Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp Fourth Quarter and Year-End Results 2018 Conference Call. As a reminder all participants are in listen-only mode and the conference is being recorded. After the presentation there will be an opportunity to ask questions. [Operator Instructions]. I would now like to turn the conference over to Brian Ector, Vice President, Capital Markets. Please go head.

Thank you Ariel. Good morning, ladies and gentlemen and thank you for joining us today to discuss our fourth quarter and year-end 2018 financial and operating results. With me today are Ed LaFehr, our President and Chief Executive Officer; Rod Gray, our Executive Vice President and Chief Financial Officer; and Jason Jaskela, our Executive Vice President, Shale Oil. While listening, please keep in mind that some of our remarks will contain forward-looking statements within the meaning of applicable security laws. I refer you to our advisories regarding forward-looking statements, oil and gas information, and non-GAAP financial measures and the notice to U.S. residents contained in today's press release. On the call today we will also be discussion an evaluation of our reserves at year-end 2018. These evaluations have been prepared in accordance with Canadian disclosure standards which are not comparable in all respects to United States or other foreign disclosure standards. Our remarks regarding reserves are also forward-looking statements. All dollar amounts referenced in our remarks are in Canadian dollars unless otherwise specified. And I would now like to turn the call over to Ed.

Thank you and good morning everyone. I'd like to welcome everybody to our year-end 2018 conference call. 2018 was a defining year as we repositioned our company to a high netback light oil company with a stronger balance sheet. We did this by merging with Raging River to create a new Baytex with stronger assets and organizational capability than ever before. We have successfully merged our two companies, 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 operational targets. I'm very excited about our operating performance post the merger and we are well positioned to execute our business plan and further strengthen our balance sheet in 2019. I will start with fourth quarter results and I would characterize the quarter this way, our operating results were strong. We exceeded our volume expectations and full year guidance, and we maintained diligent capital and cost control. We delivered on every facet of our business that we control. The only unfortunate aspect of the quarter was delivering these strong operating results during a period where we saw a sharp decline in crude oil prices including a significant widening of Canadian light and heavy oil differentials. As we sit here today the commodity markets have improved markedly both globally and in Canada which points to stronger financial results moving forward compared to Q4 2018. We delivered production of approximately 99,000 boe/d in Q4 2018 and 80,500 bo0e/d for the full year exceeding our annual guidance. And we did so with capital spending for full year of $496 million which was in line with our annual guidance. We generated adjusted funds flow of $111 million in Q4 2018 and $473 million for the full year of 2018. And our cash…

[Operator Instructions]. Our first question comes from Greg Pardy of RBC Capital Markets.

Thanks. Good morning guys and thanks for the rundown. Just I guess a couple of areas to dig into a bit, could you just maybe give us a sense as to what the duct count is in the Eagle Ford and maybe just the slight adjustment you made on drilling locations, could we start there?

Sure, the duct count last year as I was talking about it was running about in the 80's gross count for us. By the end of the year it had moved to the mid 60's and our target this year of course influencing the operator rather than controlling the outcome is to drive that down into the mid to low 40's. So what was the second question on the drilling count.

Just on some of the locations that you would have adjusted in the Eagle Ford?

Yeah, I don't think there was really any substantial adjustment. In the Eagle Ford we were running about 250 to 260 netbooked locations if that's what you're talking about in 2017. And this year we're looking at about 234. We drilled 21 wells though, so that reduces the 260ish down to 240 and we reduced the net count then by about six net wells. If that is okay.

Okay, yes, that's fine. And then just switching over little bit on the crude by rail, I guess first you have more appetite to take additional crude by rail and then could you just walk us through the arrangement that you have where you're really selling at a fixed price to WTI?

Yes. We are railing today 11,000 barrels a day which is about 40% of our total heavy oil production. And I have targeted internally to the team to get to about 50%. So that's another 1000 or 1500 barrels a day we'd like to put on. Of that 11,000, 8000 are moving from Peace River -- 7500 moving from Peace River and all of that is moving to the Texas Gulf Coast in Tuscaloosa, Alabama. So we would like to put on a little bit more. There are some rail constraints that still exist. There's also some pricing that needs to be right for all of us but we're in the money on pipe economics right now. But having said that, crude by rail has been and continues to be a critical part of not only our pricing formula but our egress formula. So in terms of pricing whenever we move to around an $18 to $20 differential or higher we want to be railing. And whenever we are less than $18 want to be on pipe. Having said that these are contracted barrels and we're not flexing away from those barrels. These are contracted barrels, it's not necessarily sender pay or taker pay but it's best endeavors and we value the relationships we have. In the egress it gives us to the particular market that we run to in the Gulf Coast. So that's maybe a little bit more than you were looking for.

That's okay, no that's helpful. And just to be sure I mean the spreads you are quoting then are versus [indiscernible] WTI spreads?

Yes.

Okay, great. But the other piece of it, I know that you guys have sold, you are selling I think at Peace River at a different rate off WTI and I am just trying to understand how that works?

Yeah, those are getting into more specific marketing arrangements Greg. We are happy to talk offline. We don’t -- we won't talk about our specific marketing relationships and pricing that we have with our broker into the Gulf Coast.

Okay, understood. Thanks for all of that.

Our next question comes from Thomas Matthews of AltaCorp Capital.

Hello everyone. Just have a few question. Just do you guys have any shut in volumes still outstanding, I know that you were shutting in some barrels in Q4 to reflect the differentials but have those been brought on again in Q1?

Yes Thomas, we did bring on those volumes mostly in January, some in February as well. We had about 1200 barrels a day curtailed in January and February. We have nothing curtailed today in terms of the Alberta requirements. So, we are moving ahead with nothing curtailed bringing back all of our heavy -- heavy is definitely making strong margins, it is good profitable oil right now and so we are flowing into that market.

Sounds good, and then just with the recent earthquakes in the [indiscernible] area, I know that some of the offsetting operators have been or one in particular obviously has been restricted on their fracking operations in the Duvernay. Just kind of wondering if that is filtered into your area or has there been any AER requirements to control fracking…?

Well, what we are doing right now, I will let Jason talk about this more specifically, but we're drilling four wells in the first quarter. We're not fracking any wells, we will be fracking this summer starting in June on those four wells. We are in a very different area, we are 60 miles to the north and the West, more virgin area. I'm not sure exactly where this was, I think it was in the heart of the best area that was in the press. But we will certainly stay on top of it and manage our business such that we mitigate any risk that exists. Jason, you have anything to offer there.

Yeah, absolutely. And I think the AER submitted or disclosed document that says it has to submit by March 11th the seismic data information, the frac reports, and all the future frac plans. And I think the AER will assess and make sure it complies with the subsequent order too and I expect thereafter they will get back to normal operations. I think it is precautionary measure from AERs behalf and I don’t expect anything long-term from it.

Okay, sounds good. Just on the oil reserves this was looking at some of the technical revisions there and there's a lot of positive technical revisions on the tight oil side which I would assume is all Eagle Ford, I know there's been some good wells drilled over the last year but just wondering if those technical revisions, if that trend is expected to continue, does that respond in a type curve revision from you guys or just how much of that is kind of Eagle Ford versus Austin Chalk just trying to understand the positive oil revision there, obviously it came with a little bit of negative NGL and gas revision as well but oil is more profitable clearly so, just trying to understand the dynamics with that technical revision there?

Right, I would say in the Eagle Ford these -- the revisions in the proved area, the probable area, and the 2P were all very relatively small and well within kind of the historical range. There are pluses and minuses. As you say this year there were more pluses than minus positive technical revisions to negative largely due to the technical complexity of the reservoir. So as you mentioned in the volatile window where we have solution gas and oil and condense [ph] it just depends how these are classified through NI 51-101. So, we run through that rigor every year and sometimes things move around a little bit. But in terms of the liquids to gas ratio everything is still running very strong in terms of this 78% to 80% total liquids, 58% crude, 22% NGLs, and then 22% dry gas. So it's very much on historical par if I can call it that.

Okay, yeah so no major kind of philosophy changes from your end there, okay. And then…

And we're taking a conservative view I think on some of the new well performance as you saw on our 2P reserves. We haven't booked to the higher performance we're seeing on the initial call it IP 365s on these new wells that we've drilled over the last year, year and a quarter. So we're taking a conservative approach with respect to the new well performance.

Okay, and I assume that conservative approach filters down to the Viking. If I remember from my Raging River coverage they were always pretty conservative booking, their Viking -- again some offsetting operators have taken some technical revisions down on the total recoveries from the Viking. Didn't notice anything in your reserve report here, so I would assume that the bookings are -- you're comfortable with the bookings from the Viking perspective?

Absolutely, we spend a lot of time on that during the merger and in our due diligence and the PDP reserves are plus 1% to 2P reserves from minus 1%. So we're very pleased with where we are with respect to the outcome but there are a number of things in the inner workings of the Viking that are complex. There are 9000 wells now in the trend and we've changed our development philosophy, we're moving more to a flat profile than a growth profile and one that generates free cash flow as opposed to growth. So we've changed some of our development thinking from that standpoint. The other thing we've changed is we're moving aggressively towards extended reach horizontal wells. 85% of our program this year is extended reach horizontals. So when you bake that all into the reserves basically as you say we think Raging River we're conservatively booked, have a good set of reserves management and have an undeveloped booking component that comes in every year. The conveyor belt is working very well, there was no impairment on the asset as we saw with some other competitors. So it's a philosophy that Raging River adopted that we've also employed that we think is conservative and prudent. But the development plan has changed somewhat.

Okay, and then final question I promise, just on the free cash flow. I know there was a clear message in the press release about paying down debt and getting to that 2.2 times debt to EBITDA. But just hypothetically under what circumstances would you see a back half increase to that budget just to maybe accelerate a little bit of growth through year-end and into 2020 or is that just something that's not quite on the table for this year?

Well those are April and May decisions. Right now we've got approved in our capital budget, the low end of guidance around 550 but we have discretionary spend of about $65 million that we will be looking at whether or not to implement. We need to continue to see -- we need to see two things, continue to see strong pricing and number two we need to see real tangible evidence of additional egress from Western Canada. And that means shovels in the ground on TMX or Line 3 and/or crude by rail ramping up to significant volumes around the 400,000 barrel a day range. That would give us the confidence then to go more towards the high-end of our guidance.

Okay, great. That's it for me, thanks.

Our next question comes from Phil Skolnick of Eight Capital.

Thanks for taking my question. Just looking at when you talk about your Q1 production rate of over 97,000 barrels a day, was that above expectations, I mean it sounds like based on the wording in the press release how should we think about the trajectory come out breakup season because it seems like that maybe there might be some upside to your production targets just based on that?

Yeah, I think so we expected to be 97,000 barrels a day even with the shut-ins. Q1 was always going to be strong, we are bringing back inventory that we have built up and some of the optimization that we had shut-in in Q4. So we expected it to be strong, we're running obviously whatever we say publicly it is going to be conservative so we're running very strong in Q1. But Q2 is always our seasonal downswing so we have got lumpy quarters and that's when we see break-up. Obviously it impacts both the heavy oil and the Viking. So, we'll see high in Q1, we move lower in Q2, stabilize in Q3, and we deliver midpoint of guidance.

Okay, thanks, that's it for me.

Our next question comes from Brian Kristjansen of Macquarie Capital Markets. Brian your line is live.

Sorry, I was on mute there. You mentioned in response to Thomas' question changing the development in the Viking, does that imply any change to the existing sort of 13 extended reach wells per section or the 22 shorties per section or is that just a matter of pacing?

Why don’t I turn this over to Jason, getting into the specifics of the development.

Sure, it is really just replacing a longer well with shorter wells. It doesn't really change the number of wells in the section. But they're really backed into from recovery, back to a well in place count. So, it really is simply just replacing long with shorts.

Yeah, short with long.

Okay, thanks JJ.

This concludes the question-and-answer session. I'd like to turn the conference back over to Brian Ector for closing remarks.

Alright, thanks Ariel. And thanks to everyone for participating in our year-end 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.