Baytex Energy Corp (BTE) 2015 Q1 法說會逐字稿

Good morning ladies and gentlemen, and welcome to the Baytex Energy Corporation 2015 first quarter results conference call. Please be advised that this call is being recorded. I would like to turn the meeting over to Mr. Brian Ector, Senior Vice President, Capital Markets and Public Affairs. Please go ahead.

Thank you Donna, and good morning ladies and gentlemen. Thank you for joining us today to discuss our first quarter 2015 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. On -- 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. All dollar amounts referenced in our remarks are in Canadian dollars unless otherwise specified.

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

Thanks Brian, and good morning everyone. Welcome to our first quarter conference call. I am going to break my comments into three parts for you today. First, I will talk about our operations. Second, our financial results. And third, I will provide an update on our marketing.

So first, on our operations, our performance in the first quarter was consistent with our full year plan and was led by record Eagle Ford productions in the continued advancement of the multi- zone development potential of our acreage. Capital expenditures for expiration development activities totaled CAD147 million in the first quarter, down from CAD215 million in the fourth quarter. This reduction in capital is reflective of reduced activity levels combined with negotiated cost savings with service providers.

In the first quarter, we participated in the drilling of 81 gross or 25.1 net wells with a 98% success rate. Despite the reduced activity level, operating results were strong, with production averaging 90,700 BOEs per day in the first quarter, largely unchanged from the fourth quarter of approximately 92,000 BOEs per day.

Our full-year production guidance remains unchanged at 84,000 BOEs to 88,000 BOEs a day. Now with the Q1 coming in at nearly 91,000 BOEs a day, our annual plan therefore does reflect lower production volumes for the balance of the year.

In the Eagle Ford, the activity reductions that commenced during the first quarter will be fully recognized as we move into the second quarter. And in Canada, please recall that we didn't suspend drilling activity during January. Our budgeted expiration and development expenditure range remains at CAD500 million to CAD575 million. I would, however, note that our 2015 program remains flexible and allows for adjustment to second half capital spending based on changes to commodity prices.

Turning to our Eagle Ford operations, production here averaged 41,100 BOEs per day during the first quarter, an increase of 8% over the fourth quarter of 2014, and now represents 45% of our total volumes. Capital expenditures totaled CAD126 million, down from CAD150 million in the fourth quarter.

During the first quarter, we participated in the drilling of 86 gross or 16 net wells and commenced production from 52 gross or 13 net wells. Of the 52 wells that commenced production during the first quarter, 42 wells established 30 day initial production rates of just over 1,000 BOEs per day.

In addition to targeting the lower Eagle Ford formation, we are now actively delineating the Austin Chalk formation. To date, we have delineated the Austin Chalk in over 50% of our acreage. Since acquisition, we have drilled 32 Austin Chalk wells and brought 20 of those on production. These 20 wells established an average 30 day initial production rate of approximately 1,000 BOEs per day, which is very consistent with our lower Eagle Ford development.

Additional advancements have been made to delineate the multi-zone development potential of our sugarcane acreage. We have initiated stack and frac pilots which target up to three zones in the Eagle Ford formation, in addition to the overlying Austin Chalk. Recent production data from a four well pad that targeted the lower Eagle Ford, the upper Eagle Ford, and Austin Chalk formations, delivered 30 day initial production rates per well ranging from 1,100 BOEs to 1,500 BOEs per day, and results from additional pilots like this are expected in 2015.

Shifting to Canada, production in Canada averaged just under 50,000 BOEs per day during the first quarter, a decrease of 8% from the fourth quarter. The reduced volumes in Canada include the divestiture of non-core assets in late 2014 and the shut-in of uneconomic production, which in aggregate, totaled approximately 2,000 BOEs per day.

In our updated budget for 2015, we chose to defer the majority of our development activity in Canada to the second half of this year. As a result, capital expenditures for Canadian assets totaled CAD21 million, down from CAD65 million in the fourth quarter.

At Peace River, we drilled one cold horizontal producer and five stratigraphic and service wells, and at Lloydminster, we drilled three oil wells. In our thermal operations, we have made the decision to decommission our Gemini SAGD pilot project in the second quarter, following a power plant outage. Our Gemini operations commenced over a year ago and since that time, we have successfully captured the key data associated with all the pilot objectives. Any subsequent sanctioning decision will be considered in the context of a higher commodity price environment sometime in the future.

Moving now to our financial results, we generated funds from operations of CAD160 million, or CAD0.95 per share, which is down from CAD246 million, or CAD1.47 per share, in the fourth quarter of 2014. Our reduced FFO is attributable to significantly lower commodity pricing.

During the quarter, we maintained a conservative payout ratio, net of our dividend reinvestment plan of 26%. We generated an operating netback in the first quarter of CAD13.89 per BOE or the CAD26.37 per BOE, including hedging gains.

Our Canadian operations generated an operating netback of CAD7.35 per BOE while the Eagle Ford generated an operating netback of CAD21.78 per BOE. Our light oil and condensate production in Eagle Ford is priced primarily off of the Louisiana Light Sweet, or the LLS benchmark, which typically trades at a premium to WTI. This strong pricing, combined with low cash cost contributed positively to our operating netback in the first quarter. Today, LLS is trading at about a CAD6 premium to WTI.

Our balance sheet has been significantly enhanced. Subsequent to the end of the first quarter, we completed an equity financing, raising net proceeds of CAD606 million, which has been applied to reduce bank debt. This strengthens our financial position and provides flexibility for us to pursue our planned capital program.

Pro forma from the equity financing, our total monetary debt is CAD1.85 billion, which results in a debt to EBITDA ratio, 12-months trailing, of 1.5 times. Our revised financial covenants allow this ratio to reach a maximum of 4.75 times, through June of 2016, and 4.5 times for the second half of 2016.

Our credit facilities consist of a CAD1 billion Canadian facility, a [$]200 million US facility that mature in June of 2018. Pro forma to equity financing, we have approximately CAD1.1 billion of undrawn capacity on these facilities.

Now, with respect to our marketing efforts, we do attempt to mitigate some of the volatility in commodity prices with a risk management program. Our second quarter 2015 crude oil hedge position amounts to approximately 33% of our net WTI exposure with 31% fixed at $87, per barrel. The unrealized financial derivatives gain with respect to our WTI hedges, at March 31, 2015, was approximately CAD105 million.

As part of our hedging program, we also focused on opportunities to mitigate the volatility in heavy oil differentials by transporting crude oil to markets by rail, when economics warrant. We have no fixed investment nor take or pay obligations to transport crude oil by rail, and the recent developments in rail infrastructure around our core heavy oil producing regions have allowed us to optimize deliveries by rail and pipe.

In the first quarter, approximately 22,000 barrels per day of our heavy oil volumes were delivered to market by rail. And for the second quarter of 2015, we expect to deliver approximately 20,000 barrels per day of heavy oil to market by rail as we optimize our heavy oil netbacks.

So in summary, our operating results for the first quarter were led by record Eagle Ford production and the continued advancement of the multi-zone development potential of our acreage, and we continue to scrutinize our capital and operating expenditures, which has resulted in significant cost savings. In response to the decline in crude oil prices, we have completed several key initiatives to maintain strong levels of financial liquidity. We have strengthened in our balance sheet with the equity financing, and as I mentioned earlier, the 2015 program remains flexible and allows for adjustments to second half capital spending based on changes in the commodity price environment.

Lastly, this has been a very active quarter for Baytex. I would like to commend the exceptional commitment of the Baytex employees, to quickly refocus their work on the key objectives that we outlined at the beginning of the year. I would also like to acknowledge the support of our shareholders during this high period of volatility.

So with that, I will conclude my formal remarks and ask the operator to please open the call for questions.

(Operator Instructions)

Mark Friesen, RBC Capital Markets.

Good morning, Jim. A few questions for you. A lot of discussion around oil pricing -- just wondering what kind of pricing signals you would be looking for as you may think about reviewing your CapEx budget, probably around midyear. What would cause you to increase or decrease your spending at that time?

Good morning, Mark, and thanks for the questions. I will take you a bit to the extremes maybe.

If we don't see oil get to and stay kind of in the -- call it the CAD60s, you know, I would look for Baytex to adjust our capital downward, and maybe forgo some of the capital spending we have in our current plan in the second half of the year, and that is an estimate, at this point. Kind of some of the markers that we have talked about openly as we put together our capital budget leading on the provision we made in February.

And likewise, on the other side of that, if you see -- if we see oil move up toward CAD70 or higher, by sometime in the third quarter, we would likely just stick with our capital plan through the rest of the year, as it is outlined right now. It is probably the way we look at that. There is probably somewhere in the middle there between those two that we will have to look at things, and take a look at each well we are drilling, and the incremental economics, and the cash flows at the time.

Differentials are also going to affect it, exchange rate will affect it somewhat. We do have a few other moving pieces that go into those calculations. In general, that is how we are thinking about it and have been since probably late December of 2014 and certainly as we outlined our budget into the first part of the year this year.

Okay. That is good context, Jim. Just focusing on Gemini for a second, I understand what you're saying and the actions you have taken there. But what kind of pricing outlook, maybe shorter term, for financing purposes or longer term for economics, would you be looking at, in terms of making a sanctioning decision for Gemini? And based on that, when do you think that might begin producing?

Certainly. Let me start by saying, the key information we obtain from that pilot is kind of all in the bank. The number one, key piece of information is, we've got a good reservoir there that flows vertically, and in a higher price environment, with the steam flood, can be produced in paying quantities. So there is a lot of other information we've got out of it, but the reservoir indication was the most important, the performance.

So moving on from that, to your -- directly to your question, to be quite frank, we have been very open about our plans with thermal. They have shifted back substantially, with not only the lower commodity price environment, but in addition, the change in our portfolio to a good inventory across our three key areas of conventional primary development and very, very high capital efficiencies. So it has been a couple of things that have shifted that. We would probably need to get back into an CAD80 or higher, CAD90 environment, before we would see sanctioning further thermal projects including Gemini.

Last pricing question. I saw that you added some hedges in the mid-$60s -- what should we expect for your hedging activity going forward? Do you want to add more at that level? Are you going to wait until prices change?

Mark, how we have thought about that is -- you know, prices have been extraordinarily low. And how we have looked at it, is -- while there may be the potential for a single geopolitical event, or production declines in primarily the US shale plays, could be sticky for awhile, there are some negative things that could come out, and maybe depress prices further, from a very short term perspective. But it is unlikely that we would see a sustained level, under $50, for years on end. So as we have thought about that, there isn't a whole lot of downside further below into the $40s, for sustained periods.

Therefore, when you look at -- when you would consider taking on hedges, we kind of looked at it from our business model standpoint of, where do hedges help start protecting us from -- for sustaining our business model going forward? And that kind of starts to occur in the mid-$60s and up toward $70. We have consistently said that is kind of where we are balanced with capital plans.

Again, there are a lot of moving parts in that, not only the price of crude itself, the price of natural gas is a smaller effect. The differentials are a bigger effect.

More importantly, now, is the cost savings are getting to be a pretty big effect in the ability to bring on barrels at higher capital efficiencies. So all of those things are moving parts in that. So we have talked about, as we get into the mid-$60s, a feathering on small amounts at that level.

As time goes on, and as it progresses upward in the higher level of protection that a hedge would provide, i.e. oil moves further up, maybe feathering on some more and building a base to where we would normally be hedged at 25% to 50% of our production at a level that makes a difference for the Company. So it is pretty consistent. We have just started in the last few weeks, to get into the $60s.

Today, you can put on a hedge at over $65 for 2016. I am talking all US dollars here, by the way. And you have seen us feather very small amounts in at that stage, and if prices gradually continue to increase, we will probably do a little bit more of it.

That is great, Jim. A couple quick Eagle Ford questions. What percentage of your acreage would you say has exposure to the chalk, exposure to the upper Eagle Ford, and exposure to all formations?

The lower Eagle Ford is obviously productive across all of it. The chalk at this stage is about -- is about 50% of it. And the other layers, the upper portion of the lower Eagle Ford and the upper Eagle Ford itself, are really just getting defined as we go through some of the testing this year.

So you have heard some of the results today that we've got of our 30 day IPs that we came out in the first quarter from one of our stack and frac pilots. You will be hearing more of that.

So we really are in the process in 2015 of defining really all three of the upper layers. But in particular, we have drilled quite a few more chalk wells and have a pretty good definition of what we think that might be.

There is probably a little further expansion that it could happen over time. But the middle portion of the Eagle Ford that we are testing here in 2015, is really the year to get it defined, if you will. So we haven't quoted a number yet on what portion of the upper Eagle Ford our acreage has been defined over.

Finally, do you expect the Eagle Ford to be self-financing this year?

Mark, it depends on -- you are going to have to go through the math on that. We've got low capital -- really high capital efficiencies and low development cost. Are you talking CAD40 deck, a CAD60 deck, an CAD80 deck, a CAD70--

Based on your views and planning. That's all.

Yes. Probably not quite, I would think. I'm talking off the top of my head. We are a little less self-funding all year long with everything. We don't have much in Canada. So that is probably a fair assessment at this stage.

Okay. Thank you very much for your comments, Jim.

Thank you.

Patrick Bryden, Scotiabank.

Good morning, gentlemen. Thanks for your time. Jim, I was just wondering if you might be able to elaborate a little bit further on the Eagle Ford and its evolution, as we look at the interplay between chalk in the upper and the lower. How should we think about the inventory implications for the year as we look ahead here?

I guess I would point to our year-end disclosure on reserves, as the best indicator of that. Last year, when we concluded the acquisition, we thought at that point, we have lower Eagle Ford locations, net to Baytex of about close to 200 to 250. As we ended this year, the lower Eagle Ford, both probable and undeveloped locations were close to that 200 mark in net locations.

And in addition, we did certify a probable reserve -- excuse me, a possible reserve category that defined some of the upper Eagle Ford and most of the Austin Chalk we saw at that point, and there are about 390 additional locations. As time has gone on here, the potential for this has certainly grown in our minds. And that is probably the best way to reflect it -- is to look straight at the number of locations we've got in what we call 2P proved, and the 3P, we have quantified it as best we can at this stage, which has grown substantially since we first took a look at this in 2014.

Great. Appreciate that. Maybe just one more question. If possible, are there distinctions you would draw, at this point, between the economics between all of those zones and the way you complete them? That is it. Thank you.

Thanks, Pat. Not really. There are some minor variances between individual wells across the entire acreage position, for sure. And there are variances across the liquids window from the volatile oil to retrograde condensate. You are really asking the question in elevation, as we move up and down the pay levels.

The differences between the wells are not a lot from an economic standpoint. They are pretty close to each other, within the same liquids or PVT window, if you will.

Appreciate that. Thanks very much.

Thomas Matthews, AltaCorp Capital.

Jim, two quick questions. On the stack and frac pilots, that four well pad, do you have any more of those planned? Are you currently working on any more of those in Q2 and beyond?

Yes, we do, Thomas. We have several planned throughout the year. Each quarter will probably have some results. We kind of wait until we've got 30 day IPs and the data is all in.

So it takes some time, because we are in all pad drilling mode. So you don't bring individual wells on any longer. You essentially bring on the entire pad, with all of the work is completed and the facilities are installed. So you will see us talk about this a little bit more through the year as time goes on.

I guess my -- let me rephrase my question. The pad that you are going forward now, will have the multi-zone potential mainly? Or will you be still just targeting the lower Eagle Ford and some of those pads?

No. We will have quite a few pads throughout the year. If you take a look at our first quarter numbers, about 25% of all the wells drilled were in the chalk. And then in the Eagle Ford were the rest, with a few of those wells being the upper Eagle Ford included on some of the pads.

You will be -- see, it is probably 50% to 60% of lower Eagle Ford and then the other 40% to 50%, in that range, will be a mix of the other layers, mixed in with a lower Eagle Ford. We will get a good series of tests as the time goes on. Those are the approximate numbers.

That sounds good. Finally, with the WCS diffs coming in and obviously the improvement in WTI, when do you look at bringing on your shut-in production again in Canada?

It varies well by well and area by area. It's just going to be a matter of economics. So we're getting to the point where we are looking at it right now.

The WCS -- we moved into driving season -- this is the time of year that that crude gets exceptionally high in demand. You've seen it trade inside of single-digit netbacks here -- excuse me, single-digit differentials.

So we are in and around CAD8 differential to WTI right now. So that certainly helps. And WTI has moved up toward the low CAD60s on a spot basis. That certainly helps. And it depends on -- what the operating expenses were.

Some of the production was single-digit netback at CAD90 oil, but it was still making positive cash flow. Some amounts will not come back on until we get probably -- with cost reduction, back up into the CAD80s. So it will feather back in here as prices continue to improve. And if they don't, some of that will remain shut in. So it is just going to depend on price. Parts of it, we're looking at right now.

Great, thank you.

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

Thank you, Donna, and thanks everyone for participating in our first quarter conference call. Have a great day.

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