Baytex Energy Corp.
Q3 2014 Earnings Call Transcript

Published: 1 Nov 2014

[Executives:]

Brian Ector - SVP of Capital Markets & Public Affairs Jim Bowzer - CEO, President and Director Rick Ramsay - Chief Operating Officer

[Analysts:]

Mark Friesen - RBC Capital Markets Gordon Tait - BMO Capital Markets Gary Stromberg - Barclays Thomas Matthews - AltaCorp Capital Kali Ramachandran - State Street Global Advisors Ltd Kyle Preston - National Bank Financial

[Operator:]

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

[Brian Ector:]

Thank you, Arena. 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.

[Jim Bowzer:]

Thanks, Brian. And good morning everyone. We are pleased to report our third quarter results which reflect a strong contribution and the first full quarter from our Eagle Ford asset. Strong operating results were led by performance from the Eagle Ford which is exceeded our acquisition expectation. Before I get into the third quarter highlight, 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 2014, which at the midpoint reflects a 5% increase over our previous guidance of 86,000 BOE to 88,000 BOE per day. We expect to generate this addition of 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 49% 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 asset for net after tax proceeds of approximately $290 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 operation. Back when we acquired the Eagle Ford asset, the acreage position included 22,200 net contiguous acres in the sugarcane 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 BOE per day and in the third quarter production average approximately 34,000 BOE per day. This represented 36% above production during the quarter. Showing results have exceeded our initiation expectations with wells drilled during 2014 outperforming the type curves upon which acquisition evaluation was based. You will recall that our evaluation earlier this year was based on 30 day initial producing rate of 800 BOE to 1,000 BOEs per day. Through the first eight months of 2014, over a 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% in 30 day IP rate. This improved performance is being driven by combination of factors including drilling of longer lateral horizontal, tighter spacing of fracs and an increased amount of profit per stage. These individual well economic 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 wells. The capital expenditures for the Eagle Ford asset 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 acres. Furthermore, we are now piloting the drilling of up to four stacked horizon from a single pad, which if successful could lead to further expansion of our drilling inventory. I am now going to update you on a Canadian operation. In Canada, our operations and capital program remain on track with strong performance so far this year. Production average 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 approval 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 recovery from the field. In Lloydminster, our heavy oil area is there, we continue to expand the use of multi-lateral drilling technique. 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 rate exceeding 1,100 barrels a day. Consistent with our delineation plan in the fourth quarter, we will be filing the required regulatory amendment for our planned 5,000 barrels per day SAGD facility. While this regulatory step is necessary to progress the project, and final investment decision is contingent upon full economic review and the outcome of the first hand engineering study which is currently in progress. Now I'll spend the few minutes on our marketing efforts. First, heavy oil pricing is certainly being strong this year. The discount for Canadian heavy oil is measured by the price differential to WTI, average approximately $20 per barrel in the third quarter, essentially unchanged from the second quarter. Importantly, the WCS differential averaged approximately $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 reducing 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 WTI exposure at weighted average price of approximately $96 per barrel. For the first half of 2015, we have hedges in place on approximately 37% of WTI exposure at weighted average price of $95 per barrel and approximately 11% at $94 per barrel for the second half of 2015. We remained focus 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 my formal remarks, I would 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 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 make 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 places which have these 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 the lower percentage of our FFO to be reinvested to maintain our productive capacity. And while we certainly haven't thought finalized our plan for 2015, we have carried out a variety of sensitivity analysis, one sensitivity analysis using an $80 per barrel WTI price and exchange rate of $1.12 Canadian to US dollar. And WCS differentials 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 cap portion of our dividend. Over the long term, our objective is to fund our capital expenditures and cash dividend 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 the few key points about the quarter. We certainly believe we delivered an outstanding third quarter. We are 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 increase to capital spending. We are 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.

[Operator:]

(Operator Instructions) The first question is from Mark Friesen with RBC Capital Markets. Please go ahead.

[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?

[Jim Bowzer:]

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

[Mark Friesen - RBC Capital Markets:]

Okay. And then with regard to 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?

[Jim Bowzer:]

Get you well cost question that was fairly steady, it is certainly is going to improve the rate of return at relative fixed oil price by having initial producing rate. If you refer back to that, we got a chart in our material that shows the improving performance from 2011 through -- through the first part of 2014. We will be updating that curve to give you an idea of what that looks like to the year, but we were early on we saw that in 2014, we were outpacing our performance from initial producing standpoint in this year and that is further enhanced with the data that we have today. So we will update that curve for you as we get through here. And certainly we hope and believe it will impact EURs, although it is a bit early to say that with some of these wells are just coming on their first 30 days, some of been on for six to nine months here. But it is pleasing news that for sure.

[Mark Friesen - RBC Capital Markets.:]

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?

[Jim Bowzer:]

Yes. Prior to the acquisition we had data on about four wells, Mark. Throughout the year I think we had mention this in some of the presentation we've been giving when we are 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 is delineates about half of our acreage. So that's certainly good news and we will continue to watch for the results on the Chalk performance as they get to the 30 day IP. And we get additional performances as we move into 2015.

[Mark Friesen - RBC Capital Markets:]

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

[Jim Bowzer:]

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

[Mark Friesen - RBC Capital Markets.:]

Okay. Just jumping over to the water flood at the Harmon Valley, what do you expect for -- to see for response time on that?

[Jim Bowzer:]

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

[Rick Ramsay:]

Yes, sure, Mark. Rick Ramsay is here. We are modeling our pilot in Harmon Valley after the very successful water flood 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 is fairly small pilot. Just three wells, three adjusting wells. One of which we are going to convert to an injector and anticipating having that on stream here at the end of November. Obviously timeframe to response is a little uncertain at this point. Historically, in the other field we've seen response three 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 recovered about 3% of primary reserves already. So we do have some voyage to make up before we start that pushing towards the producers so --

[Mark Friesen - RBC Capital Markets.:]

Okay, yeah, that's helpful. Rick, while I also have your attention just my final question here 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?

[Rick Ramsay:]

Impact on enhanced oil recovery schemes, I am not really sure that it is applicable -- are you suggesting impact on water flood, Mark?

[Mark Friesen - RBC Capital Markets.:]

Yes.

[Rick Ramsay:]

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

[Mark Friesen - RBC Capital Markets.:]

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

[Jim Bowzer:]

Not effectively, no.

[Operator:]

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

[Gordon Tait - BMO Capital Markets:]

Good morning. In the -- with the change in the commodity prices here, are there any change you work through Marathon's development plans in Eagle Ford?

[Jim Bowzer:]

Gordon, not at this point. Certainly not as we finish up rest of the year. But we got a joint venture meetings coming up here this coming month, and we all be working collectively together on our budget just kind of to find what we do going forward there. So it's really too early to say whether it's going impact, it is certainly some of the best rates of return we have on our portfolio. So we are not too concerned about that. But just stay tune because we haven't worked on, yet ready to announce our budget and we won't be there till sometime in December.

[Gordon Tait - BMO Capital Markets:]

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?

[Jim Bowzer:]

If you we break that down into 640 acres spacing unit and you had at least two zones at -- four 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 little continue that on, it is right in the middle of sugarcane field, it's a part of joint venture acreage.

[Gordon Tait - BMO Capital Markets:]

Okay. And then last question, don't you like to give, 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?

[Jim Bowzer:]

Hey, Gordon, I refer you back to our guidance update that we just gave. You can kind of back out what fourth quarter would be out that because you have the third, we are saying that we are going to average 91 to 92 so it is kind of 92.5 is the second half of the year and minus where we are at. You got to take out the 35,000 barrels a day from the third quarter because we did have North Dakota Bakken production -- not quite the whole quarter but almost, so if you back that out it, it's kind of leaves you to that rate, we don't really publish exit rates for those kinds of things.

[Operator:]

Thank you. The next question is from Gary Stromberg with Barclays. Please go ahead.

[Gary Stromberg - Barclays:]

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

[Jim Bowzer:]

I don't have the breakdown, but if you are referring to the scenario that we were talking about there to sustain low oil price

[Gary Stromberg - Barclays:]

That's right.

[Jim Bowzer:]

From a cash flow. Give you the example, that it depends on how we place our capital little bit but you can get into that $600 million, $600 million pay range as we go forward if indeed prices were as low as they are today for some sustained portion of time going on. They get you the kind of the numbers that we talked about there in terms of balancing our cash flow with our capital spend and dividend.

[Gary Stromberg - Barclays:]

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

[Jim Bowzer:]

Yes. That's what we mean by sustaining our business going forward.

[Gary Stromberg - Barclays:]

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 2015 that was under different scenario, I realize. But 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?

[Jim Bowzer:]

Certainly. For starter, let's go back to kind of where we were prior to this spending. In round term $450 million to $500 million in our previous business. We had a fair amount of thermal spending there, some pieces of that round that to $50 million we had on average. Over the past several years about $100 million go into 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 rate returns are great and we will 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 are kind of just right almost if things get worse from here, I doubt we would be collectively deciding 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 yes 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.

[Operator:]

Thank you. The next question is from Thomas Matthews with AltaCorp Capital. Please go ahead.

[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?

[Jim Bowzer:]

Yes. Like I said it's really just a reverse of the previous question. And our programs are fully scalable. We needed to scale that up to $400 million spend high number. We are capable of doing that like wise.

[Operator:]

Thank you. The next question is Kali Ramachandran with State Street Global Advisors Ltd

[Kali Ramachandran - State Street Global Advisors Ltd:]

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?

[Jim Bowzer:]

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 don't -- 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 are 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 to 90 millions barrels a day to be over supplied, one or two 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 adjustments. So if that scenario presents itself, we will deal with it at that time. But right now, that's -- I don't think we are in a sustained sub 70 world that we need to focus on. We are certainly can run those scenario 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.

[Kali Ramachandran - State Street Global Advisors Ltd:]

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

[Jim Bowzer:]

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

[Operator:]

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

[Kyle Preston - National Bank Financial:]

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?

[Jim Bowzer:]

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 de-bottle necking that occurred in the third quarter associated with the two new production stations that were commissioned in the Eagle Ford as well. Like I said you can essential 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 and then October here that's going to be even more and then that will affect things a little bit. But it's all accounted for in the numbers we've already provided.

[Operator:]

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

[Brian Ector:]

All right. Well, thank you, Leena. And thanks everyone for participating in our third quarter conference call this morning. Have a great day.

[Operator:]

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