Baytex Energy Corp (BTE) 2014 Q3 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the Baytex Energy Corp's Third Quarter 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, Senior Vice President, Capital Markets and Public Affairs. Please go ahead, Mr. Ector.

Thank you, Elina. Good morning, ladies and gentlemen, and thank you for joining us today to discuss our third quarter 2014 financial and operating results. With me today are Jim Bowzer, our President and Chief Executive Officer; Rod Gray, our Chief Financial Officer; and Rick Ramsay, 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, oil and gas information and non-GAAP financial measures contained in today's press release.

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

Thanks, Brian, and good morning everyone. We're pleased to report our third quarter results, which reflect a strong contribution and the first full quarter from our Eagle Ford assets. Strong operating results were led by performance in the Eagle Ford, which has exceeded our acquisition expectations.

Before I get into the third quarter highlights, I want to update you on our guidance for the second half of this year, which we are adjusting upward due to our strong third quarter operating performance. We now expect to generate an average production rate of 91,000 BOE to 92,000 BOE per day in the second half of 2014, which at the mid-point reflects a 5% increase over our previous guidance of 86,000 BOE to 88,000 BOE per day. We expect to generate this additional production while maintaining our original capital guidance of $440 million to $465 million for the second half of 2014.

Now back to the third quarter, we generated production of just over 94,000 BOE a day an increase of 41% over the second quarter of 2014 and 56% over the third quarter of 2013. We delivered funds from operations of $298 million or $1.79 per basic share. This represents an 80% increase over the second quarter of 2014 and an 49% increase over the third quarter of 2013. We generated a strong operating netback of $41 per BOE during the third quarter with the Eagle Ford operations contributing $45 per BOE to our overall netback.

We maintained a conservative payout ratio, net of dividend reinvestment plan participation of 30%. And we divested of our North Dakota assets for a net after-tax proceeds of approximately $290 million, which were used to repay debt. And lastly, total monetary debt at the end of the third quarter is at $2.26 billion of which approximately $1.38 billion is comprised of long-term debt with no material repayments required until 2021. And we have approximately $600 million in undrawn capacity on existing credit facilities, which provides us with ample liquidity to allow us to execute our growth and income model.

I'll now move into an update of our Eagle Ford operations. Back when we acquired the Eagle Ford assets, the acreage position included 22,200 net contiguous acres in the sugar cane field located in South Texas in the core of the play. Since that time we have acquired additional acreage, bringing our total land position to approximately 23,000 net acres.

At the time of acquisition, production was approximately 28,000 BOEs per day and in the third quarter production averaged approximately 34,000 BOEs per day. This represented 36% of our production during the quarter.

Drilling results have exceeded our initial expectations with wells drilled during the -- during 2014 outperforming the type curves upon which our acquisition evaluation was based. You will recall that our evaluation earlier this year was based on 30-day initial producing rates of 800 BOEs to 1,000 BOEs per day. Through the first eight months of 2014, over 100 gross wells have been drilled and placed on production for more than 30 days. For these wells, we are seeing an improvement of 20% and 30-day IP rates. This improved performance is being driven by a combination of factors, including drilling of longer lateral horizontals, tighter spacing of fracs and an increased amount of [profit] per stage.

These individual well economics provide some of the best capital efficiencies in North America. During the third quarter we participated in the drilling of 14.9 net wells and commenced production from 14.4 net well.

The capital expenditures for the Eagle Ford assets incurred during the quarter totaled $140 million. We have identified additional well locations to support future growth as we are now actively delineating the Austin Chalk formation. To date we have delineated this formation on approximately 50% of our acres.

Furthermore, we are now piloting the drilling of up to four stacked horizons from a single pad, which if successful could lead to further expansion of our drilling inventory.

Now, I'm now going to update you on our Canadian operations. In Canada, our operations and capital program will remain on track with strong performance so far this year. Production averaged 56,700 BOEs per day essentially unchanged from the third quarter of 2013 with capital expenditures of $77 million.

At Peace River we produced approximately 26,500 BOEs per day in the third quarter. We drilled six cold horizontal producers encompassing a total of 81 laterals. We also received regulatory approvals to implement a water flood pilot in the Bluesky reservoir in Harmon Valley.

Construction of the required facilities commenced in the third quarter and we anticipate that water injection will begin in the fourth quarter.

This is our first water flood project in the Peace River area, which if successful could enhance our ultimate recoveries from the field.

In Lloydminster, our heavy oil area there, we continue to expand the use of multi-lateral drilling techniques. In the third quarter, we drilled three successful horizontal multi-lateral wells. One dual lateral well and two triple lateral wells.

Initial results are showing an approximate 20% improvement in capital efficiencies through the use of multi-lateral drilling. We continue to monitor the performance of these wells and are planning for an expanded multi-lateral drilling program in the Lloydminster area for 2015.

At our Gemini SAGD pilot project, the 600 meter horizontal well pair averaged 850 barrels per day in the third quarter with peak rates exceeding 1,100 barrels a day. Consistent with our delineation plans, in the fourth quarter we will be filing the required regulatory amendment for our planned 5,000 barrel per day SAGD facility. While this regulatory step is necessary to progress the project, a final investment decision is contingent upon full economic review and the outcome of the front-end engineering study, which is currently in progress.

Now I'll spend a few minutes on our marketing effort. First, heavy oil pricing is certainly been strong this year. The discount for Canadian heavy oil is measured by the price differential to WTI averaged approximately US$20 per barrel in the third quarter essentially unchanged from the second quarter.

Importantly, the WCS differential averaged approximately $13 per barrel for the October trade month, for $14 a barrel for the October trade month and $13 a barrel for the November trade month. The narrowing of the WCS differential is certainly reduced the impact of the recent decline in oil prices. In addition, we are also benefiting from the weakness in the Canadian dollar.

With respect to our hedging program, we do employ risk mitigation strategies to attempt to reduce the volatility in our funds from operations. For the fourth quarter, we have hedges in place on approximately 51% of our WTI exposure at a weighted average price of approximately US$96 per barrel.

For the first half of 2015, we have hedges in place on approximately 37% of our WTI exposure at a weighted average price of US$95 per barrel. And approximately 11% at $94 per barrel for the second half of 2015.

We remain focused on opportunities to mitigate the volatility in WCS price differentials by transporting crude oil to higher value markets by rail and currently approximately 60% of our heavy volumes are delivered to market by rail.

Now before I wrap up my formal remarks, I'd like to make some comments about our business model and what the current state of the crude oil markets might mean for us. First, we are committed to our growth in income business model and its three fundamental principles delivering organic production growth; paying a meaningful dividend; and maintaining capital discipline.

When oil prices fall as they have over the past couple of months, this certainly can put stress on any business model. However, we believe, we are well positioned to weather this current downturn. From our perspective, and I think this is important not to lose sight of what makes our business model so successful. First, we have some of the strongest capital efficiencies across our portfolio, which allows us to add production at relatively low capital cost.

Second, we are now directing over 90% of our capital to those key plays, which have these high capital efficiencies. And third, we have a material advantage with respect to how much capital we need to allocate to sustain our business. Our strong capital efficiencies benefit us as we require a lower percentage of our FFO to be reinvested to maintain [both] our productive capacity.

And while we certainly haven't thought -- finalized our plans for 2015, we have carried out a variety of sensitivity analysis, one sensitivity analysis using an US$80 per barrel WTI price an exchange rate of about $1.12 to US dollar. And a WCS differential of 18% does provide some context to the current commodity price environment. In that, under these assumptions, we would expect to generate sufficient FFO to fund our sustaining capital requirements and the cash portion of our dividend.

Over the long-term, our objective is to fund our capital expenditures and cash dividends with FFO. And it's important to emphasize that in a persistent low commodity price environment, Baytex would initially look to reduce our capital expenditures to achieve that balance.

And now, I am going to conclude with just a few key points about the quarter. We certainly believe we've delivered an outstanding third quarter. We're very pleased with our operations that are performing exceptionally well. Our Eagle Ford asset is exceeding what our expectations were at the outset. And we have increased our second half production guidance by 5% with no increases in capital spending. We're very pleased with our operating performance and look forward to sharing with you our 2015 budget in the coming months.

And with that I'll conclude my formal remarks and ask the operator to open the call for questions.

Certainly. Thank you. (Operator Instructions). Mark Friesen, RBC Capital Markets.

Thanks, good morning, Jim. Just a couple questions on each of the operating divisions. First of all you mentioned some increased acreage in the Eagle Ford, wonder if you could just give a bit of color around that, where it is, how much you paid, is there -- should we expect more of that to come?

Yes, it's in and around the sugarcane area essentially in our joint venture area, Mark, right in with the acreage that we initially purchased. I don't want to get into for competitive reasons. The competitive nature of it, so just suffice it to say, it's a direct bolt on to our existing operations there.

Okay. And then with regard to the, the increase to the or the shift up to the type curve, what impact would that have on ultimate recovery and IRR of those wells and has the well costs gone up as well or is that done at the same cost?

[What gets] you well cost questions, those are fairly steady. It certainly is going to improve the rates of return at any relative fixed oil price by having initial producing rates. If you refer back to that, we got a chart in our materials that shows the improving performance from 2011 through 20 -- through the first part of 2014.

We'll be updating that curve to give you an idea of what that looks like through the year, but we were early on, we saw that in 2014, we were outpacing our performance from a initial producing standpoint this year. And that is further enhanced with the data that we have to date. So we'll update that curve for you as we get through here. Certainly, we hope and believe it'll impact the EURs, although it's a bit early to say that with some of these wells are just coming on their first 30 days. Some of them been on for six months to nine months here. But it's pleasing news, that's for sure.

Okay. I'll be watching for that. Little surprised with the progress in the Austin Chalk, I thought you would previously only had a few wells in there and now you mentioned delineating half the acreage. How did that happen, was it a rapid increase in Chalk targets or can you talk about that?

Yes, prior to the acquisition, we had data on about four wells, Mark, throughout the year. And I think we had mentioned this at some of the presentations we've been giving when we're out on the road and in the middle of the third quarter. But we are actively delineating it and just to give you an update there, we got about 15 wells across the acreage, which is about, which if you calculate that out, it delineates about half of our acreage.

So that's certainly good news and we'll continue to watch for the results on the Chalk performance as they get to be 30-day IPs and we get additional performance as we move into 2015.

So should we expect that to impact the year-end reserve booking?

It could possibly. You saw a reserve number we came out on the initial announcement. We're just entering that part of the season as well, but we certainly have better data, a wider spread number of take points there with some quality performance so for, but, so there -- while the full impact of that won't be known for some time, it certainly impacted somewhat as we moved into 20 -- late 2014, early 2015 when we complete a reserve evaluation.

Okay. Just jumping over to the waterflood at the Harmon Valley, what do you expect for (inaudible) on that?

I'll turn that one over to Rick, he can maybe talk a little bit about the background of setting that up and it's a relatively small first pilot, but let him provide some color here on that.

Yeah, sure Mark, Rick Ramsay here. We're modeling our pilots in Harmon Valley after the very successful waterflood that we got in for others in Saskatchewan. And that's targeting oils in the viscosity range of 6,000 centipoise to 13,000 centipoise. It's a fairly small pilot just three wells, three existing wells, one of which we're going to convert to an injector and anticipating having that on stream here at the end of November.

Obviously time-frame to response is a little uncertain at this point. Historically in the (inaudible) field we've seen response three months to six months after injection has begun. But every location is different, this particular project, the wells have been under production for a number of years and we've recovered about 3% of primary reserves already. So we do have some voyage to make up before we start pushing fluid towards the producers. So --

Okay. Okay, yeah, that's helpful. Rick, while I also have your attention just my final question here on, on the multi-lateral program that's picking up in the Lloydminster area, you obviously see the benefit, the capital efficiencies there. But how are you thinking of that in terms of potential future impact to enhance the oil recovery schemes in that area?

Impact on enhanced oil recovery schemes, not really sure that it's applicable, are you suggesting impact of waterfloods, Mark?

Yes.

Well, we would be doing this in areas where we most likely would not be pursuing waterfloods. If we do complicate the reservoir a little bit, when you have multi-legs does make it little bit more difficult to waterflood. For example, we do have a waterflood underway in the Tangleflags area, which we've initiated using single lateral wells to 15 well pilot that's underway.

Okay, but you're not using these multi-laterals in areas that would be future waterflood candidate.

Not effectively, no.

Okay. Okay, good. Thank you very much. That's it from me.

Thanks Mark.

Gordon Tait, BMO Capital Markets.

With the change in the commodity prices here, are there any change (inaudible) Marathon's development plans in Eagle Ford?

Gordon, not at this point, certainly not as we finish out the rest of the year, but we got our joint venture meetings coming up here this coming month. And we'll all be working collectively together on our budgets kind of define what we do going forward there. So it's really too early to say whether it's going to impact it. That's certainly some of the best rates of return we have in our portfolio. So we're not too concerned about that, but just stay tuned because we haven't worked on getting ready to announce our budget and we won't be there until sometime in December.

Okay. And then with the 1,000 acres that you bought, just to give us a [context] about how many productive zones do you think you would see in that, and therefore how many wells could it actually support just the 1,000 acres?

If you break that down into a 640 acre spacing unit, and you had at least two zones that 44 wells per zone potentially eight or more over time depending on the spacing thickness and whether there are some isolating barriers in there allow you drill more. And if there are potentially more than that across the acreage position, Gordon. So it's not a little -- that on, it's right in the middle of the Sugarkane Field that's part of the joint venture acreage.

Okay. Then last question, (inaudible) you haven't talked about, you don't have next year's budget yet, but do you have a sense of what your 2014 exit rate would be based on where you are?

Gordon, I'd refer you back to our guidance update that we just gave you, kind of back out what fourth quarter will be out of that because you have the third, we're saying that, we're going to average 91 to 92, it's kind of 92.5 is the second half of the year minus where we're at. You've got to take out the 3,500 barrels a day from the third quarter because we did have North Dakota Bakken production in -- not quite the whole quarter, but almost. So if you back that out, it kind of leaves you to that rate because we don't really publish exit rates for those kind of things.

Okay, thanks.

You bet, Gordon. Thank you.

Gary Stromberg, Barclays.

Can you just give us an update on what sustaining CapEx is today and perhaps break that out between Canada and the US?

Yeah, I don't have a breakdown, but you're referring to the scenario that we were talking about there, the sustained low oil price -- from a cash flow. Give you the example that it depends on how we place our capital little bit, but you get into that $600 million to $650 million say range as we go forward F&D prices were as low as they are today for some sustained portion of time going on. That gets you the kind of the numbers that we talked about there in terms of balancing our cash flows with our capital spend and dividend.

And when you talk about sustaining, does that mean sustaining flat production or would you let production fall?

Yeah, that's what we mean by sustaining. Sustaining our business going forward.

Okay. And then what if there is a scenario where in the US, the operator wants to spend more and maybe there is more negative free cash flow coming out of that business, I know in the summary, you talked about the Aurora assets being free cash flow positive in '15 that was under different scenario, I realize.

But, you know, how do you think about balancing being a working interest partner and not really having control over CapEx versus your Canadian assets, where you do have a control, I mean, how do you think about toggling those two pieces?

Certainly, for starters, let's go back to kind of where we were prior to this spending. In round terms 450 million to 500 million say in our previous business. We had a fair amount of thermal spending there, some pieces of that, round that 50 million we had on average. Over the past several years about 100 million going to the Bakken that's gone. So and the rest of our Canadian business is fully scalable, we control all of that. So if we end up for whatever reason drilling more in the Eagle Ford, those rates return great and we'll take them. And we can scale down. So we've got quite a bit of flexibility with full scalability in everything else we do if we needed to, that was the case.

Now, having said that, you kind of described almost if things get worse from here, I doubt we would be collectively deciding that, in that joint venture to pick up rigs together and accelerate that pace at that time. So I don't think that's very likely, but yeah, it's a question, we certainly thought it through and have the scalability capability to scale down our operations elsewhere and allow that to provide the production growth.

Okay. That's really helpful. Thank you.

You bet. Thank you.

Thomas Matthews, AltaCorp Capital.

Hi, most of my questions have been answered, but I just like to take the other side of that coin. What if in your budget talks with Marathon, they decided to cut CapEx where, you know, maybe you guys don't necessarily agree with. Would you be more likely to ramp up the 100% acreage in the Eagle Ford or take maybe some of your extra CapEx in on the Canadian side?

Yeah, like I said, it's really just that reverse of the previous question. And our programs are fully scalable, if we needed to scale that up to $400 million spend, a higher number, we're capable of doing that, likewise.

Okay. Great.

Thank you.

Kali Ramachandran, State Street Global.

Hi, thank you. Just a clarification, you mentioned earlier on that an $80 WTI that you could live within your CapEx spending and maintain your distribution. What happens under a scenario where WTI is around $70?

Well, first of all, I would say that, we look at this very seriously and very well thought out over the long term. So I think it's important that we don't need to react to anything that happens. So if the world was where it is today, where we're at kind of this $80 environment, the overall fundamentals in the world balance of oil supply versus demand are fairly solid, in the big picture of a consumption of 88 million to 90 million barrels a day to be oversupplied 1 million barrels or 2 million barrels for a short period of time. I don't think that you would come to the case where you would see a sustained low for many years that would require some sort of other adjustment. So if that scenario presents itself, we'll deal with it at the time. But right now that, I don't think we're in a sustained sub-70 world that we need to focus on. We'll certainly can run those scenarios and look at them over time. I don't have that set of numbers right here in front of me, but we certainly will take a look at it if that's the case.

Would you say in general that most of your sites would be generating a internal rate to return of over 10% at $70 oil?

Yes, I would. We've looked at the breakeven numbers and from what we have in our portfolio, those get down to kind of the $50 to $60 range and we still get a decent rate of return out of those. And there is some work that's been done that's public, we even referred to that in our slide deck, if you want to take a look at. I think it was the Barclays Conference we presented a breakeven scenario there at that time for incremental rates of return. It's pretty solid performance, which again is a, what we believe a competitive advantage of the mix across our portfolio.

Okay. Thank you.

Thank you.

Kyle Preston, National Bank.

Yes, thanks good morning guys. Most of my questions been answered, but just to clarify again, on your Eagle Ford production, the 34,000 barrels in Q3 how should we be thinking about Q4? I mean is that sort of a run rate here going forward or was there a lot of fresh production included in that?

I think there is certainly a bit of plus, we brought on a few more wells. But over a quarter, Kyle, it's -- we tend to balance out those ups and downs. We are bringing on large volumes when a single pad comes online. But over a quarter it should be fairly stable. We did have some debottlenecking that occurred in the second quarter or the third quarter associated with the two new production stations that were commissioned in the Eagle Ford as well.

Like I said and you can essentially back out the numbers from what we've got for a second half overall guidance increase. We did refer to on some of our facilities, we do have maintenance in October here that's going to be even more then that will affect things a little bit. But it's all accounted for in the numbers we've already provided.

Okay. thanks. That's it for me.

Thanks, Kyle.

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

Alright, well, thank you, Elina. And thanks everyone for participating in our third quarter conference call this morning. Have a great day.

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