Baytex Energy Corp (BTE) 2013 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the Baytex Energy Corp year-end results and reserves conference call. Please be advised, 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.

Thank you, operator. Good morning, ladies and gentlemen, and thank you for joining us today to discuss our fourth quarter and year-end 2013 financial and operating results. With me today are Jim Bowzer, President and Chief Executive Officer; Derek Aylesworth, 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. On the call today, we will also be discussing the evaluation of reserves and contingent resources at year-end 2013. These evaluations have been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects to United States or other foreign disclosure standards.

Our remarks regarding reserves and continued resources are also forward-looking statements. I refer you to our advisories regarding forward-looking statements, oil and gas information, and non-GAAP financial measures and the notice to US residents contained in today's press release.

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

Thanks, Brian, and good morning, everyone. I'm going to break my comments into three parts for you today.

First, I'm going to comment on our fourth quarter results and year-end reserves. Second, I'll provide you with an update on our operations and marketing. Third, I'll review with you the pending acquisition of Aurora Oil and Gas.

Before I get into the specifics of the quarter, I want to reiterate the guidance for 2014, which remains unchanged at 60,000 to 62,000 BOE's per day with budgeted exploration and development expenditures of CAD485 million. This guidance does not include the integration of our Eagle Ford acquisition, which was announced on February 6 and is expected to close in late May.

Following the closing of the acquisition, we will provide revised guidance for full year 2014. With respect to our fourth quarter results and year-end results, we generated quarterly production of just over 58,000 BOE's per day, which brings our full-year 2013 production to approximately 57,200 BOE's day; an increase of 6% over 2012.

As previously reported, our transportation operations were hampered by severe winter weather during the fourth quarter, which impacted our ability to deliver crude to sales points. As inventory levels reach capacity, production was curtailed by approximately 5,000 barrels per day in December. We generated funds from operations of CAD148 million or CAD1.18 per basic share in the fourth quarter, bringing our funds from operations for the full year to CAD604 million or CAD4.88 per basic share.

This represents the highest level of annual funds from operations in Company history. Our payout ratio in the fourth quarter net of our dividend reinvestment plan remained conservative at 40%, which is consistent with the 39% payout ratio realized for the full year. We ended the year with total monetary debt of CAD762 million, representing a debt to funds from operations ratio of 1.3 times based on funds from operations for the trailing 12 months.

At year-end, we had CAD627 million in undrawn credit facilities and no long-term debt maturities until 2021. On the capital spending front, we spent CAD85 million on exploration and development activities in the fourth quarter, with full-year expenditures coming in at CAD551 million. For the full year, we drilled 227 net wells with a 99% success rate.

During the fourth quarter, we were able to mitigate the volatility in the benchmark Western Canadian Select, or WCS Index, by transporting crude oil to higher value markets by rail. Approximately 21,500 barrels per day of our heavy oil volumes were delivered to market by rail. This is significant for Baytex as it represented 50% of our total heavy oil production.

The effect of our crude by rail strategy is really driven home by the improvement in Baytex's realized price relative to WCS. During the fourth quarter, our realized heavy oil price of CAD62 per barrel represented 90% of WCS.

A year ago, our realized heavy oil price of CAD55 per barrel represented just 79% of WCS. Our crude by rail strategy is having a positive impact on our overall net backs and is something we are set certainly pleased with.

I'm now going to switch gears and talk about our year-end reserves. We increased our proved reserves by 11% to 160 million barrels of oil equivalent, which represents a 9% increase on a per-share basis. We increased our proved plus probable reserves by 9% to 318 million barrels of oil equivalent or an increase of 7% on a per-share basis.

As I run through the highlights of the reserve report, to keep things simple, all of the reserve data I will reference reflects our proved plus probable reserves and is inclusive of changes in future development costs. Highlighting our 2013 reserve report includes: our net reserve additions in 2013 totaled 47 million barrels of oil equivalent, we replaced 234% of production through organic exploration and development activities. We recorded finding development and acquisition costs of CAD18.28 per BOE for 2013 and CAD15.65 per BOE for the three-year average 2011 to 2013.

Baytex generated an operating netback of CAD33 per BOE, resulting in a recycle ratio of 1.8 times for 2013 and a three-year average recycle ratio of 2.1 times. The net present value, before income taxes and discounted at 10%, of the future net revenue attributable to our proved plus probable reserves increased 15% to CAD4.3 billion.

Based on the midpoint of our 2014 production guidance, our reserve life index increased from 14 years to 14.3 years. If I look at each of our core operating regions, first of all I would like to state that we are very pleased with the results across each of our core areas and specifically, starting with Lloydminster, there we replaced produced volumes and year-end reserves totaled 59 million barrels, essentially unchanged from year-end 2012.

At Peace River, reserves attributable to our conventional heavy oil development in the Bluesky formation, our cold horizontal multilateral wells, increased 6% to 67 million barrels. In our Bakken/Three Forks resource play reserves increased 55% to 53.5 million barrels due to an increased drilling density to five wells per 1,280 acre spacing unit versus three wells previously. Lastly, our Bitumen reserves, and this relates to our thermal projects at Cliffdale, Kerrobert, and Gemini, totaled 102 million barrels unchanged from year-end 2012.

With respect to Baytex's contingent resources, our best estimate of economic contingent resources is 798 million BOE, which is essentially unchanged from year-end 2012. We are very pleased with our 2013 reserve report. We continue to demonstrate consistent reserve growth, very strong FD&A costs, and a healthy recycle ratio.

I'm now going to provide you with a quick update on our operations. Production from our Peace River properties averaged 23,900 barrels per day during the fourth quarter. On a year over year basis production at Peace River was up 7%.

During the fourth quarter, we drilled 11 cold produced horizontal producers encompassing a total of 125 laterals. Our 2013 cold horizontal multilateral program was one of the strongest in the Company history, with average 30 day peak production rates of approximately 600 barrels per day, which is near the upper end of our production expectations.

Turning to our thermal operations in Cliffdale at Peace River, at Pad 1, steaming operations were reduced in the fourth quarter due to steam generator repairs and maintenance. At Pad 2, which consists of 15 wells that were drilled in 2013, these wells are currently producing as planned under primary conditions to create the initial voidage required for cyclic steam stimulation process.

At Pad 2, we expect steaming to commence mid-2014. At Lloydminster, production averaged 19,400 barrels per day during the fourth quarter. Drilling included 8.7 net horizontal wells and 1.5 net vertical wells with 100% success rate. This area is characterized by stack pay, which has led to successful exploitation of multiple horizons with projects in the area generating consistent and repeatable results.

Construction of the Gemini SAGD pilot project facilities continued in the fourth quarter and commissioning was completed in early January. Steam injection commenced on January 24, with first oil projected to occur during the second quarter. In our Bakken/Three Forks development in North Dakota, three previously drilled wells established 30-day peak reduction rates of 410 BOE per day.

Now I want to spend a few minutes on heavy oil pricing and our marketing efforts. During the fourth quarter, about 75% of our production was weighted toward heavy oil. The price differential between WCS and WTI during the fourth quarter averaged 33% as compared to 17% in the third quarter. As I mentioned at the outset, we remain focused on opportunities to mitigate the volatility and WCS price differentials by transporting crude oil to higher value markets by rail.

During the fourth quarter, 50% of our heavy oil production was delivered to market by rail, which we expect to increase to just over 55% during the first quarter or approximately 26,000 barrels per day. Market conditions have recently improved with the forward market indicating a WCS price differential of approximately 23% for the first quarter of 2014 and 21% for the remainder of this year.

The improved market conditions reflect a number of positive catalysts unfolding in 2014, including increased refinery demand in the US Midwest and a continued increase in crude by rail volumes and a number of pipeline capacity improvements and expansion projects. We have taken advantage of the recent strength in WTI prices to add to our hedge portfolio. For the first quarter 2014, we have entered into hedges on approximately 55% of our WTI exposure at a weighted average price of just over CAD99 per barrel. For full year 2014, approximately 37% of our WTI exposure is now hedged at a weighted average price of just over CAD98 per barrel.

That summarizes our fourth quarter and year-end results. Before we open the call for questions, I thought I'd just spend a few minutes and update you on the pending acquisition of Aurora Oil and Gas.

On February 6, Baytex entered into an agreement to acquire all of the ordinary shares of Aurora for AUD4.10 per share. The total acquisition price is estimated at CAD2.6 billion, which includes the assumption of approximately CAD750 million of debt. The acquisition was financed in part by a CAD1.5 billion subscription receipt financing that closed on February 24.

The acquisition enhances Baytex's growth and income business model, delivers production and reserves growth per share, and provides attractive capital efficiencies for future investment. The acquisition is accretive to Baytex's funds from operations while maintaining a strong balance sheet.

The acquisition, which is being completed by way of scheme of arrangement under Australian law, is subject to a number of customary closing conditions including the receipt of required regulatory approvals and court approvals, as well as the approval of the Aurora shareholders. The acquisition is expected to close in late May 2014.

Aurora's primary asset is 22,200 net contiguous acres in the prolific Sugarkane Field located in South Texas in the core of the liquids rich Eagle Ford shale. Aurora's fourth quarter 2013 gross production averaged approximately 25,000 BOE's per day.

Sugarkane Field has been largely delineated with infrastructure in place, which is expected to facilitate low risk future annual production growth. In addition, these assets have significant future reserve upside potential from well down spacing, improving completion techniques, and new development targets in additional zones.

At Baytex, we are committed to a growth and income model and its three fundamental principles: delivering organic production growth, paying a meaningful dividend, and maintaining capital discipline. Through a combination of an expanded inventory of high capital efficiency projects and an improved outlook for heavy oil differentials, we remain confident in our business plan going forward. Consequently, Baytex has committed to increase the monthly dividend on its common shares by 9% to CAD0.24 per share, subject to the completion of the Aurora acquisition.

In summary, 2013 was certainly a strong year of performance for Baytex. We delivered the highest level of annual production and funds from operations in Company history, and increased our proved plus probable reserves by 9%.

Through our organic development program, we replaced 234% of our production and generated a strong 1.8 times recycle ratio, all in what was generally considered to be a challenging year for heavy oil pricing. Our development program for 2014 is well underway with 12 rigs currently running. We are excited about the potential for an improved heavy oil pricing environment in 2014 and look forward to continuing our strong performance with the expansion of our asset portfolio with the pending Eagle Ford acquisition.

With that I will conclude my formal remarks and ask the operator to open the call for questions.

(Operator Instructions)

Mark Friesen, RBC Capital Markets.

I noticed that, on your balance sheet, you've indicated that you've got some assets held for sale, and your notes mention that you've agreed on a swap of some assets from Saskatchewan into the Peace River region. Could you maybe provide a bit more details on that, and if there's further opportunity for this type of swapping action?

Yes, Mark. Thanks for your question. That's really just something that's in process, so we can't comment too much on it. But it's a relatively small swap -- the kind of things that we've worked on in the past, and would hope to continue to be able to work on to continue to improve our portfolio. We're in the middle of it during a quarter change, and that's why it's reflected in the comments that you saw there.

Okay. So, more to come in the first quarter, or soon?

Yes, it's relatively small.

Okay. Gemini is scheduled to start producing here pretty soon; it's been on steam for a little while. Can you be a bit more specific as to when you think that's going to start up? And just remind me, if you could, what your expectations are for rate and SOR on that pilot?

Mark, this is Marty. I'll take the question.

We're really right on track with Gemini. We were on track with our budget and schedule. Everything was complete around year-end 2013. We started first steaming of the pilot well pair on January 24, and we expect to get some oil production from that project in the second quarter of 2014.

A little bit early to predict what we're going to see. There's a lot of analogues we can point to. Our expectations remain that we're going to see what we expected, and then move on to a commercial phase. But for now, everything's on track, both budget and timing, and we're anticipating good results by mid-year.

Thanks, Marty. Can you remind me what you expected in terms of rate and SOR?

I don't think I told you before, so it's difficult to give you a precise number. But there's a lot of analogues that say that we should expect somewheres between 800 and 1,000 barrels per day, and that's kind of on track.

Okay, great. (multiple speakers) Thank you.

We're looking for resolution from the AER on the issues in Reno; that should come out in the next couple weeks, hopefully. Can you mention what your planned activity or response is going to be, assuming you get a positive ruling from the AER?

You're right. There was a hearing -- a proceeding in the Peace River region that had an oral phase in the second half of January. Baytex was a very active participant in all parts of that proceeding. We do expect the panel that sat for the AER intends to deliver their report on the proceeding by the end of March. We are prepared to do whatever they recommend.

We still anticipate drilling around 36 horizontal wells -- cold horizontals in that Peace River region this year. Those plans haven't changed. What we have committed to do is install vapor recovery on everything in the region, do our best to minimize our environmental impact, and improve, actually, the way we've been interacting with the community. We are committed to continue to be an environmentally responsible operator in that region.

So, no change to the 2014 program regardless of what they say, but it could be positive for drilling activity in Reno in the 2015 time frame?

I don't expect there will be, based upon the results of this proceeding. There's a possibility we'll change the program a bit as we integrate the Aurora acquisition when the time comes. But at this time, we don't foresee any change.

Okay. Just switching gears here a little bit, I noticed that some undeveloped land had decreased a little bit in Alberta, BC, and the US. Is that just sales or normal expiries, or do we have to be thinking about potential expiry issues coming up here this year, or soon?

I think it reflects a bit of a decrease in asset and purchase prices that have been paid at crown sales in the last year for one thing, and a little bit on expiries, yes.

Okay, but nothing unusual in the upcoming time frame?

No.

Okay. And thanks for your comments, Jim, about the impact of rail, in terms of what that's done, in terms of netbacks and realizations. With that positive impact, why not continue to increase it even beyond the levels that you're talking about for the first quarter, or is that your intention? What sort of constraints would you have in terms of increasing rail shipments going forward?

Yes, Mark. I really want to, first of all, give a shout out to all of our folks involved in that. We've got a great team here between the operations folks that make this happen and an outstanding marketing organization that puts these things together for us. It's pretty impressive work that's gone on.

But it's a dynamic market. And as refining capacity increases here coming on, as we speak right now, really, with additional expansion of unit trains for others to use to move their crude by rail out of Canada, and additional pipeline projects are coming on this year, that changes kind of where the benchmark might end up going to.

As a result of that, we remain flexible on what we're going to do with rail to achieve the highest netbacks, which includes maybe keeping a certain higher percentage on pipe. It just depends on where the market goes to, and we're certainly as good at being on top of that as anybody, and take advantage of whichever way we go.

I don't really have any further predictions other than what we stated we would be at in the first quarter for transportation on rail versus pipe. We'll see how the economics of the various decisions we make are going forward.

Okay. Thanks for that extra color, Jim. That's it for me.

Dirk Lever, AltaCorp Capital.

You were down about 5,000 barrels a day in December from cold weather in the Peace River, and that's about 1,700 for the quarter. Any sense of what it's like for Q1 2014 since we've had some pretty cold weather up in the north region? How could we look at that for Q1, assuming that, from here forward, we're not going to have that type of weather?

Dirk, it's Marty. I'll take the question.

I would say Q1 is very typical of most first quarters we've experienced over the last many years. Q4 was certainly unusual. And it wasn't just Peace River; it was in some others of our operating region, as well. Q1, we got off to a good start with our drilling program. In fact, we had colder-than-usual weather, which helps, really, with executing our stratographic test [drilling] program.

By now, we've already drilled about 100 wells, and we're on track. Production-wise for the first quarter, also, we remain on track to deliver what we committed for the year, which was between 60,000 and 62,000 barrels equivalent per day. I would say we're off to a good start, really as expected.

Thank you.

(Operator Instructions)

Gordon Tait, BMO Capital Markets.

I have a question going up to seal. If the two thermal pads that you're developing now -- one's up and running, the other's being drilled and developed -- if they work out as you expect, how many of these 15 well pads do you think you might be able to build, say, in the next five or six years? Specifically, how many of these do you think you could actually do in any given year, once you get some scale behind you?

Gordon, this is Jim. We've got the two pads on right now. And as we've indicated to everybody in the past, we've got two more that have been submitted for approval. The logistics are really around the year-and-a-half to two years it takes for approval through time.

The pace at which we develop that will really be dictated by our cash flows and the capital efficiency adjustments as we go through. As we pull the Aurora in, that could be somewhat mitigated. The flip side to that is that, as our cash flows improve through time, it makes it a little easier to actually do these if we would choose to do the pace.

As you well know, we focus our capital spend around our business model, which is to deliver a moderate growth rate that we've talked about in the past, kind of the 5% to 7%, and maintain a consistent pay-out ratio that allows for a very healthy dividend. That really drives what we do capital-budget-wise. Within that, we basically use the highest capital efficiencies going down to some of the longer-term projects that we do that may be relatively lower capital efficiencies from the outset, but build in a flatter life, which actually helps improve declines over time.

With the changes in our portfolio here, we'll get out some additional understanding of what pace may be as we fully integrate the changes that are coming on. But that's kind of how we would look at it, if you will, Gordon.

Okay, I understand. It sounds like you have another potential project in Texas that might be some competition for capital in the Company.

Secondly, if you step back and look a little bit at the market, Jim, because I know that you know a lot about the market dynamics for the different products in North America -- when you think about what happened last year in Canada, we had those heavy light differentials blew out, Canadian oil trading at discount to US. It seems to have stabilized. Can you maybe see how you see that market now, and the changes, say, in the last 12 months, and what you see going forward that would impact the things that affected us last year?

Yes, certainly. If you step back to look at the cause of -- the Western Canadian Select disconnect is the primary one -- but suffice it to say that it's really been over the past four years, transportation bottlenecks have affected really all crudes north of Cushing, Oklahoma. That's where the transportation problems have been.

That problem was, first, in a lot of ways, solved in North Dakota by rail. The last I saw was almost 75% of that crude is moving out of that basin by rail, and that's a significant volume, as you know what the total production is out of that basin. The same thing has occurred in Canada with lights and heavies over time, and at various discount rates with various changes that have been taking place.

The market has done a good job of reacting to this, I think, in pipeline expansions that have been done. If you go back several years, we've had continued increase in the conversion capacity that exists at refining complexes in the Midwest. In pad 2, the latest of those is Whiting's facility that is coming up to taking its full amount of heavy, as we speak now.

The combination of the significant expansion of rail out of Canada, which has really started to occur notwithstanding our relatively small volumes in the -- it's big for Baytex, but in the entire amount that's being moved out of Canada, it's really relatively small. With two new unit trains coming on this year, Flanagan South coming on, you're seeing the stabilization, as you would hope to see, with bottlenecks being removed and producers having options in which to transport their crudes.

It ought to come down to the very basic fundamentals if transportation is not an issue, and that is the cost of the transportation if it's available, the quality of the crude, and the ultimate value that is created out of that crude as it's turned into transportation fuels at a refinery. We're seeing the benefit of the bottlenecks being removed that's causing that to happen.

Okay. It sounds like you think we're in for at least a period of more stability, certainly than we were last year?

Yes, Gordon, I would call it a period of lower -- lesser volatility, is probably the way that we should think of that. This is a commodity. There are other factors across the world that affect crude prices other than just bottlenecks relative to crude-on-crude competition. I would like to think that we've lowered the volatility window, as opposed to reduced volatility completely, or provided stability is probably a better way to say that.

Okay. All right, thanks.

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

Thank you, operator. And thanks, everyone, for participating this morning on our fourth-quarter and year-end conference call. Have a great day.

Thank you. That concludes today's conference call. Please disconnect your lines at this time. We thank you for your participation.