Thank you very much, and welcome to the PrairieSky Royalty Q1 2019 conference call. On the call from PrairieSky are Pam Kazeil, CFO; Cam Proctor, COO; and myself, Andrew Phillips.

I will provide an overview of operations for the quarter. Then turn the call over to Pam to walk through the financials.

Free cash flow of $57.8 million was used to pay $45.6 million of dividends, which represents a 79% payout ratio, $6.3 million was used to cancel 331,000 shares, and the remaining $5.9 million reduced our working capital deficiency by 40% to $6.2 million and was used to fund minor land fund purchases. Q1 oil royalty volumes of 8,904 barrels per day were impacted by production curtailments and delayed field activity throughout the fourth quarter – throughout the fourth quarter because of straight NGLs, including condensates were 2,586 BOE for the quarter and natural gas royalty volumes totaled 63.1 million cubic feet a day as extreme cold weather impacted field operations as well as freezed off a number of regions.

209 wells were spud on PrairieSky lands in Q1 2019 with an average royalty of 5.8%, this is reflective of an active quarter of drilling in oil units. Cash G&A for the first quarter totaled $3.84 per barrel reflecting the cash settlement of LTI for all staff management.

PrairieSky expects cash administration to be under $3 per barrel for the year, a record low. Compliance recoveries for the quarter totaled $1.8 million, and we continue to work hard on both lease compliance and royalty compliance.

Leasing resulted in $2 million in bonus revenue as PrairieSky entered into 27 new leases with 24 new counterparties. One interesting highlight was that leasing fee in Southwest Saskatchewan for numerous – say, the potential projects from large Canadian operators as well as small independents.

Both companies have significant expertise in executing on these types of steam-assisted gravity drainage projects. While a number of acquisition opportunities were presented and evaluated, none met our internal criteria.

Modest dollars were spent through one of our land funds to capture quality land fund acreage at a reasonable acreage at a reasonable price. Our continued efforts to lease land to quality counterparties is our focus and should result in oil production growth at capital flows in the Western Canadian basin, we’re trying to more normalized historical levels.

Meanwhile, we will continue to pay cash dividends and capital shares below intrinsic value. PrairieSky will host an Investor Day at 9:00 AM Eastern at the Fairmont Royal York Hotel in Toronto on May 23.

We will unveil of our 2019 playbook, outline our tenure free cash flow outlook and give more detail on plays that will be important to PrairieSky’s future cash flow generation. We will also be live webcast for those who are unable to attend in person.

I will now turn the call over to Pam to walk though the financial results.

Thank you, Andrew. Good morning, everyone.

PrairieSky generated funds from operations of $57.8 million or $0.25 per share in the quarter. Cash flow was generated primarily from royalty production revenue of $66.5 million on average production volumes of 22,007 BOE per day, which were 52% liquids.

Q1 2019 oil volumes were 8,904 barrels a day, down from Q4 2018 due primarily to the impacts of curtailments and trends. PrairieSky generated $46.3 million oil royalty revenue, which was up over $18 million from Q4 2018 as lower volumes in WTI pricing were offset by narrow Canadian light and heavy oil differentials.

NGL royalty volumes of 2,586 barrels a day were in line with Q4 2018 royalty volumes and generated an additional $9.1 million in revenue. Natural gas volumes were impacted by lower activity in 2018 as well as extended cold weather in February and March.

Although cold weather negatively impacted volumes, it improved AECO, generating natural gas revenue of $11.1 million in the quarter, 26% higher than Q4 2018. PrairieSky’s production volumes in the quarter included 815 BOE per day of prior-period adjustments, which were 73% liquids and included 425 BOE a day from compliance activities and an additional 390 BOE a day of prior-period adjustments related to new wells on stream and better well performance.

The compliance script continues to recover missed and incorrect royalties, through forensic accounting collecting $1.8 million in the quarter. There were 209 wells, five in Q1, which included 194 oil wells and 15 natural gas wells.

This was comparable to both Q1 2018 and Q4 2018, 198 wells and 202 wells respectively were spud. The average royalty rate of wells spud in Q1 2019 was 5.8%.

Other revenue totaled $6.7 million, including $2.3 million in lease rentals and $2 million in bonus consideration on entering into 27 leasing arrangements with 24 different counterparties. PrairieSky also earned $2.4 million of other income, including $2 million related to a non-performance payment.

Production in mineral taxes totaled $1.4 million and cash administrative expenses totaled $7.6 million or $3.84 per BOE. Cash administrative expense is expected to be below $3 per BOE in 2019.

Cash taxes for the quarter totaled $6 million. During Q1, PrairieSky paid $45.6 million in dividends as a result in payout ratio of 79% and repurchased 331,440 common shares to $6.3 million for an all-in payout ratio of 90%.

During the quarter, PrairieSky reduced its working capital deficiency to $6.2 million from $10.4 million at year end. Since IPO, PrairieSky has generated approximately $1.1 billion in funds from operations and returned over $1 billion to shareholders through approximately $900 million in dividends and a repurchase of 4.5 million common shares.

We will now turn it over to the moderator to proceed with the Q&A.

Hi Andrew and team. I’ve got two questions for you this morning.

The first one would be your messaging has been very consistent since IPO regarding leverage. I’m wondering if you could share your current views on leverage with us?

And then number two, do you view U.S. royalties as a potential future opportunity set for PrairieSky?

Yes. Good morning, Dana, and thanks for the question.

Our view on leverage is unchanged, we have not used it as a permanent part of our capital structure. We do have a $250 million bank line in case something exceptional came along, and then we could just pay it down with the free cash flow on top of the dividend by turning down the buyback.

So to answer your question, our view is unchanged, and we would not use leverage as a permanent part of our capital structure. And on the U.S.

royalties, we’re coming off all-time high in the United States capital spending in the major onshore basins. And in Canada, we’re at about a 20-year low in CapEx.

So our view is to create time to buy quality Canadian royalties. In addition, we’ve never seen a royalty package in the U.S.

or company with large tract of undeveloped lands, which gives you the duration of investors that share the same characteristics as a PrairieSky asset.

Thank you very much.

Good morning. I have two questions.

One is, your gas price realizations were fairly high for the quarter, and I was wondering why is that and is it sustainable? The second question is about activity on your land due to the production curtailment way of the view that activity and the Canadian basin will be probably low for quite a while meaning that services or any activity will be fairly low.

I was wondering what gives you confidence or what is your view on the subject? And how do you see this progressing over the next year or maybe two?

Thank you.

So Edward, I’ll talk about the gas price realization. So realizations were $1.97 in the quarter.

So generally, we see a blend in our realized pricing between daily and monthly AECO as well as above 10% of station 2. Realizations were higher this quarter just due to, obviously, higher daily AECO pricing.

In addition, we saw some prior period adjustments, including some recoveries of introductions in the quarter, which we see it incurred in price but not impacting volume so that helps with the price realizations as well.

Yes. And on the curtailment side, you’re certainly not going to drill new wells when you have oil production curtails, and we definitely felt a lot of that in Q4 and into Q1, which obviously impacted overall drilling activity.

When you look at the cash flow generation of our oil producers, they’re generating a huge amount of excess free cash flow right now. So it’s likely that a bunch of that goes back into the field in the back half of the year.

So we’re expecting second half drilling activity to pick up. And certainly, we’ve – those are the light oil producers have started to get pretty active licensing with short cycle time by [indiscernible] operation.

So we do expect back half long-term CapEx in light oil gas. Hopefully that answers your questions.

Okay. About the cash price realization, do you see this is as a sustainable or because previously your realization was about between 75% to 85% of AECO?

Do you see this going back to the federal or…

Yes. When we’re modeling, we would say that gas price realizations, it should be about 45% daily AECO, 45% monthly AECO and about 10% of station two.

And then we would deduct $0.45 for any deductions and transportation charges. So that’s a good way to model gas price realization.

Of course, with prior period adjustments and any compliance activity that we see in the quarter, that can impact pricing, but that is a good way to forecast our natural gas realizations.

Thank you very much.

Hey, thanks. Good morning, everyone.

I know, there’s an uptick in receivables this quarter, can you just try to provide a bit of detail on that? And is it something that we could expect to kind of clear out in due course?

Or should we expect a higher run rate going forward?

Yes. That’s a good question, Luke.

So in receivables, compared to year-end, we did certainly see an uptick. Generally, we carry about two months of production royalty revenue in receivables, so we saw an uptick from December, that was one impact.

And then the second impact is in the first quarter, we record the freehold mineral tax receivable. So freehold mineral taxes paid annually, so you’ll see the Accounts Payable increased as well.

So we pay the entire account payable to the government, and then we collect from many of the payers. So that’s why you’ll see an uptick in Accounts Payable as well as an offsetting uptick in accounts receivable.

Great. Thank you.

Thanks, good morning, guys. Do you have an estimate of how much net oil is being shut in on your lands due to the mandated provincial curtailments?

And I guess a follow-up question is, what proportion of your oil drilling activities in Saskatchewan versus Alberta?

Yes. So in terms of shut-in volumes, we saw about 100 barrels a day of volumes shut-in, in the fourth quarter.

We didn’t see that volume come back in the first quarter. And in addition, we saw about an additional 200 barrels shut-in in Q1.

Now some of that is shut-in barrels just due to pricing and some of that is directly related to the curtailment. So we would expect to see that production coming back on in the second quarter.

Yes. And in terms of oil activity, 40% of our oil royalty volumes are on the Saskatchewan side.

And we’ve seen an uptick in activity just because there are no curtailments in the Saskatchewan side. So right now, snapshot in time of about 50% of our drilling activity is on the Saskatchewan side.

Perfect. Thanks, guys.

Thank you very much for dialing in to the PrairieSky Q1 earnings call, and please call Pam or myself if you have any further questions. Thank you.