Whitecap Resources Inc

TSX:WCP

Earnings Call Transcript 2018-Q3

[Operator]

Good morning. My name is Sylvie and I will be your conference operator today. At this time, I would like to welcome everyone to Whitecap Resources Third Quarter 2018 Results Conference Call. [Operator Instructions.] And I would like to turn the conference over to Whitecap's President and CEO, Mr. Grant Fagerheim. You may now begin your conference.

[Grant Bradley Fagerheim, President, CEO & Director]

Good morning, and thank you, everyone, for joining us. I am 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 our $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 our 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 Midale par prices, which currently receives a premium to Edmonton par prices. The Midale par price in the fourth quarter is expected to be approximately USD 57 per barrel relative to Edmonton par price of USD 43 per barrel and WTI at USD 68 per barrel. Approximately 26% of our crude oil production is in southwest Saskatchewan, which is a premium gravity crude oil that receives Fosterton pricing. The Fosterton price currently receives a premium to WCS price and is anticipated to be approximately USD 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 USD 15 per barrel for the remainder of 2018.The remainder of our crude oil is priced off of Edmonton par, where we had hedged approximately 32% of our light oil production at an average price of approximately USD 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 increasing crude by rail, higher 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 Thanh Kang to provide some color on our financial results, including our netbacks and other key financial metrics. Thanh?

[Thanh C. Kang, Chief Financial Officer]

Thanks, Grant. WTI averaged USD 69.50 per barrel compared to USD 67.88 per barrel in Q2 '18 and USD 48.20 per barrel in Q3 of '17. Whitecap's realized crude oil prices continued 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 CAD 77.24 per barrel compared to CAD 75.36 per barrel in Q2 of '18, an increase of 2%, and $53.85 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 was $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 was 13% lower than Q2 '18 at $1.27 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 1.6x compared to 1.7x 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.

[Grant Bradley Fagerheim, President, CEO & Director]

Thanks, Thanh. To conclude, we continued 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 5, 2018.With that, I will turn over to the operator for any questions. Thank you.

[Operator]

[Operator Instructions.] And your first question will be from Jeremy McCrea at Raymond James.

[Jeremy McCrea, Energy Analyst]

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 budget on like a normalized differential, where 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 plays that you're targeting?

[Grant Bradley Fagerheim, President, CEO & Director]

Yes, thanks, Jeremy. Just regarding the -- our budget plans, as I say, 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, 1-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 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 5 as we see what the investment environment looks like and what the differential profile looks like at this particular time.

[Jeremy McCrea, Energy Analyst]

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

[Grant Bradley Fagerheim, President, CEO & Director]

Again, I think that, Jeremy, just regarding the -- we'll probably spend more on the eastern side of the western Canadian sedimentary basin, so probably more in Saskatchewan just because of this apportionment challenges that the basin is dealing with than 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 into Saskatchewan than Alberta.

[Operator]

Next question will be from Travis Wood at National Bank Financial.

[Travis Wood, Analyst]

I 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 some step-out wells or maybe even some new pools within some of your core assets.

[Grant Bradley Fagerheim, President, CEO & Director]

Yes, Darin? Sure, I'm going to just roll that over to Darin Dunlop.

[Darin Roy Dunlop, Vice President of Engineering]

Yes, Travis, Darin here. Yes, 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 were -- had a little bit of 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 a strengthening of our inventory as we get additional results.

[Travis Wood, Analyst]

Okay, and as you are looking to kind of push the areal extent of some of the plays. Have you seen any changes in well results that could suggest even maybe less on inventory itself, but some changes in the EURs of those wells?

[Darin Roy Dunlop, Vice President of Engineering]

For the most part, we're seeing some areas, like for example, the lower Shaunavon in southwest Sask, we have had some results that had derisked that and increased EUR 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.

[Operator]

Next question will be from Elvis Matthews at AltaCorp Capital.

[Thomas Matthews]

It's actually Thomas, but that's all right, I'll take Elvis today.

[Grant Bradley Fagerheim, President, CEO & Director]

Elvis, I like that.

[Thomas Matthews]

I just wanted to ask just on some of the cost reductions. So we saw, I think in the Viking last quarter, you announced 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 2 plays 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 out from.

[Grant Bradley Fagerheim, President, CEO & Director]

Thanks, Elvis. Thanks, Thomas. I'm going to pass that over to Joel Armstrong. Joel?

[Joel M. Armstrong, Vice President of Production & Operations]

Yes, I guess in regards to the Viking and Deep Basin, I mean, we've been developing the Viking play for a long 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 are still making some pretty significant improvements in terms of overall frac design there and really, our flowback 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.

[Thomas Matthews]

Okay, and then I guess just in terms of the water flood, if you do have these cost savings from your other primary drilling plays. Does that free up allocation to some of these water flood initiatives? Or going into 2019, if you are somewhat under-spending your guidance, would you just use the excess to pay down debt? Or would you say, “Okay, let's allocate some more into the water flood to mitigate that decline?”

[Thanh C. Kang, Chief Financial Officer]

Sure, it's Thanh here. I mean, there's always going to be a component of water flood capital spending, and we're a little bit lighter this year, around 15%, spending about $70 million. As we look forward over the next 3 years, it will 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.

[Thomas Matthews]

Okay, great. 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 2 of significant ramp? What's the thought in that growth profile?

[Darin Roy Dunlop, Vice President of Engineering]

Yes, Darin here. Yes, no, it will be fairly consistent, like a steady ramp over that 5-year period. So we have what's in our growth profile, we have defined a 5-year program or development plan that could very well change depending on commodity prices in the environment. But as of right now, it is a fairly steady ramp-up.

[Operator]

The next question will be from Josef Schachter at Schachter Energy Research.

[Josef Schachter]

The first question is for Thanh. On the balance sheet, accounts receivable is up by 25%, but payables are up by 50% from year-end. Has there been a change in how you're going to pay? Have you delayed your payables?

[Thanh C. Kang, Chief Financial Officer]

No, it's the same 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.

[Josef Schachter]

Okay. A question, then, for Grant. You've paid down debt in the quarter $40 million -- $40.7 million. You also did stock buybacks, $8.4 million in the quarter and $25.5 million 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 buy back more stock and your normal course issuer bid?

[Grant Bradley Fagerheim, President, CEO & Director]

Yes, Josef, we had a very fruitful conversation with our board as part of this, and that is something we are looking intensely at. 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 will talk about that as part of our December 5 budget release. But I would expect us to be -- we're not finalized yet on that, but definitely indication-wise, we'll be more aggressive than less aggressive.

[Josef Schachter]

Okay, last question for me. Long-term debt at $1.24 billion, 32% compared to your debt. And as you mentioned earlier, debt to cash flow at 1.6x. Where is your target? Are you at 1.5x and then you're comfortable and then you could use more of the cash for other items, either dividend or normal course issuer bid? What's your thinking there in terms of what's the proper capitalization, debt to equity?

[Thanh C. Kang, Chief Financial Officer]

It's Thanh here. So we see our debt-to-cash-flow levels between 1x to 2x 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 1.6x, the 1.5x is a comfortable range for us to be in at this time, Josef.

[Operator]

The next question will be from Shailender Randhawa at RBC Capital Markets.

[Shailender Randhawa, Analyst]

Yes, 2 questions for 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?

[Grant Bradley Fagerheim, President, CEO & Director]

Thanks, Shailender. First of all, just regarding any substantial turnarounds or outages, no, we're not projecting this 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're very well defined at this particular time for our fourth quarter capital program. So we're anticipating on a full year basis to be $450 million, which includes our early startups on some of our wells that we'll be drilling here starting in mid-November, sort of to run hot rigs coming into the first quarter.

[Operator]

The next question will be from Hossein Aram at Richardson GMP.

[Hossein Aram]

My question is about the hedging strategy, hedging program that you have. Is it fair to think about the price that you hedge at is going to be the same in 2019? If not, what will be your outlook for your hedging?

[Thanh C. Kang, Chief Financial Officer]

So just on the hedging front there, our approach really is to layer on incremental positions, 1,000 to 2,000 barrels a day. Our objective is to really hedge over a 2-year period of time. In Year 1, 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 2 years out, to be between 20% to 40%. So we just started that starter 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 costless callers. That's what we're focused on at this time. This gives us an opportunity to layer on a very good base level of price but also provide for that upside participation as well.

[Hossein Aram]

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

[Thanh C. Kang, Chief Financial Officer]

So all of our production is sold through the -- at the different sales points 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.

[Operator]

[Operator Instructions] And at this time, Mr. Fagerheim, we have no other questions, so I would like to turn the call back over to you, sir.

[Grant Bradley Fagerheim, President, CEO & Director]

Once again, I just wanted to thank everyone for your support, and we look forward to advancing our program forward in 2018 as well as for the full year reporting on December the 5th 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 of not only Whitecap, but the Canadian, western Canadian sedimentary basin.So thanks again for listening in, and hope everyone has a good day. Thank you.

[Operator]

Thank you, sir. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending. And at this time, we do ask that you please disconnect your line. Enjoy the rest of your day.