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Baytex Energy Corp. (NYSE:BTE)

Q3 2012 Earnings Call

November 13, 2012 11:00 am ET

Executives

Brian G. Ector – Vice President, Investor Relations

James L. Bowzer – President and Chief Executive Officer

Marty L. Proctor – Chief Operating Officer

Analysts

Philip Skolnick – Canaccord Genuity

Gordon Tait – BMO Capital Markets

Robert Bellinski – Morningstar, Inc.

Mark Friesen – RBC Capital Markets

Jason Frew – Credit Suisse (Canada)

Operator

Good morning ladies and gentlemen. Welcome to the Baytex Energy Corp. Third 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, Mr. Ector.

Brian G. Ector

Thank you, operator, and good morning, everyone. Welcome to our third quarter conference call. With me here on the call today are Jim Bowzer, our President and Chief Executive Officer; and Marty Proctor, our Chief Operating Officer. Derek Aylesworth, our Chief Financial Officer would normally be with us today, but he is traveling to an Investor Conference.

While listening, please keep in mind that some of our remarks will contain forward-looking statements within the meaning of applicable securities laws. I would refer all listeners to our advisory regarding forward-looking statements contained in today’s press release.

I would now like to turn the call over to Jim.

James L. Bowzer

Thanks, Brian, and good morning, everyone. Let me provide you with a few highlights from the third quarter. Baytex generated record quarterly production of 54,381 BOEs per day during the quarter and we remain on track to meet our full-year guidance of 53,500 BOEs per day to 54,500 BOEs per day. At the midpoint of our guidance range, this would equates to approximate 8% year-over-year growth, production during the quarter was weighted 88% to crude oil and natural gas liquids and about 12% natural gas.

Our funds from operations totaled a $139 million, or $1.15 per basic share, bringing our funds from operations for the first nine months of 2012 to $405 million, or $3.39 per share. Our payout ratio net of our dividend reinvestment plan remained conservative at 38%, which is consistent with the 39% payout ratio realized during the first nine months of 2012.

Our balance sheet remains in excellent shape as well with debt to funds from operations ratio based on funds from operations for the training 12 months of 0.8 times. And if you adjust for a previously announced Cold Lake acquisition, this leaves us with almost $600 million of available undrawn credit facilities today.

During the third quarter, we spend about a $113 million on exploration and development activities, which is on track with our full year plan for expenditures of approximately $400 million. During the third quarter, we drilled 48 net wells with a 98% success rate.

I’m going to touch just briefly on a few of our core areas beginning with our operations in Peace River. Production from our Peace River properties averaged approximately 21,350 barrels per day during the quarter that’s up 20% year-over-year basis. Third quarter was once again highlighted by a successful development program when we drilled nine cold multilateral wells with a total of 116 laterals there.

During the quarter, we had a total of 10 wells, including one well drilled during the second quarter, which established an average 30-day peak production rate of 410 barrels per day. During the rest of the year, we will have about six more horizontal wells drill in Peace River for the remainder of the year.

Moving to Cliffdale in the Peace River area, successful operations continued at our 10-well commercial cyclic steam stimulation or CCS module, with production they’re averaging about 420 barrels per day and that consistent with our design plan.

During the third quarter, five wells received steam and three wells commenced post-steam flowback operations. Our first and second-cycle steam injection volumes were very encouraging here. We’ve exceeded the first-cycle injection performance demonstrated by the pilot well.

To-date, the Cliffdale project has demonstrated a cumulative steam-oil-ratio of approximately 2.0. We plan to initiate development of a new 15-well module there in Q1 of 2013. As you recall, we had originally planned to commence that construction in December this year, we were just now pushing that out as we wait final regulatory approval. Now we continue to add to our land position here in Peace River. We’ve recently added about 29 sections of perspective oil sands leases and in aggregate we have about a 306 sections of oil sands leases in this region.

I’m going to talk about our next area, which is Lloydminster. Our production from the properties in Lloyd averaged approximately 19,200 barrels a day in the third quarter, which is essentially flat on a year-over-year basis there. Third quarter drilling included 9 horizontal wells, 20 vertical wells, and we expect to drill about 7 more horizontals and one more vertical for the remainder of 2012. Our Lloyd heavy oil projects generate consistent repeatable return here with horizontal wells typically producing a 30-day peak rate of about 70 to 80 barrels a day, verticals typically producing 30-day peak rates of 30 to 40 barrels a day.

I’d like also mention here subsequent to the end of the third quarter, we acquired a 100% working interest in 46 sections of undeveloped oil sands leases in the Cold Lake area for about a $120 million. The lands as you well know are proximal to our existing Cold Lake heavy oil assets and are prospective for both cold and thermal development.

This land acquisition does add in a steam, in a crew steam-assisted gravity drainage or SAGD project to our asset portfolio, and we are now moving forward with the design plans for the pilot of the SAGD project. Assuming now pilot is successful, we anticipate the full commercial project of a 5,000 barrels of oil per day production rate with, first production would commence in 2016.

Lastly, I want to briefly mention our Bakken and Three Forks development in North Dakota. Baytex drilled 2.7 net wells during the quarter and these are all two-mile long, 1,280-acre spacing wells. The seven Baytex operated wells established a 30-day peak rate of 445 BOEs per day. We plan to drill about 1.5 wells net for the remainder of 2012, and as you may know, we have a two rig program in the area.

I’d like to talk a little bit about our hedge portfolio and our use of rail when it comes to marketing as it did affect the quarter. We continue to hedge our exposure to commodity prices and foreign exchange rates. For Q4 2012, we’ve established forward contracts on 46% of our WTI exposure, 40% of our heavy diff exposure, and 46% of our natural gas exposure.

We’ve also got about 31% exposure to currency movements between the Canadian and U.S. dollar covered. We’ve also began securing hedging contracts for 2013 exposures for the first half of 2013, we’ve established forward contracts on approximately 24% of our WTI exposure and 38% of our heavy oil differential exposure. And for the second half of 2013, we are at about 16% of our WTI exposure for forward contract and about 25% of our heavy oil differential is covered.

As part of this hedging program, we also continue to mitigate exposure to WCS price differential by transporting crude to higher oil value market by rail. During the quarter, we delivered approximately 25% of our heavy oil volumes by rail. And by the end of 2012, we expect that number to approach 30% of our heavy volumes by rail and we will as always continue to explore opportunities for additional rail delivery into 2013 and beyond.

Let me summarize the quarter by pointing out just a couple of saying, it was very obvious that we had a very strong quarter operationally. Our capital execution was on target. The production volumes were once again consistent with our guidance and we continue to have high quality, low risk bold-on acreage to our portfolio. I wanted to mention, I want to make here is that we will provide production and capital budget guidance for 2013 in early December, following the approval of our 2013 development plan by our Board of Directors.

That concludes my comments and I’ll turn it back over to Brian here for a moment.

Brian G. Ector

Okay. Thank you, Jim for little comment. At this time operator, we would like to open the line for any questions.

Question-and-Answer Session

Operator

(Operator Instructions) We have a question from Phil Skolnick from Canaccord Genuity. Please go ahead.

Philip Skolnick – Canaccord Genuity

Hi, yes. Thanks, good morning. Just a quick question, when think about 2013, what are some of the moving parts that we should be thinking about from production standpoint, CapEx standpoint? And what do you need to spend the key production flat as well and what they decline rate to think about?

James L. Bowzer

Phil, this is Jim. Well, our underlying decline is in the high 20s. And our current capital budget we have this year is gives you approximal rate to the growth that we provided in the past. I don’t want to jump the gun on a board approval for our production forecast and capital that we’re going to spend in 2013 and we’re just finalizing these plans over the next month here. But that gives you a bit of guidance there on the amount of money that is taken to provide the stable production that we’ve had during the year, this year and actually last year as well.

Philip Skolnick – Canaccord Genuity

Okay, thanks

Operator

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

Gordon Tait – BMO Capital Markets

Good morning. I was just going back in a Cliffdale. Do you know in which cycle that you would expect production rates to peak when you’re doing these different cycle injections?

James L. Bowzer

Yeah, Gordon it probably takes about four or five cycles before you start getting that peak production from each of the individual wells. Is that what you’re referring too?

Gordon Tait – BMO Capital Markets

Yeah that’s right.

James L. Bowzer

At the beginning cycles are relatively small. It’s necessary to create voidage in the reservoir to be able to get a higher amount of steam volume in. And you get to the point after four or five to where the steam volume become sufficient to kind of reach that that maximum level of production that will occur again over then several cycles going forward on an individual well basis.

Gordon Tait – BMO Capital Markets

If you can hold that for a few cycles before you start to see diminishing returns?

James L. Bowzer

Yeah. The combination of all of the wells building up cycle-by-cycle, builds to about four to five years to the peak rate of about 2,000 barrels a day for this entire project. But you would ask the question specifically about how long does it take for a single well? So I want to also clarify that the total project there as well.

Gordon Tait – BMO Capital Markets

Al right, thanks. And then a regulatory approvals taking longer now, is it getting more difficult to get that paperwork through?

James L. Bowzer

I don’t know that I’ve say it’s taking longer. What you would expect for the approval range for a small project they can run as little as a year to year and a half and a little bit bigger one anywhere from year and a half to two years, and that’s pretty typical with one and a half years being about the midpoint depending on the complexities and specifics that go with any specific project.

So we’re right there with this next module at Cliffdale and don’t have any issues with the approvals, but coming up on the holiday season here and expect that we could possibly still get this year, but it’s like it will be sometime right after the first year now we believe.

Gordon Tait – BMO Capital Markets

Okay, thanks.

James L. Bowzer

Thanks Gordon.

Operator

Thank you. Our next question is from Robert Bellinski from Morningstar, Inc. Please go ahead.

Robert Bellinski – Morningstar, Inc.

Good morning guys. The release mentions that depletion, depreciation increase due to higher estimates of future development costs, I was just wondering, can you provide some additional detail on how you see those costs increasing?

Marty L. Proctor

You are referring to DD&A, are you?

Robert Bellinski – Morningstar, Inc.

Right.

Brian G. Ector

Robert, it’s Brian here. The provision in the third quarter was about $14 of barrel, for depletion and depreciation costs a year ago $12.56. So is increase marginally just reflecting of higher costs and development costs I think in the basin of go forward, but we wouldn’t view that as a material change.

Robert Bellinski – Morningstar, Inc.

So it’s just kind of general cost inflation?

Brian G. Ector

Yeah, I suspect though.

Robert Bellinski – Morningstar, Inc.

Okay. Is that in line with what you are seeing for production in operating expense for the higher labor and production costs?

Marty L. Proctor

Robert, this is Marty Proctor, I think that’s probably accurate. We have seen some labor increase this year, probably 3% to 4% over 2011, and we anticipate a similar increase going forward into 2013, so yes, I think the answer is probably is in line with the D&D.

Robert Bellinski – Morningstar, Inc.

Okay, that’s all I got. Thanks, guys.

Operator

Thank you. Our next question is from Mark Friesen from RBC Capital Markets. Please go ahead.

Mark Friesen – RBC Capital Markets

Thank you. Good morning, gentlemen. Just a quick question on the E&D CapEx, just seem to me like that came in a little bit higher than what I was expecting, I think maybe what the few people are expecting, is that just a timing issue, or maybe going forward some of the spending that I might have been looking for in Q4, or is there a chance that, I know you’d reiterated the $400 million of guidance for 2012, but is there a chance that that could be maybe pushed a little bit?

Marty L. Proctor

That’s a good question Mark. This is Marty again, we placed a real high priority on maintain our capital discipline. We execute our capital program as efficiently as we can and historically that’s led to a tapering off at the end of the year as our programs are completed. So yes, we typically do spend more during the first three quarters of the year with a more modest fourth quarter program. I think last year program in fact, was very similar to this with respect to the spending profile.

Mark Friesen – RBC Capital Markets

Okay, great. Yeah, that’s very helpful. And just at COV 6 horizontal that you talk about drilling in the fourth quarter, how many laterals would be associated with those?

Marty L. Proctor

It’s going to be in the order of, we’re typically drilling 12 to 13 laterals per horizontal now, so it will be in the order of 70 to 80.

Mark Friesen – RBC Capital Markets

Okay, great. That’s it for me. Thank you.

Marty L. Proctor

Okay, thank you, Mark.

Operator

Thank you. (Operator Instructions) The next question is from Jason Frew from Credit Suisse. Please go ahead.

Jason Frew – Credit Suisse (Canada)

Hi, there. I was just wondering if you could talk a bit more about the proportion of your crude being railed, just how far that program could go perhaps into next year?

James L. Bowzer

Yeah, this is Jim, Jason. It is very based on what the arbitrates is, we expect differentials to tighten from the levels that they’re at right now to give you an example. We did coal back that the amount of rail that we had in the third quarter as the arbitrates versus rail versus differential, it came unfavorable for rail or we could get a higher net back on moving it on tight.

So during this time of the year, we’d like to get to the point to where we can get 40% when differentials are plus 20% on rail. We’re approaching the ability to do that right now. So I think we’re about where we want to be. We’ll continue to seek out additional contracts. It is the very dynamic and evolving markets. There are more and more players getting into it and more and more capacity becoming available as the pipelines continue to be stretched out here for the next couple of years and people understand this market better than they have in the past.

Jason Frew – Credit Suisse (Canada)

Okay, thanks.

James L. Bowzer

Certainly.

Operator

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

Brian G. Ector

Okay, thank you, operator. Before we leave, many of you have had the opportunity with Jim, since he joined Baytex here in September and the question always comes up are on heavy differentials and it’s been very topical of weight for us as well. So we’d be wrap up, I’d like to just ask Jim to provide some closing comments on heavy differentials and your thoughts.

James L. Bowzer

Yeah, I think this is a good example of what we’ve been talking about in the previous question kind of led into this. Baytex has been a forefront of maximizing our returns to our shareholders and maximizing the benefit of price realizations on our crude through the use of rail as transportation has become a major topic over the past couple of years.

Rail is really stepped up to fill that gap. You’re typically seeing right now differentials almost to the $30 WTI compared to WCS. We fully expected the differential to be higher this time a year as it is the refining turnaround season. But in particular, we’ve had a couple of issues happened here with the pipeline interruption that happened as well as an extension of a turnaround at the couple the refineries and one of the expansions that was scheduled to come on with a bit late.

The combination of those things did have a little bit bigger effect on the differential this quarter. But as those things get corrected as we move into the first Q and second Q of 2013, we fully expect the differentials to close back down to the levels that represent what should be the true value of the crude, which is the transportation it takes to get into market, as well as the discount and quality of any crude one has relative to the value of other crudes being processed in the refining network across North America, which has greatly shifted to a preference to heavy crude.

So not really anything happening here out of the normal, the exception of a little bit of exaggeration of the differential as a result of the few upsets that occurred during this time of the year this time. Brian, thank you.

Brian G. Ector

That’s great, Jim. All right, as there are no further questions, thank you, operator, and that concludes this morning’s conference call, and thank you all for your participation.

Operator

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

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