Baytex Energy Corp.

Brian G. Ector - Senior Vice President of Capital Markets & Public Affairs James L.

Bowzer - Chief Executive Officer, President and Director

Mark J. Friesen - RBC Capital Markets, LLC, Research Division Patrick I.

Bryden - Scotiabank Global Banking and Markets, Research Division Thomas Matthews - AltaCorp Capital Inc., Research Division

Thank you, Donna. Good morning, ladies and gentlemen, and 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.

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'm going to break my comments into 3 parts for you today: first, I'm going to 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 production and the continued advancement of the multi-zone development potential of our acreage. Capital expenditures for exploration and development activities totaled $147 million in the first quarter, down from $215 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, our 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 to 88,000 BOEs per day.

Now with Q1 coming in at nearly 91,000 BOEs per 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 did suspend drilling activity during January.

Our budgeted exploration and development expenditure range remains at $500 million to $575 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.

And 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 $126 million, down from $150 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 rate 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 Sugarkane acreage.

We have initiated stack and frac pilots, which target up to 3 zones in the Eagle Ford formation, in addition to the overlying Austin Chalk. Recent production data from 4-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 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 BOE 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 our Canadian assets totaled $21 million, down from $65 million in the fourth quarter. At Peace River, we drilled 1 cold horizontal producer and 5 stratigraphic and service wells.

And at Lloydminster, we drilled 3 oil wells. And in our thermal operations, we have made the decision to decommission our Gemini SAGD pilot project in the second quarter, following up 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 $160 million or $0.95 per share, which is down from $246 million or $1.47 per share in the fourth quarter of 2014.

Our reduced FFO is attributable to significantly lower commodity prices. 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 $13.89 per BOE or $26.37 per BOE including hedging gains. Our Canadian operations generated an operating netback of $7.35 per BOE, while the Eagle Ford generated an operating netback of $21.78 per BOE.

Our light oil and condensate production in the Eagle Ford is priced primarily off of 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 $6 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 $606 million, which have 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 $1.85 billion, which results in a debt-to-EBITDA ratio 12 months trailing of 1.5x. Our revised financial covenants allow this ratio to reach the maximum of 4.75x through June of 2016, and 4.5x for the second half of 2016.

Our credit facilities consist of $1 billion Canadian facility, a $200 million U.S. facility that mature in June of 2018.

Pro forma the equity financing, we have approximately $1.1 billion of undrawn capacity on these facilities. And now, with respect to our marketing efforts.

We do attempt to mitigate some of the volatility in commodity prices with the risk management program. Our second quarter 2015 crude oil hedge position amounts to approximately 33% of our net WTI exposure, with 31% fixed at USD 87 per barrel.

The unrealized financial derivatives gained with respect to our WTI hedges at March 31, 2015, was approximately $105 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 development 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 our balance sheet with the equity financing. And as I mentioned earlier, our 2015 program remains flexible and allows for adjustments to second half capital spending, based on changes in the commodity price environment.

And 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.

And 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.

Just a few questions here for you. Lot of discussion, obviously, around oil pricing.

So just wondering what kind of pricing signals you would be looking for as you think -- 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. I'll 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 60s, I would look for Baytex to adjust our capital downward to maybe forego some of the capital spending we have in our current plan in the second half of the year, and that's an estimate at this point.

But just kind of some of the markers that we've talked about openly as we put together our capital budget, leading on to the vision we made in February. And likewise, on the other side of that, if you see oil move up towards $70 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's outlined right now, it's probably the way we look at that and there's probably somewhere in the middle there between those 2. We'll have to look at things and take a look at each well we're drilling, and the incremental economics.

our cash flows at the time, differentials are also going to affect it. Exchange rate will affect it somewhat.

And we do have a few other moving pieces that go into those calculations. But in general, that's how we're 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.

So just focusing on Gemini for a second. I understand what you're saying and the actions you've taken there.

But what kind of pricing outlook, may be 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 obtained from that pilot is kind of all in the bank. And the #1 key piece of information is, we've got a good reservoir there that flows vertically and can -- in a higher price environment, with the steam flood, can be produced in paying quantities.

So that's -- there is a lot of other information we got out of it, but the reservoir indication was the most important in the performance. So moving on from that to your -- directly your question.

To be quite frank, we've been very open about our plans with thermal. They've shifted back substantially, with not only the lower commodity priced environment, but in addition, the change in our portfolio to a good inventory across our 3 key areas of conventional primary development and very, very high capital efficiencies.

So it's been a couple of things that have shifted that. But we would probably need to get back into an $80 or higher $90 environment before we would see sanctioning further thermal projects including Gemini.

Okay. Last pressing 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 to that level or are you going to wait until prices change?

Mark, how we thought about that is, prices are -- have been extraordinary low, and how we've looked at is there -- while there may be the potential for a single geopolitical event or production declines in primarily the U.S. shale plays to be sticky for a while, there are some negative things that can come out and maybe depress the prices further from a very short-term perspective.

But it's unlikely that we would see a sustained level under $50 for years on in. So as we thought about that, there isn't a whole lot of downside further below the low kind of into the 40s for sustained periods.

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

And again, there's 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.

And 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 mid-60s, 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 the difference for the company. And it's pretty consistent.

So we've just started in the last few weeks to get into the 60s, today you can put on a hedge at over $65 for '16, I'm talking about U.S. dollars here, by the way.

And you've seen it feather very small amounts in at that stage. And if prices gradually continue to increase, we will probably do a little more of it.

Just a couple of 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?

Well, the Lower Eagle Ford is, obviously, productive across all of it. The Chalk is at this stage is about 50% of it.

And the other layers, the upper portion of the Lower Eagle Ford and Upper Eagle Ford itself are really just getting to find as we go through some of the testing this year. So you've heard some of the results today that we've got of our 30-day IPs that came out in the first quarter from one of our stack and frac pilots.

You'll be hearing more of that. So we really are in the process in 2015 in defining really the all -- all 3 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's probably a little further expansion that it could happen over time.

But the middle portion of the Eagle Ford that we're testing here in 2015, is really the year to get it to bind, if you will. So we haven't quoted a number yet on what portion of our Upper Eagle Ford -- our acreage has been defined over.

Okay. And finally, do you expect the Eagle Ford to be self financing this year?

Mark, it depends on -- you're going to have to go through the math on that. We've got low capital -- we've got really high capital efficiencies and low development costs, but -- are you talking $40 deck, $60 deck, and $80 deck, $70 -- you're talking -- --

Well, basically based on your views and planning, that's all.

Yes, probably not quite, I would think. But I'm talking off the top of my head.

We're little less self-funding all year long with everything in, but we don't have much in Canada, so that's probably a fair assessment at this stage.

Jim, I was just wondering if you might be able to elaborate a little further on the Eagle Ford and its evolution as you look at the interplay between Chalk and the Upper and the Lower? How should we think about the inventory implications for you as we look ahead here?

I guess, I would point to our year end disclosure on reserves is the best indicator of that. Last year, when we concluded the acquisition, we thought at that point, we had 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 -- or 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. So as time has gone on here, the potential for this has certainly grown in our minds.

And that's probably the best way to reflect this. Just go, look straight at the number of locations that we got in, what we call 2P proved and the 3P.

We've quantified it as best we can at this stage, which has grown substantially since we first took a look at this in 2014.

Great, I appreciate that. And then 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?

Thanks, Pat. Not really.

There are some minor variances between individual wells across the entire acreage position for sure. And there's variances across the liquids window from the volatile oil to retrograde condensate.

But you're 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're pretty close to each other within the same liquids or PVT window, if you will.

Jim, just 2 quick questions here. Just on the stack and frac pilots, that 4-well pad.

Do you have any more of those planned? Or are you currently working on any more of those in Q2 and beyond?

Yes, we do, Tom, yes. We've got several plans throughout the year.

So each quarter we'll 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 modes. So you don't bring individual wells any longer, you essentially bring on the entire pad when all 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.

Okay. So I guess my -- let me rephrase my question.

Then the pad that you're going forward now, will have the multi-zone potential mainly, or will you be still just targeting the Lower Eagle Ford in some of those pads?

No, we'll 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.

So you'll see, it's probably 50% or 60% of Lower Eagle Ford and the other 40% to 50% in that range will be a mix of the other layers mixed in with Lower Eagle Ford. So we'll get a good series of tests as time goes on and that's the approximate numbers.

Okay, sounds good. And then just finally, with the WCS desk coming in, and obviously, the improvement in WTI.

I guess, 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're looking at it right now as WCS -- as we moved into driving season, this is the time of the year where that crude gets exceptionally high in demand. You've seen it trade inside of single-digit netbacks here -- excuse me, single-digit differential, so we're in around $8 differential to WTI right now.

So that certainly helps. And WTI moved up towards the low 60s on a spot basis, that certainly helps.

And it depends on what the operating expenses were, I mean, some of the production was single-digit netback at $90 oil, but it was still making positive cash flow. So some amounts will not come back on until we get probably with cost reductions back up in the 80s.

So it will feather back in here as -- if prices continue to improve and if they don't, some of that will remain shut in. So it's just going to depend on price.

So parts of it we are looking at right now.

Thank you, Donna. And thanks, everyone, for participating in our First Quarter Conference Call.

Have a great day.