Good morning, ladies and gentlemen, welcome to the Baytex Energy Corp. Fourth Quarter 2012 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, Vice President, Investor Relations. Please go ahead.

Thank you, operator. Good morning, everyone. Again, my name is Brian Ector Rande. I'm the Vice President, Investor Relations for Baytex and I will 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, 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. On the call today, we will also be discussing the evaluation of reserves and continued resources at year-end 2012. These evaluations have been prepared in accordance with Canadian disclosure standard, which are not comparable, in all respects, to United States or other foreign disclosure standards. Our remarks regarding reserves and continued resources are also forward-looking statements. 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. 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. First, I'm going to comment on our fourth quarter results and our year-end reserves. Second, I'm going to provide an update to you on our operations, and then we'll close with an update on our marketing portfolio and the oil differentials and use of rail transportation. With respect to the fourth quarter, Baytex generated quarterly production of just over 55,000 BOEs per day, which brings us full year production to approximately 54,000 BOEs per day, right at the midpoint of our full year guidance. Production during the quarter was weighted 87% to crude oil and natural gas liquids and 13% to natural gas. Our funds from operations totaled $127 million, or $1.05 per basic share, earning our funds from operations for the full year to $533 million or $4.44 per share. This represents the second highest funds from operations in our company's history, which given the volatility we have experienced in heavy oil differentials over the past year, is a sign of the underlying strength of our core business. During the fourth quarter, we had a nonrecurring adjustment to our royalty expense, which reduced our funds from operations by $4 million or $0.03 per share. So excluding this adjustment, our funds from operations would have come to $1.08 per share for the quarter. Our payout ratio, net of dividend reinvestment plan, remain conservative at 43%, which is consistent with the 40% payout ratio realized for the full year. We ended the year with total monetary debt of $603 million, representing a debt to funds from operations ratio of 1.1x based on funds from operations for the trailing 12 months. And we have significant financial flexibility with over $580 million of available…

Okay, thank you, Jim, for those comments. And at this time, operator, we would like to open the lines for any questions.

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

Just a few quick questions. First of all, you made specific reference to the rail marketing arrangements that you've been undertaking. Could you quantify the impact of that on either your price realizations or your net backs that you realized in the fourth quarter?

Yes. Mark, it's Derek here. I think what I would tell you is in Q4 of 2012, we had a net uptick relative to the next best alternative at the time that we could have sold those barrels at over [ph] $5 million. Obviously, the uptick is dependent upon the WCS environment at the time. And we actually lost on our rail deals in October and November because the differential environment was quite tight then. If we fast forward to Q1, obviously, we've got about double the volumes and the WCS environment is worse in Q4 -- or in Q1 than it was in Q4. So I think it's reasonable to expect a much more material contribution from rail in Q1 than in Q4.

Sure. And just keeping on that theme, I understand you deliver to a local marketer in the Alberta region. Would you consider taking that all the way yourself to improve those realizations?

Yes, Mark, this is Jim. We typically don't see a need to do that. The infrastructure that is in place that we deliver to has been paid for by others. It's really not where we want to spend our capital. If indeed it continues to expand in the future and our participation would help get a new facility kicked off, we might consider that but there really hasn't been a need to do that at this point in time. So we haven't participated directly in the operations itself of rail or loading facilities.

Okay. Jim, just curious here. You had a disposition, a small disposition subsequent to year-end, and there was, of course, the North Dakota one last year. Do you see any more asset dispositions in your future here?

It's always a possibility, Mark. We continue to review the portfolio for things that either don't fit or are no longer core to us. And on occasion, find some opportunity that it may be more valuable to someone else in their hands versus ours. And so, if we run into those kinds of things, that may be the case. I don't mean to imply that we have some sort of disposition target that's outlined for the year.

Okay. And just finally from me. You made the point of being a little more specific with production guidance dipping to about 52 in the first quarter. When do you expect we could see production return to, say, Q4 levels of 55,000? Like is that end of Q1? Is that a Q2 type of target? When does it turn around?

Yes, well, let me start off by saying our budgeting process that we undertook this past year is pretty similar to what we've done in the past. And if you look back at our past couple of years, our fourth quarter program did always slow down, and that was consistent and this year was really no different. With respect to the pace in 2013 though, we did plan for a reduced pace in -- if you refer back to my comments there in Q1. So clearly, we're essentially full up and running in terms of our rig program right now, and you'll start to see that impact in Q2 and on into Q3. So I think that answers your question. I would ask Marty here to step in and talk little bit about the Q1 plans that we had in place. Marty, do you mind commenting on that?

Sure, Jim. Yes, there were certainly some unique circumstances in Q1 for us. For example, at Peace River, we're drilling on previously undeveloped sections of land in the Harmon Valley area, and that required significant lease construction, the new roads and of course, that led to additional regulatory attention. And we're working hard to minimize our impact on the environment in the area. So it was to improve -- we want to improve the efficiency of our gas gathering and our infrastructure. So we've designed and built a couple of larger-than-usual PADD sites for drilling this year. And that required some of our applications to be submitted on a non-routine basis. For example, we've got one PADD that's got 9 wells on it, which is the largest PADD ever for us for our cold multilateral drilling. Most of our previous drilling had only 3 or 4 PADDs so that's a significant increase in size. Anyway, consequently, there's was additional regulatory process time built into that plan -- into our budget plan in order to accommodate the change. It was a relatively minor change in our strategy. Though we've noted, as Jim said, we got our roads and our leases constructed and our drilling program is well underway. Cost of company we've got 15 drilling rigs running right now. That includes 4 at Peace River drilling production wells and 2 at Peace River drilling stratigraphic test wells. And since we're drilling from PADDs, we expect we can drill through spring break up this year at Peace River. It should also be noted that at our corroborate SAGD project, we drilled an infill, a thermal infill well during the first quarter. And that required us to take our thermal production offline for about 10 days. In general, I'd say, I'd just reaffirm that we're on track to meet our annual guidance of 56,000 to 58,000 barrels equivalent per day.

Okay. So if I understand you correctly, the fluctuation going into Q1 is purely a timing issue, it's got nothing to do with the changes to decline rates in any of your producing areas?

That's correct, yes.

The next question is from Jeremy Kaliel from CIBC.

I think a couple of my questions have already been answered by the first speaker. So maybe I'll just take it a little bit further. Would you be able to give us some guidance on expected production levels for Q2, even just a range to give us a sense of what kind of recovery we should expect? And could you actually give us what your corporate decline rate is? And as well as your decline rate at Seal? And just maybe reaffirm whether or not there's been any changes recently?

Yes, this is Jim again here. Concerning our quarterly guidance, we've got it out for the first quarter here. We intend to build back up through the year. And that was all consistent with the plan we had built to reach the midpoint of about 57,000 BOEs per day. On our Peace River decline rates, that's been consistent. The base there is about 33% or so for -- on average for the entire production base. And the wells typically on -- new year, first year wells are kind of in the 50% range, ranging up as high as 55%, and that's been consistent with what we've seen in the past. On a corporate basis, our underlying decline for the entire corporation is about 28% to 29%.

Our next question is from Gordon Tait from BMO Capital Markets.

Approximately how many years of drilling inventory do you have for these cold wells at Seal, given the pace you're currently drilling them at?

Sure, Gordon, it's Marty here. We've got over 200 wells in our inventory at Peace River for cold development drilling. At the current pace, we're look at about 6 years of inventory.

Oh, yes. I guess, by that time, Cold Lake, Kerrobert should be up and running to sort of...

Yes, yes.

And Harmon Valley as well. Is that right?

Yes. Well, of course, Harmon Valley, we're currently developing already but you're right. By then, we'll have a significant contribution from our new, relatively new Cold Lake SAGD project, plus it should be noted that we're drilling a lot of stratigraphic test wells this year, more than ever before. And we expect with that large land position we have, now about 300 -- over 300 sections of land, these stratigraphic test wells are going to identify additional development opportunities for the future.

And maybe this question is for Jim. I know you've been quite clear about the -- and very constructive on the potential for these WCS, WTI differentials to narrow over time in rails, I guess. So like what would you share, maybe what do you see sort of going on in the overall market that would lead you to consider -- lead you to continue to lead that with or without Keystone XL?

Gordon, we've been quite clear on our views on that. There is a large demand for Western Canadian Select in the U.S. It's the largest transportation network in the world of 18 million barrels a day of refining capacity. It's largely gone through over the last 15 years a significant conversion to heavy and sour crudes. And there, today, a lot of those crudes are being purchased off of water at near WTI prices in order to fulfill those needs and the Canadian market is setting here. And as soon as the transportation gets unlocked, which I believe that that's going to happen quicker than people think regardless of Keystone XL because of the fact that you can get down there on rail, and that was clearly demonstrated, the manufacturing industry has built the capacity to do that, it unlocked the Bakken. And it's in the process of unlocking Western Canadian Select. So there's a lot of pie to be carved up between the various entities that participate in those efforts.

And just sort of a little more background question. I presume that when oil gets into the U.S. network, if you get it across the border via rail or something, it doesn't necessarily have to be transported all the way down to the gulf. I presume there's lots of delivery points within that even the pipeline network, where it's fairly fungible and you just have to get it to some place where it can be delivered and then moved by some other means. Does that happen as well in that market?

Gord, that is a fair assessment. And to further expand on that just a bit, you heard various companies announce barge deals and ties into pipeline or rail at different take points. So all of those are possibilities and, in fact, realities as people are announcing various ways you can connect in. I think you'll see more of that to come with Cushing that should get, I believe, will get cleared this year. That's going to open up new ways for Western Canadian Select to get into different points as well.

[Operator Instructions] The next question is from Cristina Lopez from Macquarie.

Just a couple of quick questions. One has to do with transportation cost, obviously, up on the quarter and up significantly from last year. Trucking being a good portion of that. Do you expect this to be the new level for your transport cost as you start railing more volumes as well and having to move more through long-haul -- the haul trucking to get to the railing loading facilities?

Cristina, it's Derek. Directionally, that's correct. The single biggest contributor to the increase in trans ex is, as you identified, the cost to truck volumes out of Seal to delivery points. And as Seal volumes increase, the trucking cost goes up with it. In the fourth quarter, that was exacerbated a little bit by the fact that we're doing some rail deliveries. The trucking distance to rail loading points is about the same as to pipe loading points, with the incremental cost that unloading trucks at a rail delivery point is a little bit slower, so you're paying standby fees and those kinds of things. So that -- but directionally you're correct, it likely is to increase as we continue to increase volumes at Seal.

And so because you're moving that rail volumes from 21% in Q4 to 40% at the end of Q1, we actually should directionally even see that go up then through the year?

That's correct. Although I think net-net, obviously, when you're moving to rail, were accessing a higher market. So there's a net contribution to us, but the trans ex component does go up.

And so that brings me to my next question on what the breakeven differential on a dollar basis would be, where you start to see a benefit from rail versus the -- versus being 100% dedicated to pipe?

All things being equal, it kind of breaks even around a $15 differential.

So the big assumption there is all things being equal, which in the last 12 months, is been outside of our norm.

When I say that, Cristina, I mean, blending cost, what the cost of condensate, what is the WCS environment, all of those kind of things. But in a current kind of pricing environment, a $15 WCS differential, it means you're neutral between pipe and rail.

And that includes that increased transportation expenditure in there?

That's correct.

Okay. And with this year's 2013 capital program, obviously, over the past 3 years, you've had this big dip in Q4 spending. Is that, again, expected to occur in 2013 or more of a level loaded program by quarter?

Cristina, it's Marty. Probably a little more level loaded by quarter this year. We have tended in the past we want to spend the exact amount that we put in it. Just execute it efficiently as we can and that has led to us spending our capital allocation a little early this year because of some of the startup and blueprint work that we did at Peace River, we're probably level loading more than past years. But it's still likely we'll be tapering off near the end a little bit.

And then my last question actually is looking a little further out into 2014 again with CapEx spending, a good jump from 2012 expenditures to 2013. As you then accelerate or move forward with more thermal projects in 2014, do you expect a similar magnitude increase in spending or relatively flat to 2013? Obviously, understanding it's still early and any sort of budgetary process?

Yes, Cristina, you're right, it is early and we haven't released our 2014 numbers yet. But just directionally, I would expect to see the thermal come down. We don't have those specific components that we have this year. So the remainder, again, all things being equal, differentials improving, cash flow getting to where it needs to be as a result that. We should -- we have -- we certainly have the projects to continue at about the same baseload that we have.

Okay. I'm going to ask one last question and then I'll hang up and let somebody else ask some questions. But with respect to a world where heavy oil differentials begin to narrow, or we see a structural narrowing of heavy oil differentials, order of priority, what do you do with incremental cash flow? Do you look at increasing the dividend, do you look at paying down debt acquisitions, increasing CapEx expenditures? Where would you see the priority as it stands today?

Well, we'll be consistent with what we've done in the past there. We'll have a little bit more capital need as the company grows. If our cash flow grows, we would expect to pass along some of that in dividend. That's been the company's history, and that would be our full intentions.

And, Mr. Ector, we have no other questions registered at this time. Please go ahead, sir.

Okay, operator. Well, thank you very much, and thanks, everyone, for participating in this morning's conference call. That does conclude the call. Thank you for your participation.