Andrew Phillips - President & CEO Pamela Kazeil - VP, Finance & CFO

Jeremy McCrea - Raymond James Ltd. Shailender Randhawa - RBC Capital Markets John Green - TD Securities

Thank you, and good morning, everyone. And thanks for dialing into the PrairieSky Royalty Q2 2018 Earnings Call.

On the call from PSK are Cam Proctor, COO; Pam Kazeil, CFO; and myself, Andrew Phillips. Before handing the call over to Pam for a walk-through of the financials, I'll provide an operational update.

Free cash flow for the quarter was $62.4 million; $45.9 million was allocated for the dividend, $8 million to the buyback and there was an additional $8.5 million in excess quarterly profit. 168 wells were spud in Q2 2018, including 113 Viking wells.

44 wells were unit wells at a 1.7% net average royalty. The average royalty of all 168 wells was 6%.

40 of the drills were in the Alberta Viking, representing close to 25% of all PSK activity in the quarter. The quick individual well payouts and high netback, light oil continue to encourage activity in the area.

A new Viking oil transmission pipeline is being built and should go into service by the end of the year. This will extend the life of the pools in the area and lower operating and transportation costs for the producers.

Over the quarter, 11 Duvernay wells were spud, seven Cardium wells, nine Mannville heavy oil wells and four Lindbergh thermal wells. Only 7 gas wells were drilled in the quarter.

We're pleased with the level of oil-directed drilling activity during the traditionally quiet breakup period. Subsequent to the quarter, PrairieSky added 150,000 acres of Clearwater oil sands leases for $4.75 million with a multi-well horizontal drilling commitment from a new operator.

Within 18 months, a major oil transmission line will be brought into this region as well to accommodate the growing oil volumes. Cash G&A per barrel was $2.83 for the quarter.

We continue to expect the annual number to be in the low $3 per barrel range. PrairieSky will continue to look for efficiencies in our business and long term, we would like to see a mid $2 annual cash G&A number.

Our compliance group collected $3.6 million over the quarter and continue to identify errors and omissions in payments. In addition, we have brought land back into the leasable inventory through the lease compliance group.

Lease issuance bonus over the quarter was $3.7 million. Leasing was active in a number of different oil plays in Alberta and Saskatchewan.

PrairieSky is proactively preparing for some large central Alberta expiries later in the year. Potential oil zones that will be available to lease on January 1, 2019, are the glauconitic, Ellerslie, Cardium, Viking and Belly River.

There are a number of well-capitalized operators looking for leases across these geologic intervals. The lands have been sterilized for 10 years, so fresh eyes should yield some new oil finds.

We are pleased to add Myron Stadnyk to the Board of Directors of PrairieSky Royalty. He shares many of our same values, including a focus on creating shareholder value and maintaining a strong balance sheet.

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

Thank you, Andrew. Good morning, everyone.

PrairieSky generated funds from operations of $62.4 million or $0.27 per share or $0.26 per share diluted in the second quarter. Cash flow was generated primarily from royalty production revenue of $70.1 million on average production volumes of 22,944 BOE per day.

Oil and NGL revenue represented 92% of total royalty revenue, which was generated from oil volumes of 9,098 barrels per day and NGL royalty volumes of 2,279 barrels per day. Natural gas represented 8% of royalty revenue and $69.4 million a day of royalty production volume.

WTI was up and heavy oil differentials narrowed in Q2 2018 from Q1 2018, both positively impacting liquids royalty revenue. Natural gas revenue was impacted by a 40% decrease in AECO during the quarter.

Average daily production volumes per day were down 2.5% from the first quarter. Oil volumes were up 4% primarily as a result of better-than-expected results from new wells on stream.

Natural gas volumes have continued to trend downwards in the second quarter due to limited drilling and work-over activity. As expected, this has resulted in lower NGL volumes, although NGL yields have remained consistent in the quarter at around 33 barrels per million.

PrairieSky's production volumes included compliance activity as well as other prior period adjustments related to new wells on stream and better well performance. The compliance group continue to recover missed and incorrect royalties, collecting $3.6 million in the quarter.

This brings compliance collections for the year to $5.6 million. Other revenue totaled $6.1 million, which included lease rental income of $1.8 million and bonus consideration of $3.7 million.

During the quarter, PrairieSky entered into 33 leasing arrangements with 30 different counterparties. As discussed on the year-end conference call, PrairieSky continues to expect bonus consideration of $15 million for the year and lease rental income at $9 million, consistent with the estimates previously provided.

Cash administrative expenses in the quarter totaled $5.9 million or $2.83 per BOE. Year-to-date cash administrative cost of $16.8 million or $3.99 per BOE are expected to decrease in the second half of 2018.

We continue to expect cash G&A per BOE to be in the low $3 per BOE range. Cash taxes were $7.5 million in the quarter and this brings the effective cash tax rate to 21% for the first half of 2018.

PrairieSky declared dividends of $45.9 million or $0.195 per share in the quarter. This has a resulting payout ratio of 74%.

Under the normal course issuer bid, which we initiated on May 4, PrairieSky repurchased 300,700 common shares for $8 million with the resulting payout ratio, including the NCIB, of 86%. From inception to June 30, 2018, PrairieSky has returned $758 million in dividends, which is $3.99 per share.

As well, we repurchased 3.2 million common shares for $91.6 million. During the quarter, PrairieSky entered into a $200 million revolving credit facility and renewed our $25 million operating line.

The credit facility provides flexibility for royalty acquisitions which meet our criteria. At June 30, PrairieSky had positive working capital of $21.1 million, including cash of $10 million and no debt.

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

Two questions, both related to production levels. The first one is just related to acquisitions.

And I know in the past, you guys have been against buying royalty assets in the U.S. I'm just curious, if you don't mind, reminding me why that is once again and what has to change for you to positively look at the acquisitions in the U.S.?

The second question is related to activity levels and if you think the current licensing data that you're seeing with new lease agreements is enough to allow, say, a 3% to 5% production growth here over the next few years?

Yes. Thanks for the questions, Jeremy.

On the activity levels, which I can answer first, I think what we've seen is, there is definitely enough activity in new licensing to create some oil growth in the back half of the year. On the gas side, it's been very quiet.

We only had seven gas wells spud last quarter. So we do expect to see the gas volumes continues to decline throughout the rest of the year.

But I think the oil volumes which are driving the free cash flow profile should continue to grow in the low single digits throughout the year, potentially even a little higher if we stay in this high $60 environment. And then to answer your second question on the U.S.

acquisitions, we've actually been getting that quite a bit as of late. There has been a number of mineral packages in the U.S.

and there's also the newly formed U.S. companies like Viper, Kimble and the big difference between those mineral packages in those companies and PrairieSky is they don't have large undeveloped land bases to go along with their cash flow stream.

So they're missing duration and if they stopped doing acquisitions or drop downs, they'd be declining cash flow streams over the long term. So I think it's important to look into the past and look at some of these similar structures that were created.

There was the SandRidge Mississippian Trust, Pacific Coast Oil Trust, Marcellus Trust, Chesapeake Granite Wash Trust, I think San Juan Basin Royalty Trust, and if you look at all these structures now, they're all just high-yielding declining cash flow streams. And again, these rollup strategies don't always end well.

So we're very pleased with our $10 million undeveloped acres, and we continue to find qualified parties to lease those lands. So I think we'll continue just doing what we're doing here in Canada, where we understand it very well.

So a couple of questions from me. So one, you mentioned the new -- new royalty in the Clearwater play.

Is that consistent with the previous deals you've done in the area just in terms of the shape and the type of royalty? And then on the central Alberta expiries that are coming up, could you maybe frame that just in terms of how much acreage may be available for re-leasing, Andrew?

All right. Yes.

Thanks for the questions, Shailender. On the new royalty in the Clearwater, it's actually in that same -- it's in that same region.

So there's the Clearwater sands as well as one other deeper horizon that has potential. It's got a 12-year term on it.

It was acquired from a senior operator that owned the land for 3 years. So again, there's still the 12 years remaining, and we've got the well commitments.

And they're going to test the Clearwater sands within the next 18 months. It does take quite a bit of time because of the surface restrictions to get access to that area.

But again, we think we've captured another very large resource in the area for future oil growth. So that's a new royalty and there's actually -- there is a map of it in our new updated presentation, which we've actually added about 10 slides.

So you're welcome to take a look there and once you've seen it, ask any questions. And then, the Central Alberta package was -- it's kind of in a deep basin and it's got a number of different intervals.

It was a lease that was entered into -- a 10-year lease entered into when it was Encana. So it's about 6 years prior to our IPO.

And, again, these lands were held -- all rights were held for a number of years. And we have over what we believe is about 100,000 acres of potentially leasable acreage coming back in a variety of different zones, and we've already been talking to about 6 different qualified parties for various parts of the acreage, where they already have a core area, or they have identified oil prospects from these lands.

So again, we do think we'll get active in early 2019 leasing these out, but there has been in one area, the Olds/Garrington, there has been significant glauconitic, light oil and condensate discovery, and we have some lands directly offsetting that, that haven't seen a well in about a decade. So we do think lots of success leasing those lands.

Got you. Okay.

And then maybe just one other question on the credit facility. You mentioned potentially having the flexibility to use that for acquisitions.

I know you haven't use debt in the past. But would that be for a specific type of acquisitions, would have to be more production cash flow-oriented if you were to use debt, then maybe assets more optionality?

Yes. Again, we just -- we want to have that flexibility with credit facility.

We evaluated the Paramount package and don't know what else may come up over the next few years, but we've always told our shareholders if there was a smaller acquisition, $100 million acquisition, we're not going to issue equity to do that. Given our strong free cash flow profile on top of the dividend, it would be debt that could be retired in a short period of time and it would never be a permanent part of our capital structure, but just wanted to afford ourselves that flexibility if that makes sense.

Just another question on the credit facility from me as well. If it's due to incremental flexibility for potential acquisitions, historically you've funded deals with equity and have largely been CRE debt adverse.

So why pay the standby fees if you're not going to use it? And do you mean further your appetite for bigger leverage for M&A has changed?

Yes. Thanks for the question, John.

We wanted to have the flexibility as Andrew talked to, to be able to, if we saw an acquisition that was accretive today and 10 years from now, to be able to make that acquisition. As Andrew mentioned, we don't see debt as part of our permanent capital structure, but we wanted the opportunity to have that flexibility and if we wanted to repay that, we could use the excess cash flow that we're putting on to our balance sheet in the quarter as well as turn down our NCIB to repay that.

So we think that's consistent with our philosophy because it should -- it would be almost bridge financing and then we wouldn't use debt as part of our permanent structure.

Another way to end -- another little comment also, John, is when we acquired the thermal project from Pengrowth, we issued just over 9 million shares. Since that time, we've canceled almost 1/3 of those shares.

So it's kind of the reverse, you're just doing it the other way around and on the Lindbergh, they're producing more than they were when we acquired it and again, we've now paid off 1/3 of that acquisition if you want to think of it that way. So this is just kind of the reverse way of looking at a smaller acquisition.

If it came available and we're -- we remain disciplined and it's unlikely that we use it, I would say, just given the quality of some of the things we've seen. But we are still seeing really good quality $3 million to $5 million acquisitions, and I think we'll continue to look at those if they become available.

Thank you for dialing into our Q2 earnings call and please call Pam or myself if you have any further follow-on questions.