Baytex Energy Corp (BTE) 2013 Q3 法說會逐字稿

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, Dave, and good morning, ladies and gentlemen. 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, 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, Bryan, and good morning, everyone. We are 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 a 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 CAD199.3 million, or CAD1.61 per basic share.

Our results in the quarter were positively impacted by a one-time recovery of cash income taxes of CAD6.6 million, which is a partial recovery of 2012 US income tax paid. Our operating net back during the third quarter of CAD42.14 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 CAD757 million, which represents a funds to op -- a debt-to-funds from operations ratio of 1.3 times, based on FFO for the past 12 months. At the end of the third quarter we had CAD605 million in undrawn credit facilities and no long-term debt maturities until 2021.

In the first nine months of 2013 our capital spending has progressed as planned in our key development areas. Spending for exploration and development activities totaled CAD122 million during the third quarter, with year-to-date spending of CAD466 million. About two thirds of our capital spending to date has been directed towards drilling and completion activities, with one-third being equipment and construction related, which does include our thermal expenditures.

We are very pleased with our operating results in all three of our key areas through the first nine months of this year. Production from our Peace River area properties averaged approximately 26,000 barrels per day in the third quarter, an increase of 13% over the second quarter. We drilled seven multilateral wells at Peace River during the third quarter, bringing the year-to-date drilling to 30 wells.

From this year's program we have achieved an average 30 day peak production rate of approximately 700 barrels per day. We plan to drill approximately 10 multilateral wells in the remainder of 2013.

At Lloydminster, production averaged approximately 19,000 barrels per day during the third quarter. We drilled 38 net wells, bringing year-to-date drilling to 101 net wells with a 98% success rate. We plan to drill approximately 15 net wells in the Lloydminster area in the remainder of 2013.

In our Bakken/Three Forks development in North Dakota, production averaged 3,400 barrels per day, which is up 10% from the second quarter. During the third quarter, we drilled three gross, or 1.3 net horizontal wells, and fracture stimulated four gross, or 2.3 net wells. Six operated wells on 1,280-acre spacing established an average 30 day peak production rate of approximately 470 barrels per day. We also continued to progress our thermal development during the third quarter.

In the Cliffdale area, successful operations continued at our 10-well CSS module, with production averaging approximately 600 barrels per day. Facility construction at our new 15-well module is proceeding on schedule, with commissioning activities now under way and production facilities start-up planned for the fourth quarter.

Drilling operations are nearing completion, and we expect to commence cold production from the first 5 of the 15 wells during the quarter. First cycle steaming is expected to occur in the first half of 2014.

At Kerrobert, we drilled one SAGD well pair which commenced production in September, and established an average 30 day production rate of approximately 900 barrels per day.

And finally, at our Gemini pilot project, we drilled one SAGD well pair and continued construction of the facilities. We remain on track for late steaming this year or early in 2014.

As we continue -- as we look to maintain our positive operating momentum into 2014, we plan to increase our original 2013 exploration and development budget of CAD520 million by approximately 5%. The incremental capital will be directed toward our Peace River, Lloydminster and North Dakota operating regions, with production additions occurring in the first quarter of 2014.

We are in the process of setting our 2014 capital budget, the details of which are expected to be released on December 13 following the approval of our Board of Directors.

I want to spend a few minutes now on our heavy oil pricing and our marketing efforts. During the third quarter, 89% of our production was weighted towards crude oil. We have a particular emphasis on heavy oil, which represented 75% of our production in the quarter.

The benchmark price of our heavy oil in Canada is Western Canadian Select, or WCS, which trades at a discount to WTI. This discount during the third quarter averaged 16.5%, as compared to 20% in a second quarter. So, when you combine a stronger WTI pricing environment with a narrowing of heavy oil differentials, our realized oil and NGL price of [$81] per barrel increased 22% from the second quarter.

As part of our marketing strategy, we are focused on opportunities to mitigate the volatility in WCS price differentials by transporting crude oil to higher-value markets by rail. During the third quarter, approximately 20,000 barrels per day of our heavy oil volumes were delivered to market by rail, as compared to 7,500 barrels per day for the full-year 2012 and 15,000 barrels per day for the first half of 2013.

During the fourth quarter, we expect to deliver approximately 23,000 to 24,000 barrels per day of our heavy oil volumes by rail, which represents just over half of our total heavy oil production.

For the fourth quarter, we are seeing seasonal weakness in oil differentials for all grades of crude oil in Canada, synthetic, light, sour and heavy. This is due to a combination of planned and unplanned refining outages, pipeline maintenance and increased supplies.

The WCS differential for the fourth quarter is expected to average approximately 30%. Importantly for Baytex, as the WCS differential widens, our rail uplift, or margin benefit, increases.

I would like to remind everyone that there are a number positive catalyst on the horizon that should contribute to sustained lower differentials and stronger heavy oil pricing going forward. These include ongoing refinery conversions, continued increases in crude by rail volumes and a number of pipeline capacity improvement and expansion projects.

We have also taken advantage of the recent strength in WTI prices to add to our hedge portfolio. For the fourth quarter of 2013 we have entered into hedges on approximately 67% of our WTI exposure at a weighted average price of almost [$100] per barrel. And for 2014, approximate 28% of our WTI exposure is now hedged at a weighted average price of [$98] per barrel.

So in summary, our third-quarter results were highlighted by the highest quarterly production rate and funds from operations in Company history. This quarter demonstrates the cash generating capacity of the Company in a strong heavy oil pricing environment.

Our operations at Peace River, Lloydminster and North Dakota are right on track, and we are very pleased for the second time this year to be tightening our full-year production guidance range. Our marketing expertise as demonstrated by our early use of rail, and the continued growth in real volumes, has contributed positively to our bottom line as we continue to have a strong balance sheet and ample liquidity to allow us to execute our growth and income model.

So with that, I will conclude my formal remarks and ask the operator to please call for questions at this time.

(Operator Instructions)

The first question is from Mark Friesen with RBC Capital Markets. Your line is now open. Please go ahead.

Things, good morning, Jim, just a few questions. I know you're going to provide guidance for 2014 in December, but just in the context of what you were saying about the increase to the CapEx level this year, I can kind of imagine that might be in response to what happened earlier this year. Seeing a very tight CapEx budget that led to the pullback in Q1-- kind of see this as trying to continue momentum and avoid that type of situation going into 2014. 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 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 get us momentum into next year as well. So it is 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 gone. Where should we think of this going? Are we going to see these volumes continue to increase? What type of volumes can we can expect?

Well, we laid out where we are today and what we expect in the fourth quarter. As we move into 2014, for starters, there are more opportunities than there have been. Additional sites are being -- these small, relatively -- the non-unit train sites, they are relatively smaller, 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 are 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 pad two -- Flanagan South 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 should it come to where we were this summer again, which we do expect we will get back to where differentials are in the sub-20 range, there will be less of an arbitrage open for rail to continue to expand and us to want to expand further. 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 what it has been, and not look for any changes necessarily in terms of commitment -- larger commitment, volumes or anything of that nature? Keep it flexible?

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, and 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 --

As we kind of stated before, as kind of some examples, and it depends on what our mix is. And you can see it is changing as our volumes are changing, but historically we've said in the CAD20 range of a differential, we see an uplift of CAD2 to CAD4 a barrel, or something like that, depending on the contract. And in the CAD30 differential range, it can be as high as CAD10.

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 are 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 rates of returns; our performance has been solid there. You will notice our well IPs were a little above the curve this quarter. So we are quite pleased with what is occurring there, and it is a matter of just making sure we do the proper capital allocation with it.

Okay. Thanks, Jim. That's it for me.

Thank you, Mark.

The next question is from Dirk Lever with AltaCorp Capital. Your line is open. Please go ahead.

Thanks very much, and congratulations, Jim, on a very good quarter. 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? Would that be another way we could look at it?

Dirk, this is Brian. I will address that one for you. 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 are 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%, 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, it's traded at a bit of a premium. So we would benefit from that.

Secondly, as we rail more of our heavy crude, we are purchasing less condensate. We are railing raw heavy barrels, we are not purchasing as much condensate, and we benefit from that as well. And in 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, we would benefit from that as well, which Jim alluded to.

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 for, because you beat the Street by a wide margin. There's got to be that number.

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

Dirk, it is pretty tough to pin it down to that single-digit point like that for the simple reason 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 refineries 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 are bidding off of somebody who can't, basically, get a WCS barrel another way and is bidding it off of a Venezuela and heavy, for example, or something like that.

There's all of those various factors that are in there, and it has been creeping up as a result of these things all coming into play together. But it is 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 can be very high, but we'd still have a high 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.

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

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

Appreciate, and as I said, congratulations on a great quarter. Thank you very much.

Thank you. The next question is from Kyle Preston with National Bank Financial. Please go ahead.

Thanks. Good morning, Jim, and congratulations on a good quarter there. Just to take this whole topic a little bit further on rail pricing, I'm just wondering if you could talk about how much flexibility you have on this rail? I understand you do have some committed volumes there, but when -- in the quarter when we see differentials narrow or widen, how much flexibility do you have to change it around? Last quarter in particular 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 is relatively minor; it is less than 10%. But our deals are typically not much more than six months at this stage. When -- Kyle, when you go back when we first began this effort, you basically had to underwrite someone who had built a loading facility nearby where you were at, and you had to make maybe a year or 18 months commitment. Today, because there are more sites and some of the sites are essentially maybe paid for at this stage, our term contracts are significantly shorter than that.

But it is also getting to the point where we are moving more on volume, so it is kind of hard to do it on a month-to-month basis, and we need to make a commitment of a quarter. For a quarter, we are kind of -- it is getting to be kind of the minimum, and a year is about as long as any of these are, with maybe a midpoint of six months. And a little bit on spot.

What we haven't had to do, and we think it is available because the number of sites are increased, we haven't been in the position where we've said -- well, we would like to get 3,000 more barrels a day on rail tomorrow. But we think we can 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 closed. It got close to it in the third quarter, and that means pipe is available and storage levels are going down, and all the factors that cause a differential to come in. And we watch all those parameters.

Having said that, I think rail is here to stay for certain volumes of certain types of crudes, because it is just not about the obvious arbitrage that looks apparent from the simple calculations. When you counter 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 will participate in rail at some level almost all the time, I would think. But it is hard to predict that forever, but in the foreseeable future that's what I'd say.

Okay, so for the time being, though, we should assume that you will 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, thanks. Just one last question here -- moving back to this capital budget for next year, I know we are getting some details here in a couple months or several weeks here, but can you give us directionally where you expect that to go? The capital that you are adding in 2013, is that strictly a reallocation from 2014 to 2013, 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, the 2014, although we haven't set the number yet, will be directionally lower than our capital budget for what it was in 2013, Kyle. And we will have that out here in just a few weeks.

Okay. Great. Thanks, and congratulations again on the good quarter.

Thank you.

Thank you. The next question is from Gordon Tait with BMO Capital Markets. Please go ahead.

Good morning. A couple questions not related to rails. I think we've got that under control. The question I have is on your Seal, your horizontal cold wells. It looks like the production rates, the IP rates and type curves can 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 look pretty good, the way they did in 2011. I'm wondering if next year, based on your development plans, would we expect them to look more like 2012 versus the way they are this year?

Gordon, it is Marty here. We did have good performance in 2013, but really we are not changing our expected profiles for the future drilling. They aren't very much different than in past years. The reality is, there's a number of different factors that we can apply that can change initial rates. Really, we can 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.

Our expected ultimate recoveries will be 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 are not changing our expected declines for any of these wells.

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

It is 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 three or four 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 is essentially exactly the same as what we were expecting from the previous 10-well module. It is that same profile -- increasing over three or four years, then flat, and then declining after some period.

We are commissioning our production facilities right now. We should start cold production with the first five wells immediately, and then we will 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, notice you don't have as much production, or a lot of production hedged into the second half of next year. I'm wondering -- just your take on the heavy/light spreads for next year. [Coal] production's hitting the market now, but the BP Whiting is supposed to be -- I think they are starting their cokers now, expected to be ramping up the first half of next year, so how do you see those spreads looking for the second half of next year, by middle of next year?

Gordon, this is Jim. The forward curve on WTI is backward-dated 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.

In terms of the WCS differential, it is posted out there, I think, Cal 14 has varied between numbers of 20% to 25% right now, and it has gone up and down. We've had a little bit of widening in the Cal 14 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.

If you take a look at the Northern Tier and Sinclair are down, both had fires; BP had its coker delay announced here, their central vacuum unit was down of their main crude facility. And then the worst one was just recently -- it looks like Citco at Lamont is going to be out. That's 175,000 barrels a day, for four to five 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 are at right now, and date this two 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 if it is light or heavy, we would be in a very, very high-differential market right now.

So those things have significantly mitigated in what I believe brought this window down from what used to blow out 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 is partially running it while they are doing an expansion, you do tend to have some upsets and they will get those things settled out. And then in addition with the pipe expansions that have been announced, as I previously referenced, and Flanagan coming on midyear, it is going to be a very different year. And what is apparent to me on the more positive side then negative things happening, which is what's occurred in the past.

I don't -- 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 I think it is reflecting what could be a more positive 2014 and beyond.

That seems to make sense that some of these issues are resolved the first half of the year -- Q1 then it could be a different situation looking in a second half of next year.

You bet, Gordon, thank you.

Thank you. 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, 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.