiliates has managed or co-managed a public offering in the past 12 months.

HH The Head of Equity Research or a Supervisory Analyst owns securities of this issuer in his or her own account or in a relatedaccount.

I Scotia Capital (USA) Inc. or its affiliates has received compensation for investment banking services in the past 12 months.

U Within the last 12 months, Scotia Capital Inc. and/or its affiliates have undertaken an underwriting liability with respect toequity or debt securities of, or have provided advice for a fee with respect to, this issuer.

V19 Scotia Howard Weil is a Division of Scotia Capital (USA) Inc., a U.S. registered broker-dealer and a member of the NewYork Stock Exchange and FINRA. Scotia Capital (USA) Inc. is a wholly owned subsidiary of Scotia Capital Inc., a Canadianregistered investment dealer, and indirectly owned by The Bank of Nova Scotia. Scotia Howard Weil Research Analysts andScotiabank Research Analysts are independent from one another and their respective coverage of issuers is different. Inaddition, because they are independent from one another, Scotia Howard Weil Research Analysts and Scotiabank ResearchAnalysts may have different opinions on the short-term and long-term outlooks of local and global markets and economies.

VS028 Our Research Analyst visited the Lindbergh, Alberta, SAGD Oil Sands Project, on July 30 and November 27, 2013. Fullpayment was received from the issuer for the travel-related expenses incurred by the Research Analyst to visit this site.

VS269 Our Research Analyst visited ARC's NE BC Montney assets on a field tour of oil and gas production and infrastructuredevelopment, on July 12, 2010. No payment was received from the issuer for the travel-related expenses incurred by theResearch Analyst to visit this site.


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http://gbm.scotiabank.com/disclosures


VS270 Our Research Analyst visited the Salt Flat Field on a field tour of oil and gas production and infrastructure development, onApril 23, 2012. No payment was received from the issuer for the travel-related expenses incurred by the Research Analyst tovisit this site.


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Definition of Scotiabank, Global Banking and Markets Equity Research RatingsWe have a four-tiered rating system, with ratings of Focus Stock, Sector Outperform, Sector Perform, and Sector Underperform. Eachanalyst assigns a rating that is relative to his or her coverage universe or an index identified by the analyst that includes, but is notlimited to, stocks covered by the analyst.

The rating assigned to each security covered in this report is based on the Scotiabank, Global Banking and Markets research analyst’s12-month view on the security. Analysts may sometimes express to traders, salespeople and certain clients their shorter-term viewson these securities that differ from their 12-month view due to several factors, including but not limited to the inherent volatility of themarketplace.Ratings

Focus Stock (FS)The stock represents an analyst’s best idea(s); stocks in thiscategory are expected to significantly outperform the average12-month total return of the analyst’s coverage universe or anindex identified by the analyst that includes, but is not limited to,stocks covered by the analyst.

Sector Outperform (SO)The stock is expected to outperform the average 12-month totalreturn of the analyst’s coverage universe or an index identifiedby the analyst that includes, but is not limited to, stocks coveredby the analyst.

Sector Perform (SP)The stock is expected to perform approximately in line withthe average 12-month total return of the analyst’s coverageuniverse or an index identified by the analyst that includes, butis not limited to, stocks covered by the analyst.

Sector Underperform (SU)The stock is expected to underperform the average 12-monthtotal return of the analyst’s coverage universe or an indexidentified by the analyst that includes, but is not limited to,stocks covered by the analyst.

Other RatingsTender – Investors are guided to tender to the termsof the takeover offer.

Under Review – The rating has been temporarilyplaced under review, until sufficient information hasbeen received and assessed by the analyst.

Risk RankingAs of June 22, 2015, Scotiabank, Global Bankingand Markets discontinued its Low, Medium, and Highrisk rankings. The Speculative risk ranking reflectsexceptionally high financial and/or operational risk,exceptionally low predictability of financial results,and exceptionally high stock volatility. The Directorof Research and the Supervisory Analyst jointlymake the final determination of the Speculative riskranking.

Scotiabank, Global Banking and Markets Equity Research Ratings Distribution*

Distribution by Ratings and Equity and Equity-Related Financings*

42.7%

50.4%

6.8%

10.6% 9.5% 0.2%Sector Outperform Sector Perform Sector

Underperform

0%

20%

40%

60%

* As of June 30, 2016. Source: Scotiabank GBM.

Percentage of companies covered byScotiabank, Global Banking and Markets EquityResearch within each rating category.

Percentage of companies within each ratingcategory for which Scotiabank, Global Bankingand Markets has undertaken an underwritingliability or has provided advice for a fee withinthe last 12 months.

For the purposes of the ratings distribution disclosure FINRA requires members who use a ratings system with terms differentthan “buy,” “hold/neutral” and “sell,” to equate their own ratings into these categories. Our Focus Stock, Sector Outperform,Sector Perform, and Sector Underperform ratings are based on the criteria above, but for this purpose could be equated tostrong buy, buy, neutral and sell ratings, respectively.


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General Disclosures

This report has been prepared by analysts who are employed by the Research Department of Scotiabank, Global Banking and Markets.Scotiabank, Global Banking and Markets Research produces research reports under a single marketing identity referred to as “globallybranded research” under U.S. rules. This research is produced on a single global research platform with one set of rules which meetthe most stringent standards set by regulators in the various jurisdictions in which the research reports are produced. In addition, theanalysts who produce the research reports, regardless of location, are subject to one set of policies designed to meet the most stringentrules established by regulators in the various jurisdictions where the research reports are produced.

The frequency of reports is determined by the analyst on a case-by-case basis, driven by external market factors and issuerannouncements. Analysts will endeavour to review and publish such estimates and recommendations as soon as possible after therelease of material information by the issuer or the occurrence of other relevant events. This will typically involve, at a minimum, asummary of quarterly earnings releases.

Scotia Capital Inc. or an affiliate thereof owns or controls an equity interest in TMX Group Limited and in excess of 1% of the issuedand outstanding equity securities thereof. In addition, an affiliate of Scotia Capital Inc. is a lender to TMX Group Limited under its creditfacilities. As such, Scotia Capital Inc. may be considered to have an economic interest in TMX Group Limited.

This report is provided to you for informational purposes only. This report is not, and is not to be construed as, an offer to sell orsolicitation of an offer to buy any securities and/or commodity futures contracts.

The securities mentioned in this report may neither be suitable for all investors nor eligible for sale in some jurisdictions where thereport is distributed.

The information and opinions contained herein have been compiled or arrived at from sources believed reliable, however, Scotiabank,Global Banking and Markets makes no representation or warranty, express or implied, as to their accuracy or completeness.

Scotiabank, Global Banking and Markets has policies designed to make best efforts to ensure that the information contained in thisreport is current as of the date of this report, unless otherwise specified.

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United States: This report is distributed by Scotia Capital (USA) Inc., a subsidiary of Scotia Capital Inc., and a registered U.S. broker-dealer. All transactions by a U.S. investor of securities mentioned in this report must be effected through Scotia Capital (USA) Inc.

Non-U.S. investors wishing to effect a transaction in the securities discussed in this report should contact a Scotiabank, Global Bankingand Markets entity in their local jurisdiction unless governing law permits otherwise.

™ Trademark of The Bank of Nova Scotia. Used under license, where applicable. Scotiabank, together with "Global Banking andMarkets," is a marketing name for the global corporate and investment banking and capital markets businesses of The Bank ofNova Scotia and certain of its affiliates in the countries where they operate, including Scotia Capital Inc., Scotia Capital (USA) Inc.,Scotiabanc Inc., Citadel Hill Advisors L.L.C., The Bank of Nova Scotia Trust Company of New York, Scotiabank Europe plc, Scotiabank(Ireland) Limited, Scotiabank Inverlat S.A., Institución de Banca Múltiple, Scotia Inverlat Casa de Bolsa S.A. de C.V., Scotia InverlatDerivados S.A. de C.V. – all members of the Scotiabank Group and authorized users of the mark. The Bank of Nova Scotia isincorporated in Canada with limited liability. Scotia Capital Inc. is a member of the Canadian Investor Protection Fund and regulated bythe Investment Industry Regulatory Organization of Canada. Scotia Capital (USA) Inc. is a broker-dealer registered with the SEC and isa member of FINRA, NYSE, NFA and SIPC. Scotiabank Europe plc is authorized by the Prudential Regulation Authority and regulatedby the Financial Conduct Authority and the Prudential Regulation Authority. Scotiabank Inverlat, S.A., Scotia Inverlat Casa de Bolsa,S.A. de C.V., and Scotia Derivados, S.A. de C.V., are each authorized and regulated by the Mexican financial authorities.

Copyright © 2016 The Bank of Nova Scotia

This report and all the information, opinions, and conclusions contained in it are protected by copyright. This report may not bereproduced in whole or in part, or referred to in any manner whatsoever, nor may the information, opinions, and conclusions containedin it be referred to without prior express consent.


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Oil & Gas - E&P - Melhoff Groupmelhoffgroup.ca/content/uploads/Oil-Gas-EP-Royalty-Review-Roundup… · For Reg AC Certification and important disclosures see Appendix A of this report.

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