Good morning, ladies and gentlemen. Welcome to the Baytex Energy Corp. Third Quarter 2013 Results Conference Call. Please be advised that this conference call is being recorded. I would now like to turn the meeting over to Mr. Brian Ector, Vice President, Investor Relations. Please go ahead, Mr. Ector.

Thank you, David, and good morning, ladies and gentlemen, and thank you for joining us today to discuss our third quarter financial and operating results. With me today are Jim Bowzer, President and Chief Executive Officer; Derek Aylesworth, our Chief Financial Officer; and Marty Proctor, 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 our advisories regarding forward-looking statements and non-GAAP financial measures contained in today's press release. I would now like to turn the call over to Jim.

Thanks, Brian, and good morning, everyone. We're very pleased to report on our third quarter results this morning, which are highlighted by the highest quarterly production rate and funds from operations in company history. Before I get into specifics on the quarter, let me update you on our 2013 guidance. As you will recall, our original guidance for this year was 56,000 to 58,000 BOEs per day. And following our second quarter results, we tightened that range to 57,000 to 58,000 BOEs per day. We are pleased to announce today in recognition of our continued strong operating results, we are further tightening our production guidance range for 2013 to 57,500 to 58,000 BOEs per day. And on to the third quarter itself. We generated production of 60,200 BOEs per day, an increase of 11% on a year-over-year basis. Our strong operating results, combined with an improved pricing environment, resulted in a 28% increase in our funds from operations versus the second quarter to $199.3 million or $1.61 per basic share. Our results in the quarter were positively impacted by a onetime recovery of cash income taxes of $6.6 million, which is a partial recovery of 2012 U.S. income tax paid. Our operating netback during the third quarter of $42.14 per BOE represented a 33% increase over the second quarter. With respect to our balance sheet, we ended the quarter with total monetary debt of $757 million, which represents a funds to -- a debt-to-funds from operations ratio of 1.3x based on FFO for the past 12 months. At the end of the third quarter, we had $605 million in undrawn credit facilities and no long-term debt maturities until 2021. In the first 9 months of 2013, our capital spending has progressed as planned in our key development areas. Spending for…

[Operator Instructions] The first question is from Mark Friesen with RBC Capital Markets.

Just a few questions. I know you're going to provide guidance for '14 in December. But just in the context of what you're saying about the increase to the CapEx levels this year, I can kind of imagine that might be in response to kind of what happened earlier this year, seeing very tight CapEx budget that led to a bit of a pullback in Q1. I kind of see this as trying to continue momentum and avoid that type of situation going into '14. Is that a good read?

Yes, there's a variety of reasons. That's certainly, one of them. We've got good, strong momentum going, and there's no reason to pull back from our operating momentum we have going today, Mark. In addition, there is some iron available that we -- is good that we want to get our hands on. Part of that leads into 2014 commitment of rigs. And in particular, there's one that we need to lock up here very soon and start using it to give us momentum into next year as well. So it's a combination of factors.

Okay. Thinking about the crude by rail, volume shipments have certainly increased for Baytex quite considerably, probably even higher than maybe where they were thought to have going -- thought to have gone. Where should we think of this going? Are we going to see these volumes continue to increase? What type of volumes can we expect?

Well, we've kind of laid out where we are today and what we expect in the fourth quarter. As we move into 2014, there are -- for starters, there are more opportunities than there have been. Additional sites are being -- these small, relatively -- the non-unit train sites that are relatively small are being built in and around a variety of light oil and heavy oil areas where there might be transportation issues associated with getting any crude on pipe, and we're continuing to take advantage of that. So the market is developing quite nicely, which would lead you to expect continued increasing rail volumes. However, next year, we will see increased refining capacity in PADD II. Flanagan South, we -- we're hearing, is on schedule. There are pipeline capacity increases in and around the Chicago and Wisconsin systems that come out of Canada. And all of those things are going to keep that market very dynamic. And it -- should it come to where we were this summer, again, which we do expect we'll get back to where differentials are in the sub-20 range, there'll be less of an arbitrage open for rail to continue to expand and us to want to expand further. So it's just going to depend on the market dynamics. Right now, it's certainly playing to our favor, Mark, and we've been quite happy with where we've been able to get to.

Okay, so that would indicate that we should continue to think of Baytex's crude by rail strategy being consistent with it has been and not look for any changes necessarily in terms of commitment -- larger commitment volumes or anything of that nature? Keep that flexible and...

Keep it flexible.

Okay. Are you able to comment on how rail -- the rail shipments, improved price realizations during the third quarter and the impact that might have on the fourth quarter realizations in the context of where differentials are right now?

As you know, Mark, we've got quite a few rail -- specific rail deals for the amount of crude that we have. Of the 20,000 barrels a day, I think we have somewhere between 10 and 12 separate contracts. So they all vary. In aggregate, frankly, during the second quarter, we'd have to go back and look -- or, excuse me, the third quarter, we were probably a little negative overall on the rail mix with differentials being as low as they were at 16.5%.

Yes. And so...

But as you go -- as we've kind of stated before as kind of some examples, and it depends on what our mix is, and you can see it's changing as our volumes are changing. But historically, we've said in the $20 range of a differential, we see an uplift of $2 to $4 a barrel or something like that depending on the contract. And then a $30 differential range, it can be high -- as high as $10.

Okay, that's helpful. And finally, just on the North Dakota Bakken. That's representing a smaller portion of the overall mix, 5%, 6% of current volume. How should we be thinking of that asset in the portfolio? Is that something you're considering changing going forward?

Not at this time. We have a standard capital allocation that we put to it. We allocate the most capital to the highest capital-efficient projects. And although the North Dakota assets and what our returns are there are relatively low compared to the other things that we pour money into, there are still solid rate of returns. Our performance has been solid there. You'll notice our well IPs were a little above the curve this quarter. So we're quite pleased with what is occurring there, and it's a matter of just making sure we do the proper capital allocation with it.

The next question is from Dirk Lever with AltaCorp Capital.

Sort of following up on what Mark was asking, when we look at your discount to WCS, we've been looking at guided around 82% of WCS. But as you do more rail, if you were to look at it from an overall basis on WCS, should we be looking at then a greater percentage of WCS as we look at your company going forward? Is -- would that be another way we could look at it?

It's Brian. I'll address that one for you. So the -- when it comes to our realized pricing, the discount that we see relative to WCS is a combination of a number of factors: the amount of condensate we're purchasing to blend with heavy oil, the cost of condensate and any certain quality discounts that we might achieve. And historically, we've been in that 78% to 80%, 82% range of WCS as a realized price. This past quarter in Q3, we benefited from a couple of factors. One was condensate pricing was less expensive. Condensate was trading at a discount to WTI versus historically, we've traded at a bit of a premium. So we would benefit from that. Secondly, as we rail more of our heavy crude, we're purchasing less condensate. We're railing more heavy barrels. So we're not purchasing as much condensate, and we benefit from that as well. And then this quarter, the WCS Index, the benchmark price was significantly higher than what we've seen in recent quarters at 16.5% off of WTI. All those factors played into the realization, which I think came in at about 86% of WCS. It will vary from quarter to quarter given all these various moving parts. And rail in certain quarters would -- we will benefit from that as well, as Jim alluded to.

Yes, I was just trying to find a shortcut way of articulating your realized prices, which came in higher than, I think, probably the Street was looking forward because you be beat the Street by a wide margin as you got to beat that number.

I think going forward, we -- 82%, 83%, 84% is a good range to be using at this time based on what we see in the market.

Dirk, it's pretty tough to pin it down to that single-digit points like that for the simple reason you -- these -- the other factors matter: how much you're paying for condensate, how much you're using, the quality discounts vary based on pipe space available and which refiners are taking them. And all those go into that uplift in addition to bypassing WCS with the raw heavy barrels themselves and getting into a Gulf Coast market where you're bidding off of somebody who can't basically get a WCS barrel another way and is bidding it off of a Venezuelan heavy, for example, or something like that. So there's all of those various factors that are in there. And so it has been creeping up as a result of these things all coming into play together. But it's even hard for us to pin that down to that number because it varies. If WTI is real high and the Brent spread is low, that could be very high, but we'd still have a WCS is another example, with some of those numbers being fairly wide and, say, condensate being expensive, or the quality discount being high in a given quarter or given month.

Well, I'm an analyst. I'm just trying to find a shortcut.

Yes, I know. And I think Brian's range he gave you was something to stick with for now, and we'll try to guide as best we can on it, but...

The next question is from Kyle Preston with National Bank Financial.

Just to take this whole topic a little bit further on rail pricing, I'm just wondering if you can talk about how much flexibility you have on this rail. I mean, I understand you do have some committed volumes there. But when we -- in a quarter, when we see differentials narrow or widen, I mean, how much flexibility do you have to change that around? I mean, last quarter in particular, you -- we saw very, very narrow differentials, yet your rail capacity increased in the quarter. How do you sort of deal with that going forward here?

We have some on spot, but it's relatively minor. It's less than 10%. But our deals are typically not much more than 6 months at this stage. When -- Kyle, if you go back, when we first began this effort, you basically had to underwrite someone who had built a loading facility nearby where you're at, and you had to make maybe 1 year or 18 months' commitment. Today, because there are more sites and some of the sites are essentially maybe paid for this stage, our term contracts are significantly shorter than that. But it's also getting to the point where we're moving more on volumes. So it's kind of hard to do it on a month-to-month basis, and we need to kind of make a commitment of a quarter. So for a quarter, we're kind of -- it's getting to be kind of the minimum, and 1 year is about as long as any of these are and with maybe a midpoint of about 6 months, so -- and a little bit on spot. What we haven't had to do is -- and we think it's available. Because the number of sites are increased, we haven't been in the position where we've said, well, we'd like to get 3,000 more barrels a day on rail tomorrow. But we think we could do that. We think there's a bigger spot market available in order to do that because there are so many more players and more options becoming available all the time.

Do you see any risk of losing that arbitrage as we get more and more guys moving to rail and also increased pipeline capacity to the Gulf Coast?

Oh, yes. Absolutely. I think that the arbitrage can get close. It got close to it in the third quarter. And that means the pipe is available and storage levels are going down, all the factors that cause a differential to come in. And we watch all those parameters. Having said that, if -- I think rail is here to stay for certain volumes of certain types of crude because it's just not about the obvious arbitrage that looks apparent from the simple calculations. And when you count in the cost of getting into pipe, the cost of blending condensate, quality discounts entering a pipeline versus hauling raw heavy oil to a refinery direct that doesn't want a diluted crude, there are going to be benefits there and uplifts that allow some of that to continue through time. And because we pretty much have all raw heavy crude, I think we'll participate in rail at some level almost all the time, I would think. But it's hard to predict that forever, but it'll -- in the foreseeable future, that's what I'd say.

Okay. So for the time being then, we should assume that you'll be shipping 23,000 to 24,000 barrels a day for the next couple of quarters at least?

Yes, I see no reason for that not to be the numbers for the time being.

Okay. Just one last question here, moving back to this capital budget for next year. I know we're getting some details here in a couple months or several weeks here, but can you give us sort of directionally where you expect that to go? I mean, the capital that you're adding in 2013, is that strictly a reallocation from '14 to '13? Or should we be looking at something flat or up or maybe down a bit since you'll be spending less on the Gemini SAGD project?

That's correct. As we've said before quite frequently and openly, into 2014, although we haven't set the number yet, we'll be directionally lower than our capital budget for what it was in 2013, Kyle. And we'll have that out here in just a few weeks.

And the next question is from Gordon Tait with BMO Capital Markets.

A couple of questions not related to rails. I think we've got that under control. The first I have is on your seal, your horizontal cold wells. It looks like the production rate, your IP rates and type curves vary from year-to-year on those wells, and I think it has something to do with the way that you actually developed the play this year. The rates are pretty good the way they did in 2011. Now I'm wondering next year, do you -- based on your development plans, would we expect them to look more like 2012 versus the way they are this year?

It's Marty here. We did have good performance in 2013. But really, we're not changing our expected profile, sort of the future drilling. They aren't very much different in the past years. The reality is there's a number of different factors that we can apply that can change initial rates. Really, you -- we could pull the wells harder, which would reduce -- which would increase declines initially. Or we could kind of maintain a lower rate, which might have less capital requirement and then, therefore, have a lower decline. But our expected ultimate recoveries, though, are very similar, we think. So your question is, I think, what is the 2014 program going to look like? Really, we've got a great inventory of wells, more than 200 locations to drill. I think we can expect 2014 results that are comparable to the past years. And like I say, we're not changing our expected declines for any of these wells.

Okay. And then secondly, on your -- the 15-well CSS module in Cliffdale, when -- approximately when would you expect it could hit its design capacity?

Well, it's like all of our CSS projects out in that region. Our anticipated production profile is a relatively slow increase. We don't expect to hit peak rates until 3 or 4 years out. And then we would maintain that peak rate for a number of years before we would see any declines. That 15-well module, it's essentially exactly the same as what we're expecting from the previous 10-well module. It's that same profile increasing over 3 or 4 years, then flat and then declining after some period. We're going to start -- we're commissioning our production facilities right now. We should start cold production with the first 5 wells immediately, and then we'll begin steaming in the first half of next year on that new module. Everything is right on track with our expectations.

Okay. And then lastly, with the -- you noticed -- you don't have much production -- a lot of production hedged into the second half of next year. And I'm wondering, just your take on the heavy light spreads for next year. Crow production is hitting the market now with the BP weighting [ph] as it's supposed to be. I think that they're starting their cokers now, expecting to be ramping up through the first half of next year. So how do you see those spreads looking for the second half of next year, sort of by middle of next year?

Gordon, this is Jim. The forward curve on WTI is backwardated quite substantially. So that's led to our kind of tapering in as the front end catches up to the back. So that's how we've conducted our hedging so far this year and explains that. And in terms of the WCS differential, it's posted out there. I think Cal 14 [ph] has varied between numbers of 20% to 25% right now, and it's gone up and down. And we've had a little bit of a widening in the Cal 14 [ph] spread of what's on the market right now as a result of a whole series of pretty negative issues that have happened here in the third quarter. And if you take a look at the -- Northern Tier and Sinclair are down. Both have fires, BP had its coker delay announced here. Their Central Bakken unit was down of their main crude facility. And then the worst one was just recently. It looks like CITGO at Lemont is going to be out. That's 175,000 barrels a day for 4 to 5 months is what's been reported in the news. If you took those kind of factors coming out of driving season into turnaround season, which is what -- where we're at right now, and date this 2 years ago when there was no rail capacity available or very little anyway, not what's there today out of Canada for all crudes, it doesn't matter what -- if it's light or heavy, we would be in a -- at a very, very, very high-differential market right now. So those things have significantly mitigated and what I believe brought this window down from what used to blow out in the -- up to the minus 40 off of WTI to where we sit today. And so that is all playing a factor. And next year, most of those things turn positive. When anybody's working on a refinery and it's partially running it while they're doing an expansion, you do tend to have some upsets and they'll get those been settled out. And then in addition with the pipe expansions that have been announced, as I previously referenced, and Flanagan coming on midyear, it's going to be a very different year, and we -- and what is apparent to me on the more positive side than negative things happening, which is what's occurred in the past. So I don't pay -- what I'm trying to say is I don't pay too much attention to what the WCS forward curve is. One, there's not much of one, and it does vary a little bit. But it's -- I think it's reflecting what could be a more positive 2014 and beyond.

That seems to make sense as some of the issues are resolved the first half of the year. Very good Q1 then. Then it could be a different situation looking in the second half of next year.

All right. And -- you bet, Gordon. Thank you.

There are no further questions registered at this time. I'd now like to turn the meeting back over to Mr. Ector.

All right. Thank you, Dave. And thanks to everyone for participating in our third quarter conference call. If anyone on the line has any additional questions, please call Investor Relations toll-free at 1 (800) 524-5521. Thanks again, and have a great day.

Thank you. The conference call has now ended. Please disconnect your lines at this time. Thank you for your participation.