Whitecap Resources Inc
TSX:WCP
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Whitecap Resources Inc
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Good morning. My name is Joanna, and I will be your conference operator today. At this time, I would like to welcome everyone to Whitecap Resources Third Quarter 2019 Results Conference Call. [Operator Instructions]I would now like to turn it over to Whitecap's President and CEO, Mr. Grant Fagerheim. You may begin your conference call.
Thank you. Good morning, and Happy Halloween, everyone. Thank you for joining us. I'm joined by our CFO, Thanh Kang, as well as our Vice President of Engineering, Darin Dunlop; and our Vice President of Operations and Production, Joel Armstrong. Before we get started, 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 we set forth in our third quarter news release issued earlier this morning. The third quarter was a very active one for Whitecap on an operational front. We are very pleased with the results we achieved, with average production of 68,255 BOE per day, on capital spending of $153.8 million, much lower than our projected $180 million to $200 million. We are also pleased to advise that we are on track for achieving our mid-case average production for the year of approximately 71,000 BOE per day on a reduced capital program of approximately $400 million, down from $450 million initially budgeted for the year with the same level of production. In the first 9 months of the year, we have generated free funds flow of $185.9 million after capital investments of $305 million. To date, we have returned $122.9 million to shareholders while continuing to strengthen our balance sheet, which is a primary focus for us in 2019. With the disciplined capital program in 2019, our capital business -- our business unit teams have not only delivered on efficient operational execution, but also had the opportunity to focus on technically advancing and expanding our light oil asset base organically. Our achievements year-to-date include organic inventory additions of 224 gross, 164 net wells -- net locations, positive type curve enhancement to 56 -- or 50 gross, 44.2 net locations, and a continued expansion of our enhanced oil recovery projects through analytical analysis and reservoir modeling, which has the potential to add significant possible oil reserves in the future. As part of the 2020 budget process, we created 5 detailed budgets with varying production growth targets and capital investments. Given the volatility in commodity prices and the uncertain economic environment, we have elected to continue the prudent and disciplined approach to capital investment into 2020. This allows us to increase free funds flow and our sustainability in a low-commodity price environment. We retain the flexibility to rapidly increase production growth when realized prices provide further -- provide higher returns on capital invested. Our Board of Directors has approved a 2020 capital budget of $360 million to $380 million, which is set to deliver average annual production of approximately 71,000 to 72,000 BOE per day, 85% oil and natural gas liquids, which is an increase of 3% per debt-adjusted share compared to our prior year 2019. We can maintain production year-over-year with less capital investments due to our low corporate production decline rate of 19% to 20%, high funds flow netbacks and strong capital efficiencies that we've achieved to date. Free funds flow in 2020 at $55 WTI is anticipated to be $263 million, of which we expect to allocate 40% to 50% towards strengthening the balance sheet and 50% to 60% towards return of capital to shareholders. We are targeting net debt of $1.1 billion in 2020, which would be our second year of strengthening our balance sheet by $100 million per year. With that, I will turn it over to Darin to comment on our technical achievements in 2019.
Thanks, Grant. In addition to the successful execution of our capital program, our technical staff have been busy advancing our organic growth initiatives. We have internally identified and successfully executed on several opportunities that enhance the economics of our current inventory as well as expanding it. This includes successfully negotiating the Montney oil joint venture in the Deep Basin, which increases the long-term sustainability of our business model; high-intensity fracture stimulations in our Cardium assets; implementing a gas flood pilot in Wapiti in the Deep Basin; optimizing and expanding our Viking waterflood assets, as well as identifying new Viking oil development areas; incorporating horizontal multifrac completion methods in our conventional Boundary Lake waterflood redevelopment; expanding our Valhalla inventory via emerging resource plays in the Charlie Lake and Montney; and continuing to expand our CO2 capture and utilization technology in Weyburn. With that, I will pass it on to Joel for comments relating to health, safety and environmental performance.
Thanks, Darin. Health, safety and environment remains a top priority at Whitecap, and we are once again pleased to report very strong results this quarter. Whitecap averaged 7 drilling rigs and 3 frac crews throughout the third quarter, which contributed to an estimated 1.71 million person hours, an 80% increase from Q2. Even with the increased activity, our total recordable injury frequency, or TRIF, for the quarter was 0.43, resulting in a year-to-date TRIF of 0.61. On the environmental front, we've been proactively managing fuel vent and flare volumes in addition to spill volumes, which are 50% lower year-to-date compared to the same period last year. Lastly, asset retirement obligations, or ARO, spent to date is $6.2 million or 70% of the 2019 budget. This level of spending has allowed us to abandon 74 wells to date, and we continue -- sorry, and we anticipate a total of 82 wells for the year. We have consistently been proactive in managing our ARO, and expect to spend an additional $9 million in 2020. With that, I will pass it on to Thanh to provide some color on our financial results.
Thanks, Joel. WTI averaged $56.45 in the third quarter compared to $59.81 per barrel in the second quarter, a 6% decrease. Canadian crude oil price differentials were comparable to the prior quarter at approximately $4.80 per barrel. Realized oil prices prior to hedges and tariffs were $65.07 per barrel compared to $71.40 per barrel in the second quarter of 2019, a decrease of 9%. Realized natural gas -- NGL prices averaged $14.85 per barrel compared to $22.50 per barrel in the second quarter of 2019, a decrease of 34%. The decrease was mainly due to low propane and butane prices, which represents 66% of our NGL mix. However, NGL revenues in the quarter were only 2% of total revenue. Realized natural gas prices averaged $1.12 per Mcf compared to $1.22 per Mcf in Q2 of '19. The decrease was consistent with the decrease in AECO natural gas prices. Natural gas revenues in the quarter represent 2% of total revenue. The royalty rate in the third quarter was consistent with the second quarter at approximately 19%. We anticipate a royalty rate of approximately 17% to 17.5% in the fourth quarter and into 2020 based on a WTI price of $55. Operating expenses for the third quarter were $12.56 per BOE, consistent with the second quarter at $12.45 per BOE. We anticipate operating costs of approximately $12.40 to $12.60 for full year 2019. In 2020, we anticipate this to increase by approximately 5% due to increased power costs and higher trucking and disposal costs at Wapiti and Cardium as we increase our production in those areas. Transportation expense of $2.23 per BOE; G&A expense of $1.04; and interest and financing expense of $1.80 per BOE, which includes realized and unrealized hedging gains and losses, are all consistent with the second quarter operating metrics and are expected to remain relatively consistent for the balance of the year and into 2020. As Grant mentioned earlier, our balance sheet is in great shape. And at $55 WTI, we anticipate to further reduce net debt in excess of $100 million in 2020. In a $45 WTI environment, we would maintain our dividend and can further reduce our capital program with minimal impact to our funds flow and still maintain a total payout ratio of less than 100%. I will now pass it on to Grant for his closing remarks.
Thanks, Thanh. Appreciate that. As we enter into 2020, we are expecting to experience continued price volatility, oscillating between $50 to $60 WTI, with natural gas prices in the $1.70 to $1.80 per GJ range. We anticipate the Canadian dollar to remain in the $0.75 to $0.76 range. We are also anticipating differentials on MSW at approximately $5 WTI differential, and WCS at $15 per barrel WTI differential. We are pleased to provide our followers a look at our 2020 budget at this time. We felt it necessary to design our program that will allow us to grow the production modestly and fund our dividend well within funds flow and provide substantial level of free funds flow. With the free funds flow, we retain full optionality to continue to strengthen our balance sheet, buy back shares through the normal course issuer bid, or accelerate growth plans for the future at the appropriate time. Outside of our usual development plans across our assets, for the upcoming 2020 year, we have entered into a joint venture with a private energy company focusing on the oil-rich window in the Alberta Deep Basin. This joint venture comprises a large contiguous land block, where we have the opportunity to earn 34 sections of land after Wapiti completes 1 well in 2019 and drills and completes an additional 2 wells over the next 2 years. We feel this is what's a very effective manner in which to earn into very favorable oil-rich lands with a very astute technical partner. We look forward to providing you with results of this initiative. Of our -- as we progress in the future. We will also continue to look for additional organic growth opportunities to enhance shareholder returns in the future. In closing, I want to express our appreciation to both Jason Kenney and Scott Moe for taking the leadership they have in support of our Canadian energy industry. We are optimistic that our energy sector will once again be recognized and respected for its level of responsible development practices and for its contribution to the Canadian economy as we move forward. Thank you to each of you on this call for your support and interest in Whitecap. With that, I will turn the call over to the operator for any questions.
[Operator Instructions] And your first question is from Amir Arif of Cormark Securities.
A couple of quick questions for you. Just the capital spending, Grant, it was -- it was a positive surprise in terms of both for this quarter and your guidance for next year. I'm just curious, is that reflecting improved capital efficiencies from changes to the way you're completing wells? Or is it lower service costs? Or is this just the timing of capital expenditures that's affecting it?
Yes, it's Thanh here, Amir. Some of it is certainly optimizations within our program. But the full year program of $400 million still remains intact. So a lot of that is timing with respect to spending within the third and fourth quarters.
Okay. And then the capital efficiency improvements, is that coming from service cost changes? Or is it just the lower decline rate, I guess, as you head into 2020?
Yes, it's Darin Dunlop here. It's a combination with regards to improving capital efficiencies on each of our plays as we optimize our completion. And -- but a big component of that is our continued spending and allocation of capital to our waterflood projects and that to continually knock down our base decline.
Okay. Sounds good. And then on the JV, sorry, I think I've missed your comments there, Grant. Was it a commitment of 3 wells to earn into the acreage?
Yes. So it was a -- first of all, it was a completion that has been done that will be tied in here by the -- we expect by the end of November. And then it was 2 additional wells. We'll be commencing the drilling of the first of those wells here late in -- I think it's spudding today, actually. So Joel, sorry, it's -- that well is spudding today. And then we'll be drilling another well in 2020. And that will provide us -- then we will go back in to redevelop the -- continue to develop the area on a joint venture basis with a private company.
Okay. And then the JV, obviously, gives you more resource capture, but just curious how you see the JV capital relative to your corporate capital allocation between other opportunities you have.
Do you have that, Darin? Just...
Yes, I do have that. I just want to flip through the -- with regards to how much spending we're going to be doing in the JV, it's upwards of -- on our total capital, it's upwards of $14 million to $15 million.
In 2020?
In 2020, yes.
2020. Yes. I mean, I was just more curious in terms of how you see it more strategically in terms of -- is it just -- is it resource captured? Is it better returns? Is it just the way to sort of add another area of focus?
It's -- I mean, from our perspective, it's another growth area for us. We think this is a substantial growth area. After our earning, we end up at the majority of the lands at 65%. On one side of the river, we end up at 50-50 with a partner. But it becomes another growth area for us as we continue in and around the region where we're already playing. So it's not a specific step out of any -- by any stretch of the imagination. It's in the area that we play already. It's just an oil window, where our technical people have worked up for a long period of time and allows us to focus there.
Your next question is from Travis Wood from National Bank.
I just wanted to hear your kind of comments around how the JV came about, kind of just extending on the last question there in terms of how you were thinking about it strategically, what your views are in terms of how this sets up for the future, you commented on growth in inventory, and kind of just how that initial conversation kicked off perhaps.
Sure. Our geotechnical staff have their preferred areas where they would like to play. And we had approached earlier this year with a view -- the private company, we had approached them earlier this year with a view to work on a technical joint venture as we move forward. So rather than buying the inventory, we thought it was best to drill to earn with the type of setup. This is a good environment where outside equity capital and debt is restricted. So we believe this is an area that we could, through drilling, have a measured growth profile, pretty substantial on a go-forward basis, that we're looking at somewhere between 20,000 to 30,000 barrels a day as we move through time. And we didn't have to pay for that upfront. We paid through it through earn-ins. So we thought it was a much better use of capital on a go-forward basis.
The next question is from Jeremy McCrea from Raymond James.
I know you guys mentioned you had 5 different budgets here. And I just want to know if that relates to anything towards Montney? And so a few questions on that. Is there the ability to expand more than the 2 wells for next year? What does maybe even 2021 look like? Is that like a 10-well program, 20-well, or another more -- a bit more exploration? And just generally, these 2 wells that you're drilling next year, are they going to be more exploration in terms of just smaller frac design? Or is it really going to try and say what can this play really start to deliver? Just trying to get a little bit more intensity of what you guys are planning here for the area?
Sure. I mean, until we've earned, there will be no joint wells that are being proposed, and we will have earned in 2020. And then we'll come back with our -- with the 2 technical teams, Whitecap and the private company. And we're looking at step-outs. These are not -- this is not wildcat exploration. This is a very well-known trend, I think you would know it, and with some very sound industry players in the area. So we're looking into 2020 as it doesn't provide us substantial amount of growth. But into 2021 -- because we're thinking more of 2020 as an earn-in year, and into 2021 -- the back half of '20 or into 2021, depending upon the results, how aggressive we'll get, and working, again, closely with our joint venture, we're not going to outrun them. We're going to work with them on a go-forward basis.
Okay. And then in terms of like frac design, is it kind of similar to what guys -- other guys are doing in the area? Or is it going to be like you're really trying to showcase what this thing could really do?
It's Joel Armstrong. All the frac design will be consistent with what's been employed in the area already. It's not a downgraded version by any means. The fracs are very substantial. And we'll be looking to maximize our productivity from each well.
Your next question is from Juan Jarrah from TD Securities.
Can you give us a bit more color on what types of economics you see from this JV? You kind of hinted at well costs, I guess. We have a good sense of where you are. Just curious where you see the economics.
Yes, Darin, Dunlop here. We have, obviously, several type curves in this area depending on different lengths in horizontals and different designs. But I'll give you the one -- the economics associated with the one that represents the majority of our inventory. So it's for a 2-mile Montney well. Total capital is $11.2 million. IP90 is about 1,200 BOE a day. The reserves associated with it, again, is about 1.2 million barrels. Oil and liquids weighting in the first year is about 60%. And all that generates a PI of just over 1, a rate of return of 115%, payout under a year, with the F&D around $9 a BOE.
Well, that's a lot more color than I expected. It looks like you're prepared for it. The other question, I guess, I have is, obviously, you went through the process -- and this follows on Travis' question, the process of looking at do we do this organically, do we look at some acquisitions, et cetera. The question I have for you guys is, if you like what you see in the next year, does that mean you could actually look to grow it a little bit bigger via acquisitions?
I think you'd have to look at the time -- Juan, I think we have to look at the timing of acquisitions. Again, since 2017, we've really not been overly aggressively looking at acquisitions. 2018 and '19 has been focused on organic growth, and we'd have to look at the environment if there might be opportunities. But at this particular time, with the capital being restricted across the Canadian Basin -- Western Canadian Basin, we thought it was more appropriate to use from an earn-in perspective, and that's -- so potentially, acquisitions might, but we're not forecasting that at this particular time.
Got you. That's helpful. And then the 3 wells, I mean, obviously, I see the license in the public data. The question is, will the other 2 wells be close to that well? Or are you going to kind of try to delineate the 34 sections that you're looking at?
General proximity. But I mean, we're within a township of one another. We're not within a section of one another.
The next question is from Adam Gill from Eight Capital.
High-level question on the capital program. How much of this program's going towards non-drilling completion and EOR investment, like batteries, gathering system build-out, gas handling, allocations, land spending? And how does that compare to your 2018 and 2019 investment levels?
Adam, it's Thanh here. So on land and seismic in 2019, we would have spent about $5 million. We're forecasting about $3 million in 2020. On the facility side, 2019, we're forecasting to spend about $14 million, and that compares to about $11 million in 2020. And then we also have budgeted for items like asset integrity; health, safety and environment, which don't add any production. We spent about $12 million this year in 2019, and it's about the same in 2020 as well.
Our next question is from Josef Schachter of Schachter Energy Research.
A couple of questions for you. Starting first with AECO now at $3, do you have shut-in gas that you could bring on for the strong winter season that is not in your numbers?
Sorry, Josef, I think just -- I think your question was around gas. We don't have any independent gas wells. All of our gas is associated with our oil production that is currently on stream. I think that was your question.
Yes. Just trying to see if there's anything that was shut in that could come on that was separate from your production with oil. Second, your production was -- in the third quarter, was it back-ended so that, right now, your volumes are above the level that you were for the average for the quarter of 68,255?
Yes. So what we're looking at is to exit -- we're up over 72,000 barrels a day now at this particular time. So we're looking for a lot of the capital spent in -- I mean, sorry, in the third quarter. Production came on either late or into the October time frame, late in September, into October, and it continues to ramp up as we move through this particular quarter into the fourth quarter. So we'll have a very strong exit going into the 2020 year as well.
Okay. A question for Thanh. On the -- if we have a low oil price at December 31, are you concerned about a goodwill write-down on the balance sheet?
Yes. I mean, we'll have to take a look at what that environment looks like at this particular time on the price forecast. Certainly, I think when you look at the price deck at December 31, 2018, compared to where strip is at this particular time, it is lower. But we'll have to see what that pricing environment looks like relative to what our reserves are as well at the end of the year here.
And then last question for me is, you're using $55 and $1.75. If things turn out much better, and we have a better pricing environment in the 60s in Q2, heading to Q3 and there's a bit more optimism, when would you change your approach to CapEx? And are there any specific areas you'd like to focus on new spending if the price of the commodity is more cooperative?
Yes. I mean, the first priority for us is our balance sheet, and we're targeting in excess of $100 million of continued debt reduction. That would be the first priority. So as commodity prices improve, I think we'll hit that target sooner rather than later. And then we'll look to redeploy that, whether that's return on capital or return of capital, and we can make that decision at that time.
[Operator Instructions] And the next question is from Christopher Jones of Haywood Securities.
Within your operational update, you highlighted, as a result of some completion improvements, some pretty impressive results in the Cardium. Just wondering if you're comfortable using this new approach on subsequent wells? Or do you guys need a little bit more time to see how recoveries unfold?
Yes, Darin here. Yes. No, we're very comfortable using it in the appropriate situations. It's not going to be a blanket. There's particular reservoir characteristics where this technology is applicable, and we've identified a significant amount of our inventory that we can upgrade with this high-intensity frac technology.
And the next question is a follow-up from Amir Arif of Cormark Securities.
Just a couple of quick real follow-ups here. Just on the share buybacks, I noticed you did become a little more aggressive on the buybacks this quarter versus the first half. So just curious on your thoughts on utilizing additional buybacks? Does that move up as the stock price moves down? Or does it move up as there's more free cash flow in your -- in terms of your budgets based on how aggressive you could be on the buybacks?
Yes, it's Thanh here, Amir. I think, from our perspective, we want to focus on reduction of our net debt first and strengthening our balance sheet. If we have more free cash flow, we'll look at considering a more aggressive buyback at that particular time. Our objective similar to this year was to keep our share count flat to slightly declining. It won't be a huge component of our free cash flow allocation, unless we have much more free funds flow in excess of what we're currently forecasting here. But expect the component of that to be directed towards share buyback similar to this year into 2020.
Okay, sounds good. And then just on the Wapiti Cardium gas flood, perhaps, Joel. If you could just give us a little color on is that being driven just because of where gas prices are? Or is this something that just technically makes sense to look at? And also, when do you expect any kind of production response from that?
Yes, it's Darin here. Yes, it was driven primarily from a reservoir perspective. Increase -- as you know, source water for a waterflood up in that area is harder to come by. Also, gas prices did have some play into it, but it's primarily an EOR opportunity where we see that we can significantly upwards to double our recovery factor by -- via gas injection.
And timing for a response, I'd like to ask you.
Oh, sorry. So we're going to commence injection here in the month of November. And we're anticipating response in -- based on the current pair that we were piloting, within 12 to 24 months.
There are no further questions. You may proceed.
Okay. So if there's no further questions, I just want to once again thank everyone for your time and interest in Whitecap, and we look forward to reporting back to you on our progress into 2020, '21 and '22. So have a great day, and thanks very much for your time.
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines.