Andrew Phillips – President and Chief Executive Officer Pam Kazeil – Chief Financial Officer

Jeremy McCrea – Raymond James Travis Wood – National Bank of Canada Mike Dunn – GMP FirstEnergy Shailender Randhawa – RBC Capital Markets

Good morning, and thank you for dialing into the PrairieSky Royalty Q3 2017 earnings call. On the call from PrairieSky are Pam Kazeil, our CFO; Cam Proctor, COO and myself, Andrew Phillips.

Before I turn the call over to Pam to walk through the financials, I’ll provide an operational update. Production in Q3 2017 was 24,183 BOE, 48% liquids down from 25,706 BOE in Q2 and up of from 23,050 BOE per day, 46% liquids in Q3 of 2016.

This was a result of natural declines from active Q1 drilling, lower activity during spring break up and voluntary plus involuntary shut-ins of natural gas due to pipeline outages and weak pricing. In addition, plant turnarounds at Onion Lake in Lindbergh affected our bitumen royalty volumes.

Spuds in Q3 were 245 wells, up from 104 wells in Q2. Free cash flow for the quarter totaled $66.8 million.

Of this total, $44.3 million was paid in cash dividends, $9.5 million used to cancel 333,000 PrairieSky shares and $13 million went into the bank. Acquisitions for the quarter totaled $20 million, of which $16 million was used to capture large contiguous land positions on emerging oil resource plays with well capitalized operators.

First royalty oil production was achieved on one of these plays and we hope to provide investors with more information on these plays in 2018. At the end of Q3 2017, PrairieSky has received $33 million in cash lease bonus consideration, and reinvested $27 million on these aforementioned emerging oil plays.

At the end of the third quarter, PrairieSky had $102 million cash in the bank. We’ve recently evaluated some small high quality oil weighted royalty packages with growth potential and acquired a number of detailed sections in good geologic areas with multi-zonal potential.

Our friends at compliance department collected $2.2 million over the quarter. Our lease compliance team returned lands to inventory for future leasing.

The total lands returned in 2017 is 185,000 acres. Cash G&A costs per barrel were $2.29 for the quarter, and remain on target to be in the low-$3 range for the year.

Our goal remains to bring this number below $2 a barrel over the next two years. Leasing over the quarter was very active and was concentrated in the devonian age Duvernay Shale formation.

We collected over $15 million during the quarter in bonus, but more importantly brought strong technical groups that are well capitalized on to the lands. The near and medium-term outlook productivity on PrairieSky acreage has expanded as a result of these leasing arrangements.

Internal geochemical analysis and thermal maturity mapping has increased our understanding of this emerging shale play and we now estimate that PrairieSky holds over 1 million acres of land in the oil window of the Duvernay. Currently, half of this acreage is leased and further leasing is anticipated over the next 12 months.

The East Shale basin had virtually no production two years ago and is now producing over 10,000 barrels a day of 40-degree API crude or over 2% of Alberta’s conventional oil production, we expect this to double in production over the next 12 months. Thank you to our employees for your hard work and to our shareholders for their support over the three years.

I will now turn the call over to Pam to walk through the financials. Pam?

Thank you, Andrew. Good morning, everyone.

PrairieSky generated funds from operations of $66.8 million or $0.28 per share in the third quarter. This is down 11% from Q2 2017 funds from operations due to lower royalty revenue as a result of lower commodity prices and volumes in the quarter.

Average daily production for the quarter was 24,183 BOE per day. Production was comprised of natural gas volumes of 75.3 million a day, oil volumes of 9,033 barrels a day and NGL volumes of 2,600 barrels per day.

Production volumes were negatively impacted in the quarter by turnarounds and estimates for voluntary and involuntary shut in volumes as well as declines and fewer wells on stream following breakup. PrairieSky’s production volumes included 788 BOE a day from compliance activity, and 1,100 BOE a day of other prior period adjustments related to new wells on stream and better well performance.

PrairieSky collected $2.2 million a day in compliance revenue, which included – which is included in total royalty revenue of $54.2 million for the quarter. Compliance volumes will vary quarter-to-quarter and are not reported unless collection is certain.

Compliance collections since IPO totaled $35.7 million. Other revenue for the quarter was $17.5 million, which included lease rental income of $1.6 million and bonus consideration of $15.5 million, both of which are generated from our free lands.

Bonus consideration related to entering into 23 new leases with 20 different counter parties in the period. Of this $15.5 million in bonus consideration, $14.3 million related to Duvernay leasing.

Administrative expenses in the quarter totaled $8.4 million or $3.78 per BOE. Cash administrative costs were $5.1 million or $2.29 per BOE.

And PrairieSky expects cash G&A to be in a low $3 per BOE range for the year. PrairieSky declared dividends of $44.3 million during Q3, with a resulting payout ratio of 66%.

Under the normal course issuer bid, PrairieSky repurchased 333,200 common shares for $9.5 million at an average price $28.85 per share. Since instituting the normal course issuer bid in May 2016, PrairieSky’s repurchased approximately 1.7 million common shares for $57.2 million.

At September 30, 2017, PrairieSky had cash balance of $102 million, positive working capital of $98.7 million and no debt. So we’ll now turn it over to the moderator to proceed with Q&A.

Hi, guys. I was just wondering if you could provide more detail on the $20 million land acquisition.

Where this is? When you plan to disclose some of this land?

How material could the production be from this area over the next couple of years. Just any kind of additional details if you can at this time?

And after that, I just want to – one more question is, just when do you start looking at slowing down potential share buybacks and weighing off potential dividend increases? So just a couple of questions there.

Thank you, guys.

Yes. Thanks for the questions, Jeremy.

So the two different plays, we’re not disclosing any details on. We’ve now again spent $27 million acquiring land of the two plays.

One is a lighter oil play, one is a medium-gravity crude play. Both have tremendous scale.

And for competitive reasons, we won’t be talking about them until next year. But again, we do see them as major growth engines in the basin, and we’re excited that we have a part of those opportunities.

We do think they’ll provide some substantial growth and could make up 10% of our liquids production in five to 10 years. So both definitely have the scale, but we won’t be able to provide any more details on that until next year.

And then in terms of the share buybacks, again, we continue to believe that the share is traded below the intrinsic value of the business. We don’t really speculate too much on commodity prices, we do tell the broker who has the buyback to buy on down days.

But I think, overall, it’s a big part of the returning capital to shareholders. And I think, we – you’d see the expansion of the Duvernay play, we’ve actually added a lot of value into the business just as our play has grown.

So I think we’re comfortable with the share buyback. And then in terms of your dividend question, we review the dividend every February and look at the cash-flow generation of the business and go through the three-year budget at that time, and it’s, obviously, a fair amount of excess free cash flow on top of the dividend and buyback today.

So assuming things stay – assuming prices stay where they are today, there should be room for some growth there, but wouldn’t want to speculate on what it looks like in the next six months. Hopefully that answers your questions.

Yes. It does.

Thank you.

Yes. Good morning, guys.

Very simple question. Of the 245 wells, could you provide any clarity on how many of those spuds would be East Duvernay perspective?

Yes. So in terms of East Duvernay spuds, there were six well spuds on our lands, in the East Duvernay.

The majority of the spuds, Travis, again, were Viking. It continues to carry the load for the business.

64% of the total spuds were in the Viking. The one interesting change from last year to this year in terms of where the new spud activity is, it remains strong on the Viking, but actually there has been a big shift to the Alberta side.

We’ve – last Q3, we had only one well spud on the Alberta Viking, and this year we’ve seen 33 wells. And I think that momentum is continuing because the exceptional 30, 60 and 90-day IP rates that they’re getting now on the Alberta side and the Provost side.

So that’s one change from last year, but six spuds and we expect that level to continue about that pace over the next two quarters.

Okay, great. That’s all.

Thanks for that. Good morning, folks.

Andrew, just wondering if you can just talk us through with, I guess, 500,000 or so acres leased on your lands on the Duvernay. What does that imply for committed capital spending, or activity levels over the next few years on these lands?

I know you don’t want to get into specifics on your deal terms there, but maybe just paint the picture for us, if you can?

Yes. So every deal we’ve entered into is slightly different in terms of the mechanics and how they are structured.

But one of the things, just given the way land retention works, Mike, on our free lands is, we do expect that – over the next five years, don’t know exactly when there’s going to be substantial amount of drilling in order to hold the lands. And I think the way we structure them, there are some minimum drilling clauses whereby the producers can then extend the lands for another period of time for another cash bonus.

So we do have some back end cash bonuses, most of them are layered into 2019. But we do expect a fair amount of drilling on the play, just in order to delineate the play.

The most active producer right now in the play is, obviously, Vesta, with four rigs running. But we are seeing some great results in the coast plan B&M area, where Artis is the major operator and I think, we do expect continued activity there in 2018, but the extent of that I can’t forecast and I wouldn’t want to speculate as to what some of the companies will look at in terms of capital budget next year, but I guess, in terms of we should see over 25 wells drilled in the next 12 to 18 months on our lands and they are expensive wells.

So we would be happy with that. But I think it does need to ramp up in 2019, 2020, in order for people to hold these lands, otherwise they return back the inventory and we can release them.

So hopefully that answers your questions.

Yes. It does.

Thank you.

Thanks. Good morning, yes.

Just a quick one for me, Andrew, just in terms of the impact on Q3 volumes due to the averages and prices. Can you kind of quantify what the size and the magnitude of those and maybe if they’ve been alleviated so far in Q4?

Yes. So in terms of the – the couple of things that impacted Q3 volumes are, one is just natural Q3 is typically our weakest quarter if you trace back our last three Q3s have all been the weakest quarter typically of the year.

We forecasted that there was 500 barrels a day of gas shut-in, so BOE net to us. So that’s something we take in our Q3 financials.

So if we’re under accrued there, then we’ll see it in Q4. But I think the majority of those volumes are back on production on the gas side.

On the oil side, you get – the biggest impact was a few sliding scales, some natural declines from Q1, but we also saw just only 104 wells spud in Q2, so not a lot of new wells went on production, but we should see that start to come back on production in Q4 as well as our new Lake and Lindbergh turnarounds, we took about 100 barrels a day out of our production for the entire quarter due to those turnarounds and I believe, Pam, they’re back on?

They’re both back on, yes.

Okay. Thanks for that.

So that’s kind of where most of the volumes come from. And I – we think we’re conservative in Q3, but I guess, you never know – some of the really weak pricing on the gas side those shut-ins could be more prolonged so I wouldn’t want to say that they’re all back on.

Right. Okay, thanks.

Thank you for dialing in and if you have any follow-up questions, please call Pam or myself at 587-293-4005. Thank you.