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Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp. Third Quarter 2018 Conference Call. [Operator Instructions] And the conference is being recorded. [Operator Instructions] I would now like to turn the conference over to Brian Ector, Vice President Capital Markets. Please go ahead.
Good morning, ladies and gentlemen, and thank you for joining us today to discuss our third quarter 2018 financial and operating results. With me today are Ed LaFehr, our President and Chief Executive Officer; Bruce Beynon, Executive VP Corporate Development; Rod Gray, Executive VP and Chief Financial Officer; and Rick Ramsay, Executive VP and Chief Operating Officer. While listening, please keep in mind that some of our remarks will contain forward-looking statements within the meaning of applicable securities laws. I refer you to the advisories regarding forward-looking statements, oil and gas information and non-GAAP financial and capital management measures in today's press release. All dollar amounts referenced in our remarks are in Canadian dollars unless otherwise specified. And with that, I would now like to turn the call over to Ed.
Thanks, Brian, and welcome everyone to our third quarter conference call. I'm excited to deliver our first call following the strategic combination with Raging River. We have a lot to discuss today. But first, let me just take a moment and thank the Raging River and Baytex employees for what has been a very rapid and successful integration. We joined forces on August 22, and everyone has been engaged as one team, all moving into the same building less than 1 month later. Since closing the transaction, we have undertaken a detailed strategic review of our operations, confirmed the organic growth opportunities in our diversified portfolio of assets, and delivered on our near-term targets. We have repositioned Baytex as a self-funded North American producer focused on per share value creation and we couldn't be more excited. As a reminder, our third quarter results reflect a 40-day contribution from the Raging River assets. In the third quarter, we generated adjusted funds flow of $171 million, $32 million of free cash flow and excess of capital expenditures of $139 million. And we delivered production of 82,400 BOEs per day. Our diversified oil portfolio generated a corporate level operating netback, excluding hedging of $31 per BOE. This represents a 76% improvement over the same period in 2017. I am very pleased with our operations. Since the closing of the transaction, production from the Raging River assets has averaged almost 24,000 BOEs a day, consistent with our expectations. And the legacy Baytex assets delivered production of over 72,000 barrels equivalent per day during the third quarter. In October, our production increased to 97,000 BOEs per day, which highlights our strong performance post the integration, and demonstrates the value of our highly skilled people and exceptional assets. On the cost side of our business, we have reduced annual guidance for operating expenses by 4% at the midpoint to $10.50 to $10.75 per BOE, reflecting strong performance year-to-date of $10.54 per BOE. And we have continued to drive efficiency across our business with a 5% reduction in 2018 G&A expenses to $1.55 per BOE. One of the key benefits of the merger is our strong oil price diversification. This combination has truly transitioned us from a heavy oil company to a light oil company. Our light oil in the Eagle Ford attracts premium Louisiana Light Sweet or LLS-based pricing, and our Viking light oil, in Canada, delivered the highest operating netbacks in the company. At current prices, approximately 80% of our operating netback is derived from these 2 assets. The Eagle Ford represents 37% of our production, and generates approximately 47% of our operating netback and $300 million of free cash flow. Likewise, the Viking represents 25% of our production and generates approximately 33% of our operating netback, and $100 million of free cash flow. So while we have historically been known as a heavy oil company, that in fact, couldn't be further from the truth today. Having said that, I do know there's a lot of attention being paid to heavy oil differentials. It's an unfortunate reality of what we are dealing with in Canada when there is a lack of pipeline egress. I want to be very clear when I say that we are 100% committed to making decisions that are in the best interest of our shareholders, including and, especially, prudent capital allocation. In the right pricing environment, our heavy oil assets generate exceptional rates of return and provide meaningful organic growth opportunities. But that is not the pricing environment we are in today. As a result, we have implemented plans to optimize our heavy oil production. This includes building inventory, deferring new well completions and shutting in barrels where appropriate. This plan will reduce our corporate volumes by about 5,000 BOEs per day during the fourth quarter. But given current pricing, we’ll have a minimal impact on our adjusted funds flow. Additionally, crude by rail is an integral part of our egress and marketing strategy. We have increased our crude oil volumes delivered to market by rail to 11,000 barrels per day through 2019. This represents approximately 40% of our heavy oil production. And commencing January 1, 2019, approximately 70% of our crude by rail commitments are WTI-based contracts with no WCS pricing exposure. Let's now shift to our light oil assets. First, the Duvernay, where we have amassed over 430 sections of land and continue to prudently advance this emerging high netback light oil resource play in central Alberta. Our development has taken an important step with 2 new light oil discovery wells in the Pembina area located approximately 5 and 7 miles south of our initial 14 or 36 discovery well. These 2 wells established average 30-day initial production rates of approximately 750 BOEs per day per well, and that's 88% oil and NGLs. We believe the oil flow rates from these wells would rank among the top 20 wells in this play, and demonstrate the continuity of the oil window in the Pembina area where we control 256 sections of 100% working interest land. This will provide the focus for our 2019 pad development drilling program. We are also currently drilling 2 wells from the original 14-36 discovery pad, and we are now initiating completion activities. Staying with our light oil assets, the Eagle Ford in South Texas is one of the premier oil resource plays in North America, and we continue to see strong well performance driven by enhanced completions. In Q3 2018, this asset generated production of 37,200 BOEs per day, that net 77% oil and NGLs for the quarter, as opposed to 36,600 BOEs per day in Q2 2018. During the third quarter, the Eagle Ford generated operating cash flow of $130 million and free cash flow after capital expenditures of $85 million. And finally, the Viking asset is a shallow light oil resource play approximately 36-degree API oil, where we are producing 23,500 BOEs per day today. The Viking delivered the highest operating netback of just over $50 per BOE in our portfolio during third quarter. Turning to our balance sheet. We maintain strong financial liquidity with our credit facilities, approximately 50% undrawn. Our net debt totaled $2.1 billion at September 30, 2018, which is up from $1.8 billion at June 30, 2018. This increase reflects the net debt assumed from Raging River. Based on our '19 plans, our 2019 plans, we anticipate a year-end 2019 net debt to cash flow ratio of 2.1x, which is healthy, but not quite where we want it to be. Our target is to drive our net debt to cash flow ratio to 1.5x. And lastly, while our official 2019 guidance will not be out until early December, I want to update you on our preliminary plans. Our top priority will be disciplined capital allocation to drive meaningful free cash flow and a strengthened balance sheet. With a diversified asset base and product pricing mix, we will optimize capital allocation based on commodity prices and economic returns by area. In addition to the near-term impact of optimizing our heavy oil operations, we currently anticipate curtailing our heavy oil development activity and focusing on our light oil assets in 2019. As a result, our preliminary plans for 2019 include capital expenditures of $650 million to $750 million, which is designed to generate average annual production of 95,000 BOEs to 100,000 BOEs per day. Development plans for 2019 include maintaining a consistent activity set in the Eagle Ford and Viking, both of which are expected to generate significant free cash flow. And as I said earlier, we are very excited to continue delineating the East Duvernay shale oil play with an increased pace of pad drilling activity. This plan contemplates the restart of shut in heavy oil volumes by mid-'19. As we believe, continued growth in crude by rail volumes and incremental pipeline egress scheduled for late 2019 will lead to a stronger pricing environment for heavy oil in the second half of 2019. And hence, our development plans for heavy oil remain flexible based on the pricing environment and outlook. Despite the volatility in commodity prices, we continue to forecast adjusted funds flow for 2019 of approximately $900 million. With reduced spending on heavy oil, we are positioned to allocate approximately $200 million of free cash flow to our debt repayment, up from our original debt reduction plan of approximately $100 million for the year. Let me conclude by saying, I am extraordinarily proud of our team for delivering strong operational and financial performance, while at the same time, integrating our legacy Baytex business with Raging River. Our strategic combination has repositioned Baytex as a North American crude oil producer with strong free cash flow and an improved balance sheet. We have completed the integration, while delivering excellent drilling results, particularly, the oil flow rates from our 2 new wells in the Pembina region of our Duvernay light oil play. We are also benefiting from strong oil price diversification, which includes light oil production in the Eagle Ford and high netback Viking light oil production in Canada. As we plan for 2019, our top priority will be disciplined capital allocation to drive meaningful free cash flow. And with that, I will ask the operator to please open the call for questions.
[Operator Instructions] Our first question comes from Brian Kristjansen with Macquarie Capital.
Can you elaborate at all on the increased pace of activity you're experiencing in the Duvernay?
Yes. I'll probably turn that over to Bruce Beynon here in a minute. But let me just say, our plan has remained consistent. We expected the Pembina area to be a strong area for us. I would say the 2 new wells exceeded our expectations. So in this environment, what we're planning is to drill between 10 and 14 wells. We'll probably be looking towards drilling on the upside of that plan for 2019. But we want to move into a pad development mode. We want to focus 100% of our activity in the Pembina region, based on these 2 results. And we want to start building production and cash flow in essentially, along with Viking, our 2 highest netback operating areas. Bruce, do you want to elaborate on the plan?
Yes. It's Ed's capsulized it quite well. I'll just refocus, everyone, to our current Pembina and landholdings are 256 sections of land. And in the context of 2019, as Ed says, lots of wells, think of them as sort of 2-well pads. But really getting a cash flow center going, at the same time, we will continue to expand Pembina, both south and north, to continue to hopefully derisk that land. So we see a pretty good deep, deep inventory in this area. And by the time we get through 2019, we will have a very good handle on it. But as Ed said, really concentrating a lot of activity in proximity to the 3, which will become 5 Pembina wells by year-end.
It's about doubling of the activity set from 6 wells this year to 12 wells next year, around doubling.
When you referenced them all being in Pembina, can you quantify or characterize those as -- are some of those going to be sort of mini development? Like how far are you going to be stepping out?
Yes. I mean, you can appreciate the plans are flexible. But I think you would see 30% of those is what you would consider a delineation or step-out well. And 60% to 70% would be closer within 2 to 3 miles of one of these existing wells.
Bruce. And do you know -- or do you have an expectation of how many wells you will need to sort of get down to your targeted long-term well costs? Because is that 2 more pads type of thing or can you say?
Well, Jason Jaskela, our VP of the business team, and he's also with us here. We know we can get there, and we will do it. But I'll let Jason speak a bit on that.
Yes, I think it really comes down to gearing up with infrastructure. And I think we can look towards 2020 as kind of a target year to getting down to, what I would call our, kind of, development -- continuous development well cost.
Our next question comes from Jeremy McCrea with Raymond James.
Just bit more follow-up on the Duvernay here. Was there a reason why this rate was quite a bit higher than prior wells? Was it more a geological thing? Or was it a completion design change? And just a bit more breakdown of the 88% liquids, like how much would be oil? How much would be condensate and kind of C3-plus I guess? And then was this like peak production? Or was this initial raise and do you know there's -- like I just -- basically what's the pressure behind pipe here? How do you think this will decline here over the next few months here too?
A lot of questions in there, but I'll hand it over to Bruce again. But keep in mind, there are only 4 wells. We've only got 4 wells on pad, 4 wells on production before these 2 came on. And we got 450 sections of land. So this definitely exceeded our expectations. But I would not call it anomalous, it's in the top 20 wells as I said in the script, of all wells drilled in the region. And that's not just on a 750 BOE per day basis, the oil is 450 and C5-plus is about another 100 plus, so call it 550. And then there's some value-added NGLs in there. So I'll let Bruce talk to the details, but there is a lot of land to be developed here and we're on our sixth producing well. So we're very excited. There's a lot more running room and we have, we think the preferred land base in the area. So I'll turn it over to Bruce.
Yes. Thanks, Jeremy. A lot of nuances in there, and we will give you some of what we can. But appreciate, again, still on a competitive chapter. So we don't want to bear all facts at this point in time. And I'm sure you can appreciate that. Number one, exceeded expectation, again, a lot of the geotechnical information is still confidential, so we'll treat that as such. What I would lead you to believe is, we modestly exceeded our [indiscernible] and porosity cutoffs that we were anticipating, having drilled the initial 14-36 discovery well. So maybe a little bit better rock is one thing. The other thing is just how we're reporting production. In the first disclosure on 14 to 36, we really focused on the oil rate. And if we kind of did an apple-to-apple comparison and measured oil rates over the first 30 days of production, which we have on these 2 brand-new wells, 14 to 36 was very similar. So they've all been in that raw oil in that 430 to 500 barrels of oil per day average over 30 days of run time. So strong oil rates. We're pretty encouraged with that. As Ed said, this is a liquids-rich area. Pembina is definitely -- there's a little bit more gas, but more importantly, there is more liquids than say the [ Vesta ] basin, the Ferrybank area, that area. With respect to declines and things like that and forecasting EORs, we need more time to go there. I think, generally, the Duvernay play as a whole, I would just not try and get anyone too far in front of it, but declines have maybe been a little slightly shallower than anticipated. But still behaving like a tight oil resource would. So definitely I think rock is a big factor on this one. Jason can elaborate a little bit on completion. But we don't want to go too deep. Purposely, we've done our completions quite similar. So there is not a magical bullet on these last 2 wells, very similar to the first Pembina base well.
Yes. On the completion side, we've been consistent just with the plug-in Pembina itself, completion 50 meters spacing. And we're targeting still on that kind of 1.5 to 2 tons a meter problem loading. So consistent where we've been historically.
Did we catch everyone in there, Jeremy?
Our next question comes from Jordan McNiven with Tudor, Pickering, Holt.
I have 2 questions. First one here, on the 5,000 of production management that you talked about, are you going to break that down between what that is between shut-ins and inventory and deferrals? And is there a possibility that, that number moves higher through the first quarter '19 if they were there?
Well, I'll turn that over to Rick, our Chief Operating Officer, here in a minute. But let me just say that the 5,000 is roughly 2,000 of shut-in, but truly shut-in barrels in the fourth quarter, average over the fourth quarter. And then it's a combination of inventory builds and deferring the onset of new wells, keeping the oil behind pipe for a better day et cetera. But it builds from no shut-ins and no optimization in October to fairly substantial shut-ins and optimization in December. And then that will continue into January and February and then we'll see where the forward strip leads -- see where the WCS pricing ends up. Rick, do you want to elaborate on?
Yes. For sure, Ed. You've pretty much touched on it. Overall, the peak is coming in December, when we're seeing the prices at least currently at their lowest. And shut-in, overall, impacted to be about 8,000 BOEs a day in December, and shut-in is about half of that. And then between delayed and slight inventory build, that would make up the other half, roughly about equivalent around 2,000 BOEs a day each.
Perfect. And then, so just second question on conventional heavy barrels and just in terms of the blending on those. Just wondering what the current approach is there. If you're able to utilize more of the light oil Viking barrels to blend there? And maybe back out other products or condensate that you were using before. Just looking for an update there and the options available.
Well, we're looking at all marketing options, Egress, as you know is extremely frustrating for everybody in Canada, as I said. So we're looking at every possible option, including blending. But the first priority for us was crude by rail, and we have managed to get up to 11,000 barrels a day contracted and committed right through 2019. And about 3/4 of that is moving to the Gulf Coast as raw bitumen unblended with condensate so we don't have any cost of diluent, very advantage pricing. That's robust right through any sort of 40 to 50 whatever differential you want to pose. The crude by rail is very attractive. I would say blending in the Southern Saskatchewan areas is a place that we're looking at. But I think we don't have much to report there. Rick, do you want to offer anything further?
Yes. No, I think that's pretty accurate, Ed. A little bit in the Viking area. We are moving some of our crude in the Peace River area to some of the lighter stream pipelines. But that's a fairly limited opportunity. So pursuing what we can, but it is fairly limited.
We do have advantaged trucking on all of our assets and we're tending to use that and look for Raging River as well and combined opportunities, trying to get more of our barrels to Cromar, but that's being backed out as well. I think Jason, we're running about, what, 3,000 barrels a day. Roughly Viking crude over to Cromar to attract a little better pricing. But few optimizations here and there, but I wouldn't say it's massive at this point in time in terms of the blending strategy.
Our next question comes from Thomas Matthews with AltaCorp Capital.
Just wanted to touch on something Jason said, actually, just on terms of the infrastructure in the Duvernay. What kind of infrastructure build-out requirements do you think you need there? And what sort of CapEx would be required there? Is it just some surface batteries? Or will there be some gas handling pipelines that you will have to put in?
Sure. So I think it really just revolves around water management, as we've been very transparent in Duvernay actually require a ton of water. And so really it's water storage and water management and water infrastructure. It's not really related to egress as far as pricing, it’s more related to gain the water for surface storage and place to [ Nigel ] programs
The relatively small, circa $10 million for the water management to get us kicked off.
That's right. Yes.
Not much beyond that. So.
Got it. And then most of the other water management would just be wrapped up in the well cost? If there is anything specific on a single well requirement?
Definitely, yes.
Yes. Again, Thomas, a good way to think of it, Duvernay, since your history much like the Viking. Historically, 90% or more of the capital was directed to drilling and completing. We really see the Duvernay being very similar that the facility requirements remain kind of modular and manageable.
Great. Okay. All right, sounds good. And then just on in terms of the heavy oil side of things, the deferral of the budget I guess into 2019, is that -- are you going to take more money out of Peace River or are you going to reduce the Lloyd? Is there a preference there? Is it a combination of everything?
It's across-the-board on heavy, I would say, Thomas. But I think more so in the drilling program in Peace River, which tends to occupy some of our larger capital. So it'd be probably, arguably, a little more out of Peace River than Lloyd, but a pretty big deferral out of both. And that's how you get the $100 million from our last guidance to this guidance, to the $650 million, $750 million of CapEx.
All right, all right. Okay. And then just one last question just on the Duvernay well, did you guys let that well rest at all? Is there any sort of differences in all your completions in terms of letting it soak this time around versus prior times?
Well, there are 2 wells, Thomas. One in the north on the same pad, all in Pembina, you want to answer that?
Yes, I'll go first and let Jason come in with more details. There is debate on this whole concept where you're leading to soaking wells. And our net game plan so far in all our completions has been, we haven't really relied upon that and have more so just proceeded to bring the wells on stream as expeditiously as possible.
This concludes the question-and-answer session. I would now like to turn the conference back over to Brian Ector for any closing remarks.
All right, thanks, operator, and thanks, everyone, for participating in our third quarter conference call. Have a great day.
This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.