Baytex Energy - Q3 2018
November 2, 2018
Transcript
Operator (participant)
Welcome to the Baytex Energy Corp third quarter 2018 conference call. As a reminder, all participants are in a listen-only mode, and the conference is being recorded. After the presentation, there will be an opportunity to ask questions. To join the question queue, you may press star one on your telephone keypad. Should you need assistance during the conference call, you may signal an operator by pressing star zero. I would now like to turn the conference over to Brian Ector, Vice President, Capital Markets. Please go ahead.
Brian Ector (VP of Capital Markets)
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. With that, I would now like to turn the call over to Ed.
Ed LaFehr (President and CEO)
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 22nd, and everyone has been engaged as one team, all moving into the same building less than one 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.
Brian Ector (VP of Capital Markets)
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 CAD 171 million, CAD 32 million of free cash flow in excess of capital expenditures of CAD 139 million, and we delivered production of CAD 82,400 BOEs per day. Our diversified oil portfolio generated a corporate-level operating netback, excluding hedging, of CAD 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 CAD 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 CAD 10.50-CAD 10.75 per BOE, reflecting strong performance year-to-date of CAD 10.54 per BOE. And we have continued to drive efficiency across our business with a 5% reduction in 2018 G&A expenses to CAD 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 two assets. The Eagle Ford represents 37% of our production and generates approximately 47% of our operating netback and CAD 300 million of free cash flow. Likewise, the Viking represents 25% of our production and generates approximately 33% of our operating netback and CAD 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 is 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, will 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 net back light oil resource play in Central Alberta. Our development has taken an important step with two new light oil discovery wells in the Pembina area, located approximately five and seven miles south of our initial 14-36 discovery well.
These two wells established average 30-day initial production rates of approximately CAD 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 two 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 CAD 37,200 BOEs per day, and that's 77% oil and NGLs for the quarter, as opposed to CAD 36,600 BOEs per day in Q2 2018. During the third quarter, the Eagle Ford generated operating cash flow of CAD 130 million and free cash flow after capital expenditures of CAD 85 million, and finally, the Viking asset is a shallow light oil resource play, approximately 36-degree API oil, where we are producing CAD 23,500 BOEs per day today. The Viking delivered the highest operating netback of just over CAD 50 per BOE in our portfolio during the third quarter. Turning to our balance sheet, we maintain strong financial liquidity with our credit facilities approximately 50% undrawn.
Our net debt totaled CAD 2.1 billion at September 30th, 2018, which is up from CAD 1.8 billion at June thirtieth, 2018. This increase reflects the net debt assumed from Raging River. Based on our 2019 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 CAD 650 million-CAD 750 million, which is designed to generate average annual production of CAD 95,000-CAD 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-2019, 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 CAD 900 million. With reduced spending on heavy oil, we are positioned to allocate approximately CAD 200 million of free cash flow toward debt repayment, up from our original debt reduction plan of approximately CAD 100 million for the year.
Let me conclude by saying, I'm 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 two 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 (participant)
Certainly. We will now begin the question-and-answer session. To join the question queue, you may press star one on your telephone keypad. You will hear a tone acknowledging your request. If you're using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star two. We will pause for a moment as callers join the queue. Our first question comes from Brian Kristjansen with Macquarie Capital. Please go ahead.
Brian Kristjansen (Associate Director of Energy Research Analyst)
Morning, guys. Can you elaborate at all on the increased pace of activity you're expecting in the Duvernay?
Ed LaFehr (President and CEO)
Yeah, I'll probably turn that over to Bruce Beynon here in a minute. But, let me just say, our plan has remained consistent. We expect the Pembina area to be a strong area for us. I would say the two 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 wanna move into a pad development mode. We wanna focus 100% of our activity in the Pembina region based on these two results, and we wanna start building production and cash flow in essentially, along with Viking, our two highest netback operating areas. Bruce, do you want to elaborate on the plan?
Bruce Beynon (Executive VP of Corporate Development)
Yeah, Ed capsulized it quite well. I would just refocus everyone that you know, our current Pembina land holdings are 256 sections of land. You know, in the context of 2019, as Ed says, lots of wells. Think of them as sort of two 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 fully de-risk that land. So we see a pretty good deep inventory in this area, and by the time we get through 2019, we'll have a very good handle on it. But as Ed said, really concentrating a lot of activity you know, in proximity to the three, which will become five, Pembina wells by year-end.
Ed LaFehr (President and CEO)
It's about a doubling of the activity set from six wells this year to 12 wells next year. Around a doubling.
Brian Kristjansen (Associate Director of Energy Research Analyst)
When you-
Ed LaFehr (President and CEO)
Sorry, Brian?
Brian Kristjansen (Associate Director of Energy Research Analyst)
When you reference them all being in Pembina, can you quantify or characterize those as, you know, are some of those gonna be sort of mini development? Like, how far are you gonna be stepping out, do you think?
Bruce Beynon (Executive VP of Corporate Development)
Yeah, I mean, you can appreciate the plans are flexible, but, you know, I think you would see 30% of those is what you would consider a delineation or step out well, and 60%-70% would be closer, you know, within two-three miles of one of these existing wells.
Brian Kristjansen (Associate Director of Energy Research Analyst)
Thanks, Bruce. And do you know, or do you have an expectation of how many wells you'll need to sort of get down to your targeted long-term well costs? Is that two more pads type of thing, or can you say?
Bruce Beynon (Executive VP of Corporate Development)
Well, Jason Jaska, our VP of the business unit, is 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.
Jason Jaska (VP of Business Unit)
Yeah, I think it really comes down to gearing up with infrastructure, and I think we can look towards 2020 as kind of the target year to getting down to what I would call our kind of development, continuous development well cost.
Brian Kristjansen (Associate Director of Energy Research Analyst)
Okay. Thanks, guys.
Ed LaFehr (President and CEO)
Thank you.
Operator (participant)
Our next question comes from Jeremy McCrea with Raymond James. Please go ahead.
Jeremy McCrea (Managing Director of Equity Research)
Hi, guys. Just a bit more follow-up on the Duvernay here. Was there a reason why this rate was, you know, 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, you know, C3 plus, I guess. And then, you know, was this, like, kind of like peak production, or was this initial rates and, you know, basically, what's the pressure behind pipe here? How do you think this will decline here over the next few months here, too?
Ed LaFehr (President and CEO)
There are a lot of questions in there.
Jeremy McCrea (Managing Director of Equity Research)
Yeah.
Ed LaFehr (President and CEO)
But I'll hand it over .
Jeremy McCrea (Managing Director of Equity Research)
Yeah.
Ed LaFehr (President and CEO)
But keep in mind, there are only four wells. We've only got four wells on, had four wells on production before these two came on, and we've got 450 sections of land. So, you know, 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 pluses are about another 100 plus, so, you know, call it 550. And then there's some value-added NGLs in there. So I'll let Bruce talk the details, but, there's a lot of land to be developed here, and we're on our sixth producing well. So we're very excited.
Brian Ector (VP of Capital Markets)
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.
Bruce Beynon (Executive VP of Corporate Development)
... Yeah, thanks, Jeremy. A lot of nuances in there, and we will give you some of what we can, but appreciate, again, still in a competitive chapter, so we don't wanna, you know, bear all facts at this point in time, and I'm sure you can appreciate that.
Ed LaFehr (President and CEO)
Yeah.
Bruce Beynon (Executive VP of Corporate Development)
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, you know, we modestly exceeded our pay thickness and broad porosity cutoffs that we were anticipating, having drilled the initial 14 to 36 discovery well. So maybe a little bit better rock is one thing. The other thing is just how we're reporting production. You know, 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 thirty days of production, which we have on these two brand new wells, 14 to 36 was very similar.
Brian Ector (VP of Capital Markets)
So, they've all been in that, you know, 430 barrels-500 barrels of oil per day average over 30 days of runtime, 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's more liquids than, say, the Viking Basin, the Prairie Basin area, that area.
Jeremy McCrea (Managing Director of Equity Research)
Okay.
Bruce Beynon (Executive VP of Corporate Development)
With respect to declines and things like that, and forecasting EURs, we need more time to go there. You know, 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 play.
Jeremy McCrea (Managing Director of Equity Research)
Okay.
Bruce Beynon (Executive VP of Corporate Development)
So definitely, I think rock's a big factor on this one. Jason can elaborate a little bit on completions. We don't wanna go too deep. Purposely, we've done our completions quite similar, so there's not a magical bullet on these last two wells, very similar to the first Pembina Bay well.
Jeremy McCrea (Managing Director of Equity Research)
Okay.
Jason Jaska (VP of Business Unit)
Yeah, on the completions side, we've been consistent just with the plug and perf and inch cell completion, 15-meter spacing. You know, and we're targeting still in that kind of one and a half to 2 tons of meter proppant loading. So consistent with where we've been with the story.
Bruce Beynon (Executive VP of Corporate Development)
Did we catch everything in there, Jeremy?
Jeremy McCrea (Managing Director of Equity Research)
Yeah. No, that's all I was looking for. Yeah, thanks, guys.
Bruce Beynon (Executive VP of Corporate Development)
Perfect. Okay, thanks.
Operator (participant)
Our next question comes from Jordan McNiven with Tudor, Pickering, Holt & Co. Please go ahead.
Jordan McNiven (Director of Equity Research)
Hey, guys, I have two questions. First one here, on the 5,000 of kind of production management that you talked about, are you able to break that down between what that is between, say, shut-ins and inventory and deferrals? And is there a possibility that that number moves higher through the first quarter of 2019, if they stay where they are?
Ed LaFehr (President and CEO)
I'll turn that over to Rick, our Chief Operating Officer, here in a minute. Let me just say that the 5,000 is roughly 2000 of shut-in, but truly shut-in barrels in the fourth quarter, average over the fourth quarter. 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. It builds from no shut-ins and no optimization in October to fairly substantial shut-ins and optimization in December. 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?
Rick Ramsay (Executive VP and COO)
Yeah, yeah, for sure, Ed. You know, you 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, you know, shut-in overall impact would 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 1/2, roughly about equivalent, around 2,000 BOEs a day each.
Jordan McNiven (Director of Equity Research)
Okay, perfect. And then just second question, on again, on the conventional heavy barrels and just in terms of, of the blending on, 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, and maybe back out, other products or condensate you're using before? Just looking for an update there and, and the options available.
Ed LaFehr (President and CEO)
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 a lot 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 advantaged pricing. That's robust right through any sort of 40-50, you know, whatever differential you wanna pose.
Brian Ector (VP of Capital Markets)
The crude by rail is very attractive and I would say blending in the Southern Saskatchewan area is a place that we're looking at, but I think we don't have much to report there. Rick, do you wanna offer anything further?
Rick Ramsay (Executive VP and COO)
Yeah, no, I think that's that's pretty accurate, Ed. A little bit in the Viking area. You know, 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.
Ed LaFehr (President and CEO)
We do have advantage trucking, on all of our assets, and we're tending to use that and look to Peace River as well, and look at combined opportunities, trying to get more of our barrels to Cromer, but that's being backed out as well. I think, Jason, we're running about, what, 3,000 barrels a day, roughly, of Viking crude over to Cromer to attract a little better pricing. But, you know, a few optimizations here and there, but I wouldn't say it's massive at this point in time in terms of a blending strategy.
Jordan McNiven (Director of Equity Research)
Okay, perfect. Thanks a lot.
Operator (participant)
Our next question comes from Thomas Matthews with AltaCorp Capital. Please go ahead.
Thomas Matthews (Managing Director of Institutional Equity Research)
Hey, guys. Just wanted to touch on something Jason said, actually, just in terms of the infrastructure in the Duvernay. What kind of infrastructure build-out, you know, requirements do you think you need there? And what sort of CapEx would be required there? Is it just, you know, some surface batteries, or will there be some gas handling, you know, pipelines that you'll have to put in?
Bruce Beynon (Executive VP of Corporate Development)
Sure. So I think it really all revolves around water management. As we've been very transparent, these fracs 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 product stream. It's more related to getting the water infrastructure and storage in place to manage your programs.
Thomas Matthews (Managing Director of Institutional Equity Research)
Okay, and then,
Ed LaFehr (President and CEO)
There will be relatively small, being circa CAD 10 million for the water management to get us kicked off.
Bruce Beynon (Executive VP of Corporate Development)
That's right, yeah.
Thomas Matthews (Managing Director of Institutional Equity Research)
Okay.
Ed LaFehr (President and CEO)
Not much beyond that, so.
Thomas Matthews (Managing Director of Institutional Equity Research)
Got it. And then most of the other water management would just be wrapped up in the well costs, if there was anything specific on a single well requirement?
Bruce Beynon (Executive VP of Corporate Development)
That's right, yeah. Yeah, you know, again, Tom, it's a good way to think of the Duvernay, you know, since your history, much like the Viking, that, you know, historically, you know, 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.
Thomas Matthews (Managing Director of Institutional Equity Research)
Right. 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 twenty nineteen, is that? You know, are you gonna take more money out of Peace River, or are you gonna, you know, reduce the Lloyd? Is there a preference there? Is it kind of a combination of everything?
Ed LaFehr (President and CEO)
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, but a pretty big deferral out of both. And that's how you get the CAD 100 million from our last guidance to this guidance, to the CAD 650 million-CAD 750 million of CapEx.
Thomas Matthews (Managing Director of Institutional Equity Research)
Right. 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 when, in all your completions, in terms of, you know, letting it soak, this time around versus prior times?
Ed LaFehr (President and CEO)
Well, there are two wells-
Bruce Beynon (Executive VP of Corporate Development)
Yeah.
Ed LaFehr (President and CEO)
Two wells, Thomas. One to the south-
Thomas Matthews (Managing Director of Institutional Equity Research)
Sorry. Yeah.
Ed LaFehr (President and CEO)
... one to the north, on the same pad, all in Pembina. Do you want to answer that?
Bruce Beynon (Executive VP of Corporate Development)
Yeah, I'll go first and let Jason come in with more details. I don't-- There's debate on this whole concept where you're leading to with soaking wells. And, you know, 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.
Jason Jaska (VP of Business Unit)
Yeah, I think Bruce that covers it.
Bruce Beynon (Executive VP of Corporate Development)
Okay.
Thomas Matthews (Managing Director of Institutional Equity Research)
Perfect. That's it for me. Thanks, guys.
Operator (participant)
This concludes the question and answer session. I would now like to turn the conference back over to Brian Ector for any closing remarks.
Brian Ector (VP of Capital Markets)
All right. Thanks, operator, and thanks everyone for participating in our third quarter conference call. Have a great day.
Operator (participant)
This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.