Whitecap Resources Inc.

Grant Fagerheim – President and Chief Executive Officer Thanh Kang – Chief Financial Officer Darin Dunlop – Vice President-Engineering Joel Armstrong – Vice President-Production and Operations

Shailender Randhawa – RBC Capital Markets Jeremy McCrea – Raymond James Thomas Matthews – AltaCorp Capital Travis Wood – National Bank Adam Gill – Eight Capital Juan Jarrah – TD Securities David Popowich – CIBC

Good morning. And thank you for joining us everyone on this first day of August.

I'm joined by our CFO, Thanh Kang, as well as two other members of our management team Joel Armstrong and Darin Dunlop. Before we get started today I would like to remind everybody that all statements made by the company during this call are subject to the same forward-looking disclaimer and advisory that we set forth in our Q2 news release issued earlier this morning.

As I expect to seem 2Q has been an excellent quarter for us in many respects as we continue on our long-term strategy. We achieved record average production of 75,813 boe/d in the quarter, 85% crude oil and liquids.

But more importantly it was a record quarter on production per share basis at 101 [ph] boe/d per million shares compared to Q2 2017 production per share increased 19%, 4% from the previous quarter, Q1 2018. For the full year we expect to grow production this year on a per share basis compared to last year 14% which is well in excess of our 6% to 8% per share long-term target.

Funds flow for the quarter about $196.5 million were at $0.47 per fully diluted share was almost twice as much as our development capital spending was $56.3 million and dividend payments of $32.7 million combined, thereby providing us with nearly US$100 million of free cash flow in the quarter. In the second quarter, we spent 15% of our full year budget, at $450 million drilling a total of 47 – 42 net wells.

This brings our total first half 2018 development spending to $248.7 million or 55% of our full year budget. With respect to our core areas, our Viking program in west central Saskatchewan continues to perform very well with exceptional rates of return, and capital payout in less than one year on a per well basis.

Compared to Q2 2017, average spud to rig release times have decreased 22% on our standard length 600 meter horizontal wells to 1.9 days and 27% on our extended reach 1,000 meter average length of horizontal wells to 2.4 days. These reduced spud to rig release times are contributing to our drill complete and equipment time cost being reduced or down by 5% to 10% below our original estimate.

The Southwest Saskatchewan asset acquisition, we completed in June of 2016, continues to be an exceptional acquisition for us. Our technical team continues to uncover new areas for optimization and enhancement.

The majority of our drills to-date have been targeting the Atlas formation where average spud to rig release times on our horizon wells have decreased 16% to 3.7 days, since we first spend capital on this play in July of 2016. We are also active on Shaunavon and Roseray success formation, giving us options in our local southwest Saskatchewan development program.

In December of 2017, we acquired the Weyburn CO2 asset in southeast Saskatchewan. The goal of the business unit was to keep production plan for 2018 at 14,800 boe/d with minimal capital and to resume development spending in the second half of 2018.

So far so good as the base production and performance has been exceptional, averaging slightly above 14,850 boe/d to-date and spending only a quarter of our budget as capital for the area. Our Weyburn team is excited to start deploying capital to this area with the six well drill-out re-activation program, four well CO2 expansion program and 12 well infill drilling program, which started in late June.

The Q1 drills at Wapiti targeting Cardium oil in North West Alberta. Business units continue to significantly exceed expectations, 21% higher than our type curve expectations.

And we have an additional seven 4.5 net follow-up locations to drill in the second half of 2018. We are currently drilling the last well of our 3-well pad targeting Dunvegan oil in the Karr area.

So far from our drilling results the reservoir is exceptional, the drilling times have been 30% faster than planned and the Karr saw 15% to 20% under budget. Our team’s exception executing in the first half of 2018 is setting Whitecap up to out perform in 2018.

As a result, we have elected to increase our 2018 production guidance miles base to capture the impact of our success to date. That said I’ll turn to the mic over to Thanh Kang, our CFO, to provide some color on our financial results including our net packs and other key financial metrics.

Thanks Grant. In the quarter WTI averaged US$67, US$88 per barrel, compared to $62.87 per barrel in Q1 2018, and US$48.28 per barrel in Q2 of 2017.

Despite wider differentials given the increase in crude oil prices and weaker Canadian dollar, we realized significantly higher prices for our crude oil. Realized crude all prices were on a Canadian dollar basis CD$75.36 per barrel, compared to CD$65.29 per barrel in the first quarter of 2018, an increase of 15% and CD$57.52 per barrel in the second quarter of 2017, an increase of 31%.

In April we started generating revenue from the blending facility at Weyburn. Blending revenue was $3.5 million.

And blending expenses were $2.4 million, resulting in a profit of $1.1 million for the quarter. The blending revenue is an additional upside that we did not include in our initial acquisition analysis, but full credit to our marketing team for capturing the outsiders as result of changing market conditions.

Crude oil blending can occur when there is a large price variance between the different crude oil streams, when there is full sufficient facility and pipeline capacity. So we don't forecast net blending revenue due to the uncertainty of monthly volumes with the variability of the various stream pricing.

That being said, with the volatility of the crude differential we are evaluating flexible blending opportunities at many of our facilities. Net operating expenses in the quarter were $11.29/boe, lower than our forecast of between $11.60/boe to $11.70/boe.

And that’s mainly from higher production volumes in the quarter. We’d expect net operating expenses per boe to be relatively flat as we move through the second half of the year at between $11.60 to $11.70.

Transportation expenses plus tariff of $2.98/boe for the quarter is relatively flat compared to the first quarter of 2018, as well as the second quarter of 2017. We are forecasting approximately $3/boe for the remainder of the year.

G&A expense of a $1.27/boe is in line with our forecast of a $1.25. And we would expect that to remain fairly flat at $1.25/boe for the balance of 2018.

Interest and finance expenses excluding unrealized gain on interest rate contracts of $1.99/boe, is higher than the second quarter of 2017 at $1.73 due to the additional debt we incurred from the late acquisition in 2017 of the Weyburn asset. We intentionally took on more debt, given the low decline production profile of the Weyburn assets and the asset significant free funds flow with the deal that we would do to reduce the debt with free funds flow in 2018.

In the second quarter, we reduced our net debt by $91.5 million. Net debt to Q2 annualized fund flow was 1.7 times.

And we anticipate to take that to 1.5 times by the end of the year. In short, very strong financial results in the second quarter, which reflect exceptional observational execution and strong business fundamentals.

With that I'll turn it over to Grant for some closing comments.

Thanks, Thanh. The last two years with depressed crude oil prices has allowed Whitecap to position in an enviable – Whitecap in an enviable position with a solid declining production profile to be able to deliver strong return on capital employed numbers, generate sustainable organic per share of production growth and significant free funds flow.

Our balance sheet remains strong and provides us with the financial flexibility to ensure that we withstand current volatile commodity prices. We are on track for delivering and achieving 14% production per share growth in 2018, with in excess of 29% per share growth in cash flow.

And that provides significant optionality with these proceeds. With that we look forward to reporting back to shareholders as we progress through the back half of 2018 and into 2019 year.

With that I will turn the call over to Johanna, our operator for any questions.

Hi good morning Grant. A couple questions for me.

So one, just give us the sense of how you're thinking about free cash flow deployment in the second half of the year, just in terms of buybacks? And what you would do to surplus cash?

And then secondly just curious on what you see in terms of running room in the Deep Basin and whether there's opportunities to expand that footprint? Thanks.

Sure, thanks Shailender. Just regarding the free cash flow, I want to make sure it’s very clear that, what we've tried to position Whitecap in is to have full optionality with the funds slowing.

And we do have a significant amount of free cash flow being projected for the back half of this year as Shailender hadsaid. Our first priority is always to be debt reduction and continue to drive down our debt if we don't have that better use of proceeds.

Second would be consolidation in our core areas of operation and then share buybacks. So we will continue to look to share buybacks.

But we want to ensure that we've got a sound level of debt. And long-term we're looking at our debt to cash flow between one to two times.

When commodity prices are higher, we prefer that to be lower on a debt to cash flow basis. So our number one objective is debt management first of all and to make sure that we've got flexibility that in the event that something does come up we can use our balance sheet in order to proceed with an acquisition or increase our capital program.

On your second question, on running room in the Deep Basin, we think we've got a lot of room to move forward in the Deep Basin. We’ve got a significant inventory both at Cardium and Dunvegan wells.

And what we're looking at is continuing, right at this particular time, in the Deep Basin we have – our current production is somewhere in that neighborhood of around 8,000 boe/d to 9,000 boe/d of production. And we're looking at that area as a continued growth area, to take us potentially up to between 12,000 boe/d to 15,000 boe/d a day of production.

So we've got a significant amount of running room at this particular time. And of course we're always looking to add to that as we move forward.

Great, okay thanks.

Yes, hi Grant. Just quick question just on your rate of return on your well economics, I am curious as we head into 2019, 2020, can you tell maybe an area where you're seeing the best rate of return change in terms of your well economics in an area that maybe you're seeing may be like it's potentially – your well economics is getting potentially worse?

And how you plan to shift capital into 2019 and 2020 versus what are you spending here now?

I'm just going to let Darin Dunlop here. Darin Dunlop go ahead.

Yes. Jeremy with regard to where we see some – and we’re talking relative to the economics you see in our corporate presentation, where we see the biggest opportunity for additional increase is our in Wapiti area, and the Cardium and the Deep Basin.

We're still early in the stages of development. So we might not have captured as currently right now our type curve.

Our performance of our last two wells have been over 20% above our current type curve. So if that continues on we will pick the rig time to identify when to start increasing that estimate.

But we do believe that. And as per things heading down a little bit, I would point to areas where we're starting to focus on a little bit more waterflood development.

That being West Pembina we're starting to get into West Pembina and into redeveloping the waterfloods and with that we – redeveloping of waterfloods we’ve seen a little bit of increase of water cuts. We’re IPs aren’t just high and the same in the Viking as we start to consume more of our inventory.

But one of the things we are going to see increase over the time and not even our rate of returns might start going down a bit, we're going to see our PIs and our long-term NPV increase as we start to realize the increase EORs per well due to waterflood improvement and redevelopment. And as well we can see in Southwest Saskatchewan [ph], we continually make improvements.

We’re doing a technical analysis in that. We're able to high grade more and more locations not only from a geographical position, but as well as a vertical and a formation position.

So as we see our technical knowledge increase, we're also starting to see our well results increase with that. So we would anticipate that we would start to see some increases in our type curve performance in those areas.

Okay. And then just on your Wapiti and Cardium and the making make up there, is takeaway an issue or did you see some good couple of years here of growth still in front of you here before you may run into those kind of challenges?

At this particular time we do not articulate issues and we continue to always get our marketing efforts showed in front of, so we don't have restricted in essence what we call frozen capital. We're kind of drill to fill company on a go-forward basis.

So what we're looking at into the future out there is we have taken the task here on some of the facilities that are being built into the future out there. And again we don't need it for the oil capacity, but we do need it for the associated natural gas.

So at this particular time we are in good position to continue to grow. And as new facilities come on in 2019 and 2020 we are taking incremental capacity in those facilities as well.

Okay, perfect. Thanks guys.

Thanks Jeremy.

Hey guys just a couple of CapEx questions. I'm just looking at the remaining budget for this year.

Is it fair to assume that production will remain relatively flat for the balance of the year. And then just the free cash flow will be used to pay down debt, either side in your three points there, what to use the free funds flow, I didn't hear anything on capital increases.

So just curious on that. And I have follow-up after that.

Sure it's Thanh here. So on the production side of things, we'd expect it to be relatively flat in the back half of the year between 74,000 boe/d to 75,000 boe/d.

Capital spending, pretty similar profile to what we had in previous years, where we'd expect to have higher levels of spending in the third quarter versus the fourth quarter there. In terms of free cash flow allocation that's correct our capital plans is at the US$450 million.

Don't expect that to change. We're already growing by 14% per share this year.

So our focus really will be on enhancing our 2019 production numbers.

Right. And then just a follow-up looking 2019 and beyond, we've seen other producers trying to flat that spending profile quarter-over-quarter.

Is that something you would consider or is there still going to be a big spend in Q1 and then a bigger spending in Q3 relative to Q2 and Q4?

Yes, that's something that we would look at as part of our 2019 budgeting process but it'll be at the rim very insignificant if there’s anything associated with that. Very comfortable that US$450 million is what we're looking at this time.

I was talking more in 2019?

Yes going forward, so we're trying to blend down. You're always going to have – we always think we're going to have higher component in the first quarter that ultimately switch out for the full calendar year from a production standpoint.

But we are trying to re-wait. And we have the opportunity to do that, we wait at little bit to balance it out because of a lot of those projects and the EOR projects that we have as well.

So I think from an operational intensity perspective where we have Joel Armstrong here he would love to see back it up more. But we are going to have always a larger component in the first quarter.

May be not the 50% of our capital program, but maybe somewhere between 30% to 40%, well always – 35% to 40% will always be the percentage capital spent in the first quarter I would expect.

Okay, great. That’s it for me.

Thanks.

Thanks Thomas.

Yes good morning, guys. I just wanted to continue on the conversation largely around the Dunvegan.

Is there opportunity there? If not this year, I know you’re in the process of drilling the pad.

Can you first kind of give us a timeline around when you could expect some results from the Dunvegan pad? And then is there the opportunity to evolve the drilling incompletions into ERHs there?

And then in the context of EOR opportunities how does the Dunvegan fit into that conversation?

Darin, you want to go ahead and talk to this.

Yes, sure. I missed out that last bit there Travis.

Can you go through that again?

Yes, the last part was just trying to understand more – this is probably more of a longer-term conversation. But how could the Dunvegan fit into EOR opportunities as the primary drilling starts to get you through?

Right now our bigger focus on evaluating EOR is, as you’re aware is in the Cardium in Wapiti. And that’s primarily maybe not from a reservoir quality basis, but more from a contiguous land basis.

So one of the things that inhibits us at this point in time from looking at EORs in the Dunvegan is that you don’t have large lab blocks have contiguous working interest. It’s a bit scattered.

We have significant landholdings, but there are different working interests and spread. So that sort of inhibits us from putting a formalized plan for waterflooding in the Dunvegan forward.

But that being said, the reservoir quality in areas of the Dunvegan certainly would be conducive to flooding if we could put together a more contiguous land block.

Okay. And then the other questions were geared towards potentially moving the Dunvegan into on ERH program that ties into the pad development.

Is there opportunity to replicate what you’re doing in the Cardium into the Dunvegan from that perspective?

For sure. In our Dunvegan we have several ERH.

We have built from two-point or two miles wells in the Dunvegan in the Karr area. Realistically the way we approach using ERHs is that we evaluate, it depends on depth.

Obviously the deeper EOR through vertical depth the farther you can go out effectively on a lateral length. So we look at it individually from opportunity to optimize our economics.

So it’s not an ERH strategy. It’s a continuous strategy on optimizing our economics.

So where our land block and the depth of the reservoir allows it, we will drill as many ERH, they are the most economic wells, which in a lot of cases ERH is possible.

Okay. Thanks for the color.

Thanks, Travis.

Good morning, gentlemen. Quick question from me.

Just wondering given the strong out performance on production for Q2, why not be a little more aggressive with the guidance increase? And I was just wondering if you give us any color were current volumes are standing?

Sure. Thanks, Adam.

As far as there are turnaround what we’re always trying to put out there obviously is achievable numbers getting in front of the markets and trying certain numbers that aren’t able to be achieved. In the third quarter, we do have third party planned turnarounds as well that are factored in our current volumes are just shy of around 75,500 barrels a day at this particular time right now as we speak.

We will continue to focus on having that those production volumes as we move through. July was a good month for us.

It was a strong month. And obviously starting on the first day of August, we’ve got a strong production profile, but we definitely want to make sure that we’re achievable and don’t disappoint the shareholders on a go forward basis.

Great, thank you.

Thanks.

Yes, good morning guys. And thanks for all the color in your opening remarks.

One of the questions I had was, so you the mentioned in Viking, you are seeing 5% to 10% cost improvements obviously better than expected productivity as well. Couple of questions there are how sustainable is this?

And two, are you seen anything similar in your other areas?

I’m going to let Joel [indiscernible]. Joel has mic on.

Joel go ahead.

Yes good morning. Ever since we purchased the Viking asset from Compass back in 2014, I believe it’s been acquisitive for ever improving the efficiencies.

We're getting to the point where we're likely not going through realize big step changes going forward. These wells are being drilled extremely fast.

Making sure that we can stay in the zone and keep the geologists happy is an important part of the process. We're getting to a point where we probably won’t see too much more.

Having said that's throughout our other areas that are as mature in terms of development for sure we're seeing better drilling performance utilizing ERH 1.5s, 2.0s as Darin mentioned to improve our overall economics. So, there's always lots of room.

We never through our hands in air and quit trying to improve on the economics, but realistically those matures like the Viking won’t see a whole bunch more improvement.

And I guess thank you. And I guess as a follow-on, does that set you up for potentially lower CapEx for the year and the same production, or maybe for the production of same CapEx type thing?

Sorry for that. Just because your Viking is 30% of your budget and you're seeing similar improvements across your asset base potentially just trying to think of the growth there?

Yes I think, we're currently in an environment where commodities have shown improvement especially on the WTI side. So along with that comes some price escalations that we're competing against.

So, overall we think we can hold our cost structure very similar to where we’re at today, meanwhile mitigating some of the escalation that we're dealing with.

Great, thank you. Last question from me is on Weyburn.

You kept production flat, you only spent a quarter of your US$60 million budget. Trying to get a sense of where you think that production could go by the year-end?

We are forecasting – we had forecasted to keep it flat. We had recently forecasted to see a slight decline obviously with no capital development and maintenance capital being spent we had expected to see a slight decline in the first half due to some efficiencies realized and keeping our stuff running and reducing our downtime.

Perhaps we managed to keep it flat in the first half. But that being said, the development which includes, six drill wells, 12 infills and 4 rollouts, one of the things to remember is, I think, it's actually five of those wells we are drilling are going to be injectors.

And also the [indiscernible] initial rate profile on these Weyburn wells are not like Viking are conventional. They do come on at fairly 50 boe/d type in rate.

But we do you expect to see fields to and waterflood influences over the next first one to three years. So that being said we're not going to be expecting to be much above 15,000 boe/d exit in Weyburn.

Well thanks guys, that’s all I had.

Thanks.

Yes thanks guys good quarter stay. I don't want to belabor the CapEx questions too much.

But I guess I'm just kind of wondering at the rate of spending that you guys are currently going, at what point you guys to yourselves exhausting the $450 million budget this year? And then just kind of on a related note, can you see any circumstances under which you might bump some 2019 spending into Q4 2018 as you guys did last year?

Thank you.

Go ahead Thanh.

In terms of the spending for the full year, there for the balance of the capital, we expect to the third quarter Dave somewhere between US$130 million to US$150 million capital. And then Q4 will be very similar to what we're spending in Q2 in that neighborhood of US$40 million to US$60 million.

So we’ll spend that throughout the year here to get to the $450 million. As I previously mentioned we're comfortable with where growth is rate at this time.

So the capital plans for this year will be the $450 million.

Great, thanks guys.

Thanks Dave.

So with that I guess that concludes our call for today. I appreciate everyone calling in.

For those you – our shareholders thanks very much for your support. We look forward to continuing to come back to you with enhancing our numbers as we go forward.

So thanks very much. I appreciate it.

And happy August. Bye for now.