Whitecap Resources Inc.

Grant Fagerheim - CEO Thanh Kang - CFO Darin Dunlop - Vice President of Engineering Joel Armstrong - Vice President of Production and Operations

Jeremy McCrea - Raymond James Travis Wood - National Bank Financial Elvis Matthews - AltaCorp Capital Josef Schachter - Schachter Energy Research Shailender Randhawa - RBC Capital Markets Hossein Aram - Richardson GMP

Good morning and thank you everyone for joining us. I'm joined by our Chief Financial Officer, Thanh Kang, as well as our Vice President of Engineering, Darin Dunlop and our Vice President of Production and Operations, Joel Armstrong.

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 Q3 news release issued earlier this morning. In the third quarter, we achieved record average production of 75,529 boe per day in the quarter, 84% crude oil and natural gas liquids, which is above our anticipated 74,000 to 75,000 boe per day range.

Production increased 30% compared to last year, primarily driven by the Weyburn acquisition but also as a result of our exceptionally strong operational performance. More importantly, our production per share increased 16% per share compared to the same period last year.

We are well on track to meet our full year production guidance and now expect average production for 2018 to be 74,500 boe per day. Funds flow for the quarter was $205 million or $0.49 per fully diluted share, which was 56.2 million higher than the capital spending of 115 million and the dividend payments of 33.8 million combined.

Capital spending for the quarter was $115 million, drilling 76 61.3 net wells and we anticipate capital spending in the fourth quarter to be approximately $90 million, drilling 35 19.9 net wells, which will bring our total wells for 2018 to 262 gross wells. The operational success that we have delivered across our asset base has been overshadowed recently by the wider than historically normal price differentials for both light and heavy crude oil in Canada, as a result of constrained pipeline access for energy sector.

However, having approximately 50% of our crude oil production downstream of current pipeline apportionment points, we've been able to realize stronger pricing. Approximately, 24% of our crude oil production resides in Southeast Saskatchewan, which is priced off [indiscernible] par prices which currently receives a premium to Edmonton power prices.

The [indiscernible] par price in the fourth quarter is expected to be approximately US$57 per barrel, relative to Edmonton power price of US$43 per barrel and WTI at US$68 per barrel. Approximately 26% of our crude oil production is in Southwest Saskatchewan, which is a premium gravity crude oil that receives fast written pricing.

The fast written price currently receives a premium to WCS price and is anticipated to be approximately US$43 per barrel in the fourth quarter of 2018, which is equivalent to the Edmonton par price for light oil. In addition, we have hedged approximately 54% of WCS price differential at an average price of US$15 per barrel for the remainder of 2018.

The remainder of the crude oil is priced off of Edmonton par, where we have hedged approximately 32% of our light oil production at an average price of approximately US$3.50 per barrel. The differential hedging gain in the third quarter was approximately $10.2 million and we anticipate on current wide differentials, a hedging gain on differential hedges of approximately $54 million in the fourth quarter.

We have strong differential hedges in place for the balance of the year, geographical diversification and optionality to deal with the short term widening of differentials. We anticipate improving differentials into 2019 with the increasing crude by rail, high refinery utilization rates and increased pipeline capacity from Enbridge's Line 3 replacement expansion later in 2019.

With this, I would like to turn over to Thanh Kang to provide some color on our financial results, including our netbacks and other key financial metrics. Thanh.

Thanks, Grant. WTI averaged US$69.50 per barrel compared to US$67.88 per barrel in Q2 ‘18 and US$48.20 per barrel in Q3 of ’17.

Whitecap’s realized crude oil prices continue to be strong in the third quarter with more normalized crude oil price differentials and a continued weak Canadian Dollar. Realized crude oil prices were CAD77.24 per barrel compared to CAD75.36 per barrel in Q2 of ’18, an increase of 2% and CAD53.85 per barrel in Q3 of ’17, an increase of 43%.

Under IFRS, we are required to split out processing income from operating expenses, which we have historically combined. Operating expenses were $11.97 per boe and processing income was $0.35 per boe in the third quarter.

On a combined basis, they were consistent with our $11.60 to $11.70 per boe expectation for the second half of 2018. Transportation expenses for the third quarter were $2.19 per boe and tariffs were $0.64 per boe.

On a combined basis, again they were consistent with our forecast of approximately $3 per boe expectation for the second half of 2018. G&A expenses of $1.10 per boe were 13% lower than Q2 ’18 at the $1.2 per boe on higher than expected production volumes and a true-up to full year expected G&A expenses.

Interest and financing expenses of $1.86 per boe compared to $1.94 per boe in Q2 of 2018, a decrease of 4%. We continue to have a strong balance sheet with net debt at the end of the quarter at 1.3 billion on debt capacity of 1.7 billion.

Net debt to Q3 annualized funds flow was 1.6 times compared to 1.7 times at the end of the second quarter. Another solid quarter for the company.

With that, I will turn it over to Grant for some closing comments.

Thanks, Thanh. To conclude, we continue to execute on 2018 capital plans outlined to the market and the performance of our assets have been very strong as demonstrated by our well economics and our free funds flow profile.

We remain very disciplined with our allocation of free funds flow to ensure we enhance and maximize shareholder returns. Our balance sheet is in very good shape and we continue to work hard to improve our share price.

We look forward to releasing our 2019 budget in full on December the 5 2018. With that, I'll turn over to the operator for any questions.

Thank you.

Yes. Hi Grant.

I know your budget is coming out here in a month’s time or so, but I just want to get a sense of how you're looking at the budget, will you be basing the budgets on like a normalized differential, it looks like it should start to improve by April or is it going to be more using some of the spot prices here and we could expect some revisions and then also where you plan to move that capital if it's changing much from 2018 in terms of the place that you're targeting.

Yeah. Thanks, Jeremy.

Just regarding the -- our budget plan, as I said, we’ll come out with -- in detail, but at this time, we have to honor the differential environment that we're dealing with and this is why we're going to watch to see what takes place over the next, in essence one month period of time and make sure that from our perspective we honor the, what we think will be a reducing differential price environment. In essence, what we're looking at for 2019 is our capital variation between -- somewhere between $500 million and $600 million.

And production of 77,000 barrels a day to 80,000 barrels a day of production. Now our thoughts are that in this differential price environment that we should probably restrict our capital back somewhat, reduce our growth rate to more moderate growth, but again we'll have that final decision that we’ll come out with by December the 5th, as we see what the investment environment looks like and what the differential profile looks like at this particular time.

Okay. And then just in terms of play allocation, does that change where you are allocating capital here for next year.

Again, I think that Jeremy just regarding the – we’ll probably spend more on the Eastern side of the Western sedimentary basin, so probably more in Saskatchewan, just because of this apportionment challenges that we’ve -- the basin is dealing with. And then we have -- but ultimately, I think, very similar, but probably a little bit more on the Eastern side than we -- just to ensure that we can move our product on a continual basis.

So, not much change but more focused on the Eastern side of the basin, more in to Saskatchewan than Alberta.

Yeah. Good morning guys.

Wanted to get a sense around inventory, how you're thinking about inventory. You’ve had some recent strong well results throughout the Viking and wanted to kind of hear your thoughts on step-out wells or maybe even some new pools within some of your core assets.

Yeah, Darin, so I’m going to just roll out over to Darin Dunlop.

Yeah, Travis, Darin here. Yeah, we don’t see -- most of our inventory has been complete and we're not adding a whole bunch of wells to our inventory, but we are, for the most part, just improving our locations that had a little bit of a risk to them before, now have been more defined and are reallocated within our inventory.

So it's not an increase of inventory, it's more along the lines of the strengthening of our inventory as we get additional results.

Okay. And as you are looking to kind of push the aerial extent to some of the place, have you seen any changes in well result that could suggest even maybe less on inventory itself but some changes in the EURs of those wells.

For the most part, we’re seeing some areas like, for example, the lower Saskatchewan in Southwest, as we’ve had some results that had de-risked that and increased EURs expectations in that area. We have some localized areas where we're seeing some results, where our EURs are increasing, but as a whole, we are sort of staying status quo, with little bits and pieces here and there where we’re increasing things.

It’s actually, Thomas. I just wanted to ask just on some of the cost reductions.

So we saw, I think in the Viking last quarter, some cost reductions you announced some cost reductions in Northwest Alberta here this quarter. Are you seeing cost reductions across the board or are those just two places where you've been, I don't want to say the most active, but active anyways that you've been able to take these 5% and 10% reductions.

I'm going to pass that over to Joel Armstrong. Joel.

Yeah. I guess in regards to the Viking and Deep Basin, I mean, we've been developing the Viking play for a longer period of time.

So, our improvements are maybe smaller in context, but we continue to drill these wells faster and faster and I think we're fairly well optimized in terms of the overall execution frac design. In regards to our deep basin development, we're still making some pretty significant improvements in terms of overall frac design there and really our flow back strategy, which has a pretty big impact on the overall capital.

Just in terms of capital going forward, we kind of see everything remaining fairly flat in aggregate. There will be some positives and some decreases, but in aggregate we expect our capital structure to remain fairly flat.

Okay. And then I guess just in terms of the waterflood, if you do have these cost savings from your other primary drilling plays, does that free up allocation to some of these waterflood initiatives or going into 2019, if you are somewhat underspending your guidance, would you just use the access to pay down debt or would you say, okay, let’s allocate some more into the waterflood to mitigate that decline.

It’s Thanh here. I mean, there's always going to be a component of waterflood capital spending and we're little bit lighter this year around 15%, spending about 70 million.

As we look forward over the next three years, it'll probably be in that 18% to 22% of our capital program that's going to be allocated towards what we call decline rate mitigation activity. In terms of additional allocations of that free cash flow, initially, the focus is definitely going to be on debt reduction, so the free cash flow that we see in 2019 gives us a lot of optionalities, but certainly when we're looking at the wide differentials at this time, it will be applied towards debt reduction.

Okay. And then just last question, the note there on your Deep Basin, about expanding it from 5,400 to 15,000, will that just be just a consistent kind of growth profile or will there be a year or two of a significant ramp, what's the thought in that growth profile.

Yeah, Darin here. I know, it will be fairly consistent like a steady ramp over that 5 year period.

So, we have -- within our growth profile, we have a defined of 5-year program or development plan that could very well change, depending on commodity prices and the environment, but as of right now, it is a very steady ramp up.

Good morning and congratulations on a good quarter. First question for Thanh, on the balance sheet, accounts receivable was up by 25%, but payables were up by 50% from year end, is there going to change in how you're going to pay, have you delayed your payables?

No, it's the same, I mean, in terms of when we receive our receivables and when we pay our payables, it's just timing effectively there, Josef, so no change in that at all.

Okay. Question then for Grant.

You’ve paid down debt in the quarter of 40.7 million, you also did stock buybacks, 8.4 million in the quarter and 25.5 in the first 9 months. Given where the stock is now, are you looking at maybe being more opportunistic in terms of using your excess cash flow to buyback more stock in your normal course issued bid.

Yeah, Josef. We had a very fruitful conversation with our board as a part of this and that is something we are looking intensely at.

We’re going to just -- we're doing lots of different modeling around the normal course issuer bid and how much we should be using on a go forward basis, so I would expect us to be more aggressive than less aggressive. And we'll talk about that as part of our December 5th budget release, but I would expect us to be, and we’re not finalized yet on that, but definitely indication wise we’ll be more aggressive than less aggressive.

Okay. Last question from me, long term debt at 1.24, 32% compared to your debt and as you mentioned earlier, debt to cash flow 1.6 times.

Where is your target, are you at 1.5 times and then you're comfortable and then you could use more of the cash for other item -- either dividend or on normal course issuer bid, what’s your thinking there in terms of what's the proper capitalization debt-to-equity.

Yeah. It's Thanh here.

So we see our debt to cash flow levels between 1 to 2 times is what we'd like to target. Obviously when commodity prices are lower, whether that’s through the actual WTI price or wider differentials, you’re going to be at the higher end of that and if you have a more robust environment in terms of realized prices, then we'd like to be on the lower end of that, so the 1.6, the 1.5 times is a comfortable range for us to be in at this time, Josef.

Hi, good morning. Yeah, two questions from me Grant.

One, are there any scheduled turnarounds in Q4 or outages we should be aware of? And then secondly, is there flexibility in your Q4 CapEx for this year and does that play into how you think about the 2019 budget just in terms of cushioning Q1 CapEx, if diffs are structurally wide?

Thanks, Shailender. First of all just regarding any substantial turnarounds or outages, no, we're not projecting those from now to the end of the year.

We've kind of gone through the -- we have gone through the turnaround season. Second question, I think on 4Q CapEx, we're pretty -- we are very well defined at this particular time for our fourth quarter capital programs.

So we’re anticipating on full year basis to be $450 million and which includes early start ups on some of our wells that we’d be drilling here, starting in mid-November, so to run hot rigs coming into the first quarter.

Hi. My question to you is about the hedging strategy, hedging program that you had.

Is it fair to think about the price that you hedge at going to be same in 2019, if not what will be your outlook for your hedging?

So just on the hedging front there, our approach really is to layer on incremental positions, 1000, 2000 barrels a day. Our objective is to really hedge over a 2 year period of time.

In year one, we'd like to see 40% to 60% of our hedges in place and right now, we're right there at that 40% range and then looking out two years out to be between 20% to 40%, so we just started position in the first half of 2020. Historically, we've used a lot of swaps to make sure that we've got a good realized price to protect our cash flows and our well economics.

We now are using [indiscernible], that's what where we're focused on at this time. This gives us an opportunity to layer on a very good base level of price, but also provides for that upside participation as well.

And my second one is about, can you remind me or give me a little macro color about what portion of your production transports with rails and what portion through the trucks?

So, all of our production is sold through the -- at the different sales point being through the pipeline, but we do have opportunities to when you see apportionment, like we are right now to truck to the different sales points so that we can keep our product flowing.

Once again I just wanted to thank everyone for your support and we look forward to advancing our program pulled in 2018 as well as for the full year reporting on December the 5 for our 2019 program. And hope through 2019, our belief is that the differentials do start to narrow and the pace of those will really define I think the pace of capital development [indiscernible] but the Canadian -- Western Canadian, sedimentary basin.

So thanks again for listening in and hope everyone has a good day. Thank you.