Baytex Energy Corp (BTE) 2012 Q3 法說會逐字稿

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.

Thank you operator, and good morning everyone. Welcome to our third-quarter conference call. With me here on the call today are James 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.

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 mid-point of our guidance range, this would equate 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 CAD139 million, or CAD1.15 per basic share, bringing our funds from operations for the first nine months of 2012 to CAD405 million, or CAD3.39 per share. Our payout ratio net of our dividend re-investment 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 an excellent shape as well, with debt to funds from operations ratio based on funds from operations for the trailing 12 months of 0.8 times. If you adjust for our previously announced Cold Lake acquisition, this leaves us with almost CAD600 million of available undrawn credit facilities today. During the third quarter, we spent about CAD113 million on exploration and development activities, which is on track with our full-year plan for expenditures of approximately CAD400 million. During the third quarter we drilled 48 net wells with a 98% success rate.

If you'll let me, 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. The third quarter was once again highlighted by a successful development program, where we drilled nine cold multi-laterals 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 horizontals we'll 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 there averaging about 420 barrels per day; and that's consistent with our design plans. During the third quarter five wells received steam, and three wells commenced post-steam flow-back operations. Our first- and second-cycle steam injection volumes were very encouraging here, and we've exceeded the first cycle injection performance demonstrated by the original pilot well. To date, Cliffdale project has demonstrated a cumulative steam-oil ratio of approximately 2. We plan to initiate the development of the new 15-well module there in Q1 of 2013. As you will recall, we had originally planned to commence that construction in December this year. We are just now pushing that out as we wait final regulatory approval. We continue to add to our land position here in Peace River. We've recently added about 29 sections of prospective oil sand leases, and in aggregate we have about 306 sections of oil sand leases in this region.

I'm going to talk about our next area, which is in more 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 nine horizontal wells, 20 vertical wells, and we expect to drill about seven more horizontals and one more vertical for the remainder of 2012. Our Lloyd heavy oil projects generate consistent [repredable] returns 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 to also mention here subsequent to the end of the third quarter, we acquired 100% working interest in 46 sections of undeveloped oil sand leases in the Cold Lake area for about CAD120 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 an approved 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 that pilot is successful, we anticipate the full commercial project of 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 at 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 US dollar covered. We've also begun 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. For the second half of 2013, we are at about 16% of our WTI exposure for forward contracts, 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 differentials by transporting crude to higher-oil-value markets 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. We will, as always, continue to explore opportunities for additional rail deliveries into 2013 and beyond.

Let me summarize the quarter by pointing out just a couple of things. 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. We continue to add high-quality, low-risk, bolt-on acreage to our portfolio. One other 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 will turn it back over to Brian for a moment.

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

Thank you. We will now take questions from the telephone lines.

(Operator Instructions)

Phil Skolnik, Canaccord Genuity.

Thanks, good morning. Just a quick question. When you 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 to keep production flat as well, and with the base decline rate to think about?

Phil, this is Jim. Well, our underlying decline is in the high 20%s, And our current capital budget we have this year is -- gives you a proximal rate to the growth that we provided in the past. I don't want to jump the gun on our 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 it's taken to provide the stable production that we've had during the year -- this year, and actually last year as well.

Okay, thanks.

Gordon Tait, BMO Capital Markets.

Good morning. I was just wondering -- question at Cliffdale. Do you know in which cycle that you would expect production rates to peak when you're doing these different cycle injections?

Gordon, it probably takes about four or five cycles before you start getting that peak production from each of the individual wells, if that's what you are referring to.

Yes, that's right.

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. You get to the point after four or five to where the steam volume becomes sufficient to kind of reach that maximum level of production that will occur, again, over then several cycles going forward on an individual well basis.

Are you going to hold that for a few cycles before you start to see diminishing returns?

Yes. 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. You had asked the question specifically about how long does it take for a single well, so I wanted to also clarify that the total project there as well.

All right, thanks. And then, are regulatory approvals taking longer now? Is it getting more difficult to get paperwork through?

I don't know that I'd say it's taking longer. We are right in the -- what you would expect for the approval range. They can -- for a smaller project, they can run as little as 1 to 1.5 years, and a little bit bigger one anywhere from 1.5 to 2 years. That's pretty typical, with 1.5 years being about the mid-point, depending on the complexities and specifics that go with any specific project. 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 it this year. It's likely it will be sometime right after the first of the year now, we believe.

Okay, thanks.

Thanks, Gordon.

Robert Bellinski, Morningstar.

Good morning, guys. The release mentions that depletion and depreciation increased 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?

You're referring to DD&A, are you?

Right.

Robert, it's Brian here. The provision in the third quarter was about CAD14, just over CAD14 a barrel for depletion and depreciation costs. A year ago, CAD12.56. It's increased marginally, just reflecting of higher costs and development costs, I think, in the basin as a whole. But, we wouldn't view that as a material change.

So just kind of general cost inflation?

Yes, I suspect so.

Is that in line with what you're seeing for production and operating expense for the higher labor and production costs?

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. We anticipate a similar increase going forward into 2013. Yes, I think the answer is it probably is in line with that D&D.

Okay. That's all I got. Thanks guys.

Mark Friesen, RBC Capital Markets.

Thank you. Good morning, gentlemen. Just a quick question on the E&D CapEx. It just seemed to me like that came in a little bit higher than what I was expecting, and I think, maybe what a few people were expecting. Is that just a timing issue, maybe pulling forward some of the spending that I might have been looking for in Q4, or is there a chance that -- I know you reiterated the CAD400 million of guidance for 2012, but is there a chance that could be maybe pushed a little bit?

That's a good question, Mark. This is Marty, again. We place a real high priority on maintaining our capital discipline. We execute our capital program as efficiently as we can, and historically that's led to a tapering off near the end of the year as our programs are completed. 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's program, in fact, was very similar to this with respect to the spending profile.

Okay, great. Yes, that's very helpful. At Seal, the six horizontals that you talk about drilling in the fourth quarter, how many laterals would be associated with those?

It's going to be at the order -- we're typically drilling 12 to 13 laterals per horizontal now, so it'll be of the order of 70 to 80.

Okay, great. That's it for me, thank you.

Thank you, Mark.

Thank you.

(Operator Instructions)

Jason Frew, Credit Suisse.

I'm 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?

Yes, this is Jim, Jason. It varies based on what the arbitrage is. We expect differentials to tighten from the levels that they're at right now. To give you an example, we did pull back the amount of rail that we had in third quarter as the arbitrage versus rail versus differential became unfavorable for rail, where we could get a higher net back on moving it on pipe. During this time of the year we'd like to get to the point where we can get 40% when differentials are plus-CAD20 on rail. We're approaching the ability to do that right now. I think we're about where we want to be. We'll continue to seek out additional contracts. It is a very dynamic and evolving market. 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.

Okay, thanks.

Certainly.

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

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

I think this is a good example of what we've been talking about, and the previous question kind of led into this. Baytex has been at the 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 has really stepped up to fill that gap. You're typically seeing right now differentials almost to the CAD30 as WTI compared to WCS. We fully expected the differentials to be higher this time of year, as it is the refining turn-around season. In particular, we've had a couple of issues happen here with a pipeline interruption that happened, as well as an extension of a turn-around at a couple of the refineries, and one of the expansions that was scheduled to come on was a bit late. The combination of those things did have a little bit bigger affect on the differential this quarter.

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 it to 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 preference to heavy crude. Not really anything happening here out of the normal, with the exception of a little bit of exaggeration of the differential as a result of a few upsets that occurred during this time of the year this time. Brian, thank you.

That's great, Jim. All right, if there's no further questions, thank you, operator. I think that concludes this morning's conference call, and thank you all for your participation.

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