Good morning, ladies and gentlemen. Welcome to the Baytex Energy Corp. Second Quarter Results Conference Call. Please be advised that this call is being recorded. I would now like to turn the meeting over to Mr. Brian Ector, Senior Vice President, Capital Markets and Public Affairs. Please go ahead, Mr. Ector.

Thank you, Mary. Good morning, ladies and gentlemen, and thank you for joining us today to discuss our second quarter 2014 financial and operating results. With me today are Jim Bowzer, our President and Chief Executive Officer; Rod Gray, our Chief Financial Officer; and Rick Ramsay, our 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 the turn the call over to Jim.

Thanks, Brian, and good morning, everyone. We're pleased to report our second quarter results, which include 20 days of operations from our recently acquired Eagle Ford assets, and the Eagle Ford is one of the premier resource plays in North America, and will certainly be an important growth engine for Baytex going forward. The second quarter of 2014 was very active for Baytex, and we also believe it was marked by some significant achievements. I would like to highlight a few of those achievements for the year beginning with a view on operating results. We generated production of approximately 67,000 BOEs per day, which was underpinned by strong performance from our base business. Production increased 12% over the first quarter of 2014, and 15% over the second quarter of 2013. We delivered funds from operations of $202.5 million or $1.49 per basic share. This excludes acquisition-related costs of $37 million, and represents a 19% increase over the first quarter of 2014 and a 30% increase over the second quarter of 2013. We realized an operating netback of approximately $41 per BOE, which is one of the strongest in company history. This represents an increase of 11% over the first quarter of 2014, and 28% over the second quarter of 2013. Our Canadian operations generated an operating netback of approximately $39 per BOE, while the Eagle Ford generated an operating netback of approximately $54 per BOE. And lastly, we maintained a conservative payout ratio net of dividend reinvestment plan participation of 37%. The second area I would like to highlight relates to the advances we have made executing some key objectives. As you well know, we closed the $2.8 billion acquisition of Aurora, adding 22,000 net contiguous acres in the Sugarkane Field, located in South Texas in the core of the…

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

My first question is about the Brent-linked contract that you've implemented. Are the volumes of that coming out of existing rail shipments? Or is this incremental to the volumes you've already been shipping by rail?

Mark, this is Jim. It's a bit of a mix. As you noted, our third -- our projection for third quarter volumes on rail are going up. So it's really a matter of how much rail total capacity we're going to have in that 6 months duration. But I would call it as partially incremental, and a partial consolidation of some of our other contacts into this one.

Okay. And you are able to give any guidance on to what kind of differential from Brent you've entered?

No. What we have disclosed is -- for competitive reasons, it's probably all you're going to get on that for the time being.

Okay. Moving over into Lloydminster and the multilateral wells that you've been starting to drill there specifically, how should we be thinking of your multilateral program there? Like what are, I guess, the cost or operating benefits of the wells? And should we be thinking of this as driving improved economics? Or could we expect some production growth from the Lloydminster or maybe both? Or how should we be looking at the multilateral program?

It's certainly going to improve, if it continues to work, our capital efficiencies because you only have 1 vertical wellbore, and you're getting multilaterals out of it. But I'll let Rick Ramsay here, our Chief Operating Officer, provide just a little more color for you, if that's okay, Mark?

Yes, please.

Mark, we are fairly early into translating that technology over to our Saskatchewan assets. And really, as Jim has commented, it's pretty much going to be a capital efficiency gain that we're going to see there. Generally, we're spending about $950,000 for -- drill, complete and equip for a single leg well there, and for a 2-well -- a 2-leg well. We're bringing that down to about 1.1 million to 1.2 million. So that's really where we're going to be seeing the efficiencies.

Yes. Great, That's good. Do you expect to see any production growth out of Lloyd or you're still planning to keep that region flat?

That's really not going to change our overall production profile, just really -- just an improvement on the capital side.

Okay. Great. Maybe while I still have you in here, Rick, just a question on Cliffdale. Can you maybe comment on the schedule or the pipeline of follow-up thermal module?

Mark, sort of early into our second module over there, and still very much learning how the performances is looking. We just started steaming in June on our 13 and 10 facility, and we really want to understand better the performance there. Obviously, with the new Aurora acquisition, we'll be making decisions on capital allocation across the entire organization as we work our way through the budget process. So it's sort of premature, both from a technical perspective and the capital availability perspective on when we'll be moving forward with the next modules there.

Okay. And just my final question is about the Eagle Ford. Are there any Austin Chalk locations currently scheduled or when do you think you might test some Austin chalk locations?

Mark, this is Jim again. As you well know, we've had an announcement of another chalk well, the 30-day IP that came out. I can't remember if it was May or around that time frame, but it's 1,600 barrels a day, which is by far the best results. Certainly pleased with that. And to get to your question, yes, there are a few more test being put forth this year to continue to delineate the productivity of the Upper Eagle Ford Austin Chalk combination there.

The following question is from Dirk Lever from AltaCorp Capital.

When looking you're looking at your production and what was core and you were talking about 5% to 10%, so you've sold off the assets in the Bakken, so you sold your North Dakota assets. Do you have some more -- some smaller asset that we can see disappear over time as you sell them off or is the sale program done now?

I wouldn't say it's done, and I don't want to speculate too much on the size of what remains because we're just kind of sorting through the next phase of that. From when we started this, Dirk, it was just a couple of months ago, and we really worked hard to get that put together, get a full bid suite in, and we're very pleased within just a few weeks, 6 to 10 weeks to get a PSA fully signed. So I was quite pleased with the team's efforts on that, but we will be looking at a few other things that really don't fit that are some legacy assets of not nearly as an individual piece as big as what the North Dakota one was. But we'll look at those as we go forward here, and there's probably a few other little things that we need to just -- we're better off in somebody else's hands.

Got you. So we shouldn't be surprised if there's some small odds and sods that are sold off over a period of time?

Yes, I wouldn't be.

The following question is from Patrick Bryden from Scotiabank.

Just curious on the Eagle Ford. If you can give us a sense for how you think volumes might progress given the drilling and completions and tie-ins that are in the hopper?

Sure, Pat. In general, I would say a couple of things. One, as we've moved to these large 6-well pads, where you're drilling 6 wells on each pad, then you're coming back to zipper frac everything together and then bring them on all together in a sequence of inventory of the existing wells, it has increased a little bit, which is fine. That's just part of what those capital efficiency gains bring you. So you need to think of it that it's going to be a little lumpier than it has in the past coming forward. So we'll see many wells coming on at the same time, more than in the past. A boost from that and then a little bit of delay, and you'll see it, I'd like to use the word lumpy, in our production forecast going forward. On a quarter-to-quarter basis, it may not be too bad. So I don't want to overemphasize that because there is quite a bit of activity as we got about 10 rigs running on our acreage here. But you'll see it continue to ramp into -- rattle off the inventory numbers. And as we move into August, those wells over the next couple of months that are in inventory, a bunch of those are going to come online and will boost production into the second quarter and -- or excuse me, into the third, and then on into the fourth as well as that program continues.

Great. And any kind of seasonal patterning to it or just chewing away with the 10 rigs and getting things done?

There's not a lot of seasonal patterning that I would project at this point in time. Once in while, if winter hits down there, it can free some things up, and really cause some production problems for short durations of moving fluids around. You can imagine, in South Texas, there's not a lot of heat tape running on water lines or things like that. So if it ever does freeze, it can raise a little bit of havoc. But from a drilling standpoint, it's 24-hour operation, 365 days a year. And all the equipment is dedicated. So the frac crews are dedicated. The rigs are fully dedicated. So it isn't like you're bringing too many in, and laying them off either.

Understood. And is there any differentiation or distinction between sort of the oil versus liquids windows that you're going to be pursuing or is that split looking to be consistent with the past?

It should be fairly consistent. It will vary on -- a couple of things drive that. One, you're trying to maximize the individual rates of return, although all of these are very, very high. So we're not too worried about that, but you're still trying to do that as well, and we have conversations with marathon about that. Secondly, as the volumes have continued to ramp-up and you are expanding the production facility, so you try to tie in your drilling where the -- in best proximity to your production facilities got the expanded capacity to take the fluids in. So that might drive a little bit of it as we go forward as well, Pat.

Okay. Great. And last question. It's always tricky to figure out pricing dynamics. Any commentary on some of the recent changes legislatively and/or supply versus demand in that neck of the woods?

There's been several things out. Here, recently, in the press, over the past couple months, everyone knows that you have the -- a couple of companies that were involved in getting a stabilizer classified as a processing equipment so that the field condensate, in some cases, can be classified as exportable. It looks like that's moving forward. You had a recent discussion here from the Commerce Department saying that they hadn't changed the rules, but the rules have always allowed export of products. And it's clear that anytime you go through some sort of processing equipment that stabilizes crude, whether that's through a tower or other devices, the refineries have been doing it for years, and it's really that this is happening in the field, in field gas plants and in field stabilization columns or stabilization tanks. So to pull off the lighter ends of propanes and butanes, and that's -- there's not any difference between what is happening from a chemistry standpoint in those fluids, and it sounds like a lot of this is getting exported. I don't know if you read today, there was something at about the first very large full tanker condensates heading out of the Gulf of Mexico, and that caught a bit of news. So I think it's just a matter of people getting comfortable that the rules are being applied properly, and that the classification of your equipment does indeed meet the condensate processed guideline.

Got it. I appreciate that. I'll get out of the way. If I can just add one more last question, please, maybe for Rick. When we look at the Gemini steamed oil ratios, is it possible to get a sense for where the ISORs are right now? Or at least maybe where you're thinking the steamed oil ratios are for the life of wells?

Yes. Certainly. Currently, we started up our steam circulation in late February, and we're currently running with a cume SOR of 3.3 and an instantaneous SOR of 1.9, and that's probably as good as what we could hope for.

And life of well? Do you have any thoughts about that as you think ahead?

Sorry, I didn't catch your question.

Sorry, the life of a typical well in that area, do you have any thoughts as you think about the potential for commerciality?

The life generally ranges, I guess -- it's a pilot project for us, and we're early days into the production life there, but the typical life would be about a 5 to 6-year time frame from a steaming perspective, and then just converting over to coal production afterwards.

Okay. And the SOR might be in the range of, say, 3 years, something like that or 2?

Yes. It'd probably be from a cume perspective, down in the low 2 range. It sort of matches historically with what we've seen on some of our other projects.

The following question is from Peter Ogden from Bank of America Merrill Lynch.

Just a follow-up on the Eagle Ford and Pat's question. Just looking for a little more granularity. If you take the 20 days and pro rate it, you got something about 27.5 thousand BOEs a day as a second -- maybe end of second-quarter rate on the Eagle Ford. Looking at your second half guidance of 86 to 88, that would almost imply that the Eagle Ford has been fairly flat in the second half if you assume Canada is at 60,000 BOEs a day. So just looking for a little bit more granularity around whether Canada comes down, what kind of exit rate you'd be looking for on the Eagle Ford, appreciating that the production is lumpy.

Yes. Peter, just in general, we're looking to continue to maximize our capital efficiencies here, and I want to take this all the way back to the big picture of where -- what we have going forward, and what we've been doing throughout the long-term history of Baytex is providing capital efficiencies that are good enough to throw off enough cash to support the dividend, and a moderate growth rate of around 6%. So as we go forward, we're trying to balance that. And so if our production gets higher in one area, we may pull back more capital in another to make sure our growth rates don't get out of hand, and that we manage that inventory over the long haul and continue to deliver consistent results around kind of that 5% to 6% growth rate and continued effort, and then don't forget that we take out our North Dakota sale in this volume here as well. And for the second half, the projection of North Dakota was about 3,800 BOEs a day net of Baytex volumes as we go forward, and that's already out of those numbers as we go forward. So I think I provided the color of how we're going to try to manage it as opposed to exactly what the numbers will be in that range.

Okay, I mean, do you have control on the Eagle Ford, I guess, per say? I guess that would be the question around Marathon's goal, and where they're going to grow it towards year end? And would you expect Canada to decline, I guess, as you fund that growth on the Eagle Ford side?

Parts of it may. It just depends on the overall production growth that we get there. But like I said, the biggest -- I think the biggest piece you might be missing is the separation of North Dakota from the remaining part of the year in those numbers.

The following question is from Phil Skolnick from Canaccord Genuity.

How has the well results in Peace River been progressing? Have you still been experiencing those high IP rates that you had been in, in the past?

I'll let Rick give you the details on that. So go ahead, Rick.

Sure. Yes, Phil, we drilled 12 wells in Q2, followed up by 8 wells, which we had drilled through Q1, and overall, the performance is -- we do have a number of different tiers that we focus on, but overall, the performance is fitting exactly in the range that we anticipate.

Are you still seeing any of those high rate wells or just now they're coming back down to the more normal levels that you saw in the past?

Yes, we're seeing a range across that -- across those levels. We've seen a couple up in that higher range that we were reporting previously, and some coming in a bit lower in the lower part of our range. But overall, averaging out sort of right in the middle of the guidance that we've provided on expected performance from those wells.

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

All right. Thank you, Mary, and thanks, everyone, for participating in our second quarter conference call today. Have a great day, everyone.