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

Well, thank you, operator. Good morning, everyone. Again, my name is Brian Ector, I'm the Vice President of Investor Relations for Baytex and I'll be hosting this morning's conference call. With me here on the call today are James Bowzer, President and Chief Executive Officer; Derek Aylesworth, Chief Financial Officer; and Marty Proctor, 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 to turn the call over to Jim.

Thanks, Brian, and good morning, everyone. I'm going to break down my comments into 3 parts for you today. The first part will be on our first quarter results. Second, I will provide you with an update on our operations, and then we'll close with an update on our hedge portfolio and marketing efforts. During the first quarter, we generated production of 52,000 BOEs per day and funds from operations of $102 million or $0.83 per basic share. Production was consistent with our previous guidance and our full year budget expectations. As previously disclosed, first quarter production was impacted by the timing of our development activities at Peace River and the suspension of our Kerrobert thermal production to facilitate the drilling of an infill well. I will expand on the initial drilling results from our 2013 program in just a few minutes but suffice it to say, we are very pleased with the execution of our capital program to date. We are currently producing approximately 56,000 BOEs per day and our full year production guidance is unchanged at 56,000 to 58,000 BOEs per day. At the midpoint of this guidance range, this would equate to an approximate 6% growth rate. Heavy oil prices were challenged during the first quarter. The benchmark price for heavy oil is Western Canadian Select or WCS, which trades at a discount to WTI. This discount during the first quarter is measured -- as measured by the price differential between WTI and WCS averaged 34%. Second quarter trading for the WCS differential is currently averaging 21%. One variance for us this quarter related to our operating costs, which from our perspective were unacceptably high. We expect to return to more normal levels in the range of $12 to $12.50 a barrel going forward. The main components…

All right. Thanks, Jim, for those comments. At this time, operator, we would like to open the lines for any questions.

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

Just a few quick questions here. First of all, on Seal. I wonder if you could outline the number of locations that you currently have identified that would still fall within the range of economics that you've outlined in your presentation. And maybe how many locations you have remaining or you think you have remaining that would be more in line with the really strong wells that you drilled in the first quarter?

Mark, thanks for the question. Good morning. We've got about 238 remaining locations that we've identified to date that are in our 5-year plan. We, at this point, haven't changed our guidance or type curves around the mix of wells, so it is outlined in our IR materials what we're projecting to date of the $5,000 to $9,000 per day barrels of capital efficiencies, the IPs of 300 to 700 BOEs per day for a 30-day average initial producing rate. So that remains the same as we speak today. And I do recognize that we've exceeded those with a few wells we had in our 2011 program and a few of the wells we've drilled so far this year.

Do you think you still have a few more of those around?

Like I said, we're sticking to our guidance but we certainly hope so.

Okay. And then kind of moving into thinking about Reno, how many locations have you currently identified there? And how would you say that the relative economics are versus Seal? And how much is Reno part of the '13 program?

Yes, we don't expect to get drilling back in Reno probably until late this year or into next year, but it's about 10% of our remaining locations that exist in our portfolio. There are, I think, on the order of 20 to 22 identified locations there. Those wells are the less expensive wells. We drilled fewer laterals there because the pay is thinner and you can recover from a greater area so they only cost about $2.6 million. But as a result of the shorter footage associated with fewer laterals, they produce in the 300-barrel a day range and the capital efficiencies are about $9,000 to $9,500 per day barrel.

Okay, that's great. Just curious regarding the bank line. You mentioned that you're trying to expand that. What would be the reason behind looking for that increase?

Yes. Mark, it's Derek here. Really, what we're doing there is introducing additional financial flexibility to our balance sheet. We don't have any immediate plans to be using that line. But the market today, there are opportunities out there and having incremental free line allows us to act quickly if we see acquisition opportunities.

Okay. And so you're active then in looking for those type of opportunities?

We're always looking.

The next question is from Kyle Preston from National Bank.

Most of my questions were asked by Mark, but gentlemen, I'm just wondering if you can expand on sort of what the reasons were for those higher well rates out of Seal there, the 800 barrels. Was that just a function of being in a sweet spot of the play, or did you put in extra laterals in those wells? Just wondering if you can expand on that?

Certainly, it's a combination of effects there. The -- we do have a little more length in some of those wells. In addition, the pay is thicker there and there's certainly the mobility ratio, which is the combination of a little less viscosity of the crude itself with a little higher permeability. The combination of those factors allows for some really good flow rates there that are quite impressive.

And can you sort of guess how many of your remaining 31 wells might be in a similar area?

We hope to have a few more of them that exceed our expectations. But in terms of specifically well to well, we'll see how that goes as we get through our program.

The next question is from Cristina Lopez from Macquarie.

Just a couple of questions for you, gentlemen. With respect to production, obviously, a big lift coming out of Q1. Are you seeing any downtime in Q2? Understanding that, of course, you can be drilling through breakup in the Peace River arch, but are you expecting any more downtime or do you expect production growth now sequentially as we go forward?

Sure, Cristina, it's Marty here. Spring breakup does affect us in some of our areas. It usually does. We always account for it with the -- we account for that impact in our production forecast. This year, as in most years, we're -- we suspended our drilling operations in Saskatchewan between April and June. But at Peace River, where we're drilling for multiwell pads, we should be able to drill right through breakup, so minimal impact at Peace River. As Jim mentioned, we're currently producing about 56,000 barrels per day. On top of that, we've got about 1,000 barrels per day shut in due to spring breakup impact in Saskatchewan, a little bit in North Dakota. But we expect those to road bans to come off in Saskatchewan soon and be able to get back on those wells and get them back up to production again.

And following on from Mark's question about the bank line and the potential for acquisitions, is there any way you could potentially prioritize acquisitions that you might be looking at, if you're looking at heavy oil, more thermal or light oil and sort of in an order of ranking, which you would prefer at this point?

Yes, we certainly don't talk about and speculate on acquisitions. But in terms of priority, Cristina, as we've stated in the past, we don't have a set priority, but what we do have is a set philosophy. And it is around what minimizes risk, which come in 2 categories: number one, things that we are familiar with that we can assess the risk on from a subsurface and operational standpoint; and the second risk is execution so that it fits our skill sets well. The third driver that tends to lead us towards what we end up doing is the entry costs are typically lower and the competition is a little bit lower for heavy oil opportunities, and therefore, we do seem to end up landing more of those. But we're looking across the spectrum of the 3 things you mentioned. But as you've known in the past, we've ended up looking from a economic standpoint straightforward on what will end up adding the greatest value. The highest competition in North America is or in and around light oil opportunities and that is also the highest entry cost, which sometimes leads to the poorest full cycle economics. So that kind of ends up tell you what drives this.

That's perfect. And now looking forward a bit into 2014. Obviously, the 2013 budget has a good percentage of thermal related to it. You've alluded to the fact that there will be a smaller component of that in 2014. Year-over-year then, do you expect production -- or sorry CapEx to be flat or down somewhat? Can you address sort of the longer-term outlook on CapEx? Is the 2013 budget a bit of an anomaly as far as its size goes?

Yes, Cristina. We, as you know, we don't put out our guidance until the end of the year, but directionally, I would say that your estimates there are -- your comments are correct. We do have $90 million that are tied to 2 specific projects this year that are in our capital budget. They are not reoccurring next year, so we do -- I'll just leave it to say that we don't have specific projects identified for '14 in our capital budget at this point for thermal.

[Operator Instructions] The next question is from Travis Wood from TD Securities.

Just a quick question around the dividend and how you think about that in the context of the volatility of today's heavy oil pricing. Generally you've been, as a percentage of cash flow, net 50% to 60% range, so how do you think about that going forward? And how important is rail and the hedging policy related back to that?

Yes, Travis, this is Jim. Maybe I should start by talking about how we kind of build up our budget in priority order because it's kind of the reverse order should a pricing scenario present itself where cash flows are significantly reduced. We first look at the amount of capital it requires to maintain our production flat and maintain our dividend payment. Those are the first 2 priorities. Our dividend flows right around $220 million. In order to keep our production flat this year, based on the projects we have, that was about $340 million. So that's kind of our first 2 most effective spends, and that's what we would look to protect the most. Then the second piece we add on is what does it take to provide some capital associated with production growth. And then in this year, we had a couple of projects that we just talked about that were $90 million associated with longer-term growth. So it would basically come off in that reverse order, if you will, if differentials were -- or WTI prices were suppressed sufficiently that we weren't going to meet our needs. So that's the first steps we would take. And in terms of what rail does is, yes, it's a big factor in what we do. From a WCS standpoint, it is our hedging mechanism for the most part. And it does really several things. There are several factors into the benefits. The first one is, is that you bypass the pad 2 market and get into the higher Mayan Gulf Coast market where people are willing to basically buy WCS for WTI plus 5. That's the first uplift you get. The second negative is that it costs more to get there versus transporting on pipes, so you have that as a negative. The third point that it is a factor in is it allows you to avoid diluent mixing, which is quite expensive to get it on pipe. And because we produce raw heavy oil and transport it on truck where we can get it -- a full -- full rail cars filled with no diluent in them, which is the benefit that we have. And then thirdly, any time that you're putting a heavy crude into a pipe system that potentially could have to be available to go to any refining point, and mixed with crudes that may not have quality discounts associated with the acid content to metals that sometimes heavies contain -- because many specific refineries have the metallurgy that acids or metals aren't an issue with and most of them are that way in the Gulf Coast and other places where they've been upgraded, if you can get to that specific refinery and you can be a rail, you then also lose the discount you have on pipe associated with quality. So it's the combination of all of those factors that make quite a big difference and that's why you're seeing the movement to rail.

Okay, sure. And then one question just on current volumes, the big step function from the Peace River area. So you're 22,000 a day, up call it about 4,000 from last quarter. Is that -- or from this quarter. Is that generally how the growth will shape out through the rest of this year? So -- and is it fair to say that corporate current production is closer to 56?

Yes, we stated that currently, we're right around 56,000 BOEs a day. You know what we averaged in the first quarter. We made that clear and we're going to definitely hit our guidance range as we go out. So it doesn't take too much to do the math to figure out where we need to be towards the second quarter. So I don't know that I would throw in a quarter-on-quarter build like that, but we'll seek to manage our capital so that we are clearly in the guidance range of both capital and production by the end of the year.

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

Yes, I just have a couple of concluding comments. This is Jim Bowzer again. Certainly, it was a challenged quarter with differentials where they were. We're certainly glad to have the quarter behind us. We are excited about our drilling results to date and where we're going. We expect to see growing production in the coming quarters, as we just talked, and look forward to reporting on those results in the coming quarters. Brian?

With that, operator, we will wrap the conference call. Thank you very much.

Thank you. The conference has now ended. Please disconnect your lines at this time, and we thank you for your participation.