Baytex Energy Corp (BTE) 2016 Q1 法說會逐字稿

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

Thank you, Melanie. Good morning, ladies and gentlemen and thank you for joining us today to discuss our 2016 first quarter 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 regarding forward-looking statements, non-GAAP financial measures and oil and gas information contained in today's press release. All dollar amounted reference end in our remarks are in Canadian dollars unless otherwise specified and I would now like to turn the call over to Jim.

Thanks, Brian, and good morning, everyone. Today I will discuss our results for the first quarter of 2016 and how we will continue to meet the challenges brought on by this low oil price environment. I will also discuss how we remain focused on prudently managing our operations to maintain strong levels of financial liquidity.

I will break my comments in four parts for you today. First I will talk about our first quarter operating and financial results, second, I'll provide an update on our balance sheet and financial liquidity, third, I will provide an update on our marketing and lastly I will review our plans for 2016.

Our operating results for the first quarter were consistent with our expectations and reflect a reduced pace of drilling activity. Production averaged approximately 75,800 BOEs per day during the first quarter as compared to 81,000 BOEs per day in the fourth quarter of 2015. This rate was slightly ahead of our Q1 guidance of 73,000 to 75,000 BOEs per day, which is largely attributable to our continued strong drilling results in the Eagle Ford.

Capital expenditures for operations and development activities totaled CAD82 million and we participated in the drilling of 13.5 net wells with 100% success rate. As we had previously indicated we proactively shut-in approximately 7500 BOEs per day of predominantly low or negative margin heavy oil production during the quarter in order to optimize the value of our resource base and maximize our funds from operations. In the Eagle Ford we produced just over 41,000 BOEs per day during the first quarter, an increase of 2% from the fourth quarter of 2015, and up 5% from the third quarter of 2015. Our pace of development in the Eagle Ford was largely unchanged during the first quarter with approximately six rigs and one frac crew working on our land. During the quarter we commenced production on 34 wells in the Eagle Ford, of which 19 wells established an average 30 day initial production rate of 1300 BOEs per day.

On the capital side we have now achieved an approximate 32% reduction in the well costs in the Eagle Ford, with wells now being drilled and completed and equipped for about $5.6 million US as compared to $8.2 million in late 2014. We continue making significant advancements and delineating the multi zone development potential of our Sugarkane acreage. We have implemented stack and frac pilots which target up to three zones in the Eagle Ford formation in addition to the overlying Austin Chalk formation and we currently have 13 of these multi-zone projects in various stages of execution and production. In Canada, our production averaged approximately 35,000 BOEs per day in the first quarter as compared to about 41,000 BOEs per day in the fourth quarter. The reduced volumes in Canada reflect the impact of the production that was shut-in and the fact that there has been no heavy oil drilling since the third quarter of 2015. We generated funds from Operations of CAD56 million or CAD0.22 per share during the first quarter. Excuse me, CAD46 million.

I think everyone on the line today is very well aware of the difficult pricing environment we faced during the first quarter and this is reflected in our first quarter netbacks. On a corporate basis, our operating netback in the first quarter was CAD5.82 per BOE or CAD12.29 per BOE including financial derivative gains. With our exposure to heavy oil our Canadian operations generated and operating loss of CAD0.77 per BOE while the Eagle Ford generated an operating netback of CAD11.41 per BOE.

During the quarter we continued to focus on cost reduction initiatives across all of our operations. Operating expenses in Canada decreased 19% on a per BOE basis as compared to the first quarter of 2015 despite the impact of fixed costs on lower production volumes. Transportation expenses in Canada have been reduced by 40% on a per BOE basis as compared to the first quarter of 2015, due to the ongoing optimization within our trucking division and decreased fuel costs.

On the corporate side our G&A was CAD14.2 million in the quarter as compared to CAD17.1 million in the first quarter of 2015. This decrease is primarily a result of cost reductions to staffing levels to coincide with lower levels of activity, combined with reductions in discretionary spending. As a continued cost control measure all full time employees salaries and all annual retainers paid to our directors were reduced by 10% effective March 1, 2016.

And now for a little more color on our financial liquidity. Total long-term debt at the end of the quarter was CAD1.83 billion, down from CAD1.88 billion in December -- at December 31, 2015. Our long-term debt is comprised of a bank loan of CAD290 million and senior unsecured notes of CAD1.54 billion. On March 31, we announced amendments to our bank credit facilities that provide us with increased financial flexibility. The amendments including reducing our credit facilities to 5 -- to $575 million US dollars, granting our bank lending syndicate first priority security with respect to our assets, and restructuring our financial covenants. It is important to note that these facilities are not borrowing based facilities and do not require annual or semiannual reviews. There are no mandatory principal payments prior to maturity in June of 2019 and the maturity date can be further extended with the consent of our banking syndicate. With this revised agreement we expect to realize savings of approximately CAD8 million in 2016 from lower interest expense and standby fees. As that March 31, 2016 our senior secured debt to bank EBITDA ratio was 0.6 to 1 and our interest rate coverage ratio was 0.48 to 1 on a 12 -- on a trailing 12-month basis, both ratios well within the allowable range. With these amendments to our bank facilities we expect to have adequate liquidity and financial flexibility to execute our business plan.

Now with respect to our marketing efforts for the balance of 2016 we have entered into hedges on approximately 44% of our net WTI exposure, with 17% fixed at approximately $62 US per barrel and 27% hedged using a three-way option structure. We have also entered into hedges on approximately 38% of our net heavy oil differential exposure and 58% of our net natural gas exposure. For 2017 we have entered into hedges on approximately 28% of our WTI exposure, utilizing a three-way option structure. We have also entered into hedges on approximately 8% of our net heavy oil differential exposure and 32% of our net natural gas exposure. You can find the details around our hedging programs in today's press release. The unrealized financial derivative gain with respect to our hedges as of April 26, 2016 was approximately CAD54 million.

So in summary, during the quarter we continued to meet the challenges brought on by this low oil price environment. We announced amendments to our bank credit facilities that provide us with increased financial flexibility, and we shut-in our low or negative margin heavy oil production. Importantly, we continue to direct the vast majority of our expiration and development dollars to the Eagle Ford which generates the highest rates of return and the highest netbacks in our portfolio. Our operating results in the Eagle Ford were strong during the quarter, with production up 2% over the fourth quarter of 2015 and well costs continuing to decline.

Our 2016 production guidance is unchanged at 68,000 to 72,000 BOEs per day with budgeted expiration and development exemptions of CAD225 million to CAD265 million. In 2016 we are targeting capital expenditures to approximate Funds from Operations in order to minimize additional bank borrowings. Our 2016 program will remain flexible and allow us for adjustments to spending based on changes in the commodity price environment. We remain well-positioned to benefit from an oil price recovery as our three core plays provide some of the strongest capital efficiencies in North America.

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

Thank you. We will now take questions from the telephone lines. (Operator Instructions). The first question is from Greg Pardy of RBC Capital Markets. Please go ahead, thanks.

Thanks. Good morning. Jim, the CAD5.6 million D&C cost in equipping that you mentioned how much of that would be equipping?

Oh, very little. Probably CAD400,000 to CAD500,000 of that is equipment, about 5% of the overall cost.

Okay. Okay. Great.

So about 55% completions and 5% equipping of the CAD5.6 million and the remainder, roughly 40% is drilling costs.

Okay. Great.

It varies from well to well a little bit, Greg, but those are approximate estimates.

Okay. Perfect. Because they were just some ridiculously low numbers that were known out earlier today so it's just interesting to compare. Just with Eagle Ford then is your sense that you'll just kind of maintains flat oil and liquid production there generally this year just given the program that you have got in place? On a quarter to quarter basis?

Yes. I mean on a quarter to quarter basis. Greg, it does come off a little bit -- we will be at a little bit more of a reduced pace throughout the rest of the year. We came into the year with completions that were based on the kind of the six rigs we were running through early first quarter and the latter part of last year. That number is probably coming down to five rigs as we move in and maybe even four throughout the second and third quarters as prices got softer in the first quarter. So it might come off a little bit and we did have some extremely good wells. Our average production rates were kind of in the 1000 to 1100 BOEs a day range and these wells were around 1300 or a little better than that. In particular we brought on one pad, the Foster pad, and that averaged over 1350 BOEs per day per well, which was -- which was pretty good. So I wouldn't look to have it be quite as high as it was this quarter.

Okay. Okay. Thanks for that. And then you just flagged in the release that there's been a little bit of an alteration just in terms of your processing agreement where I think you're getting a better realization but essentially it's just being offset in the OpEx? Could you talk about that?

Yes. It's really just a change in the -- in the procedure of how it's being handled with about CAD1 increase overall impact on -- on revenues and about CAD1 increase impact on operating expense. So it's a net wash.

Okay. Okay. Great. What is the spending profile then look through the balance 2Q, 3Q and 4Q? Just trying to get an understanding of what that might look like.

Greg, repeat the question again. We were breaking up just a little bit.

Oh, yes. Sorry, Jim. I'm just trying to get a sense of what your CapEx program looks like through the second, third and fourth quarter.

It's probably going to step down a little bit as we -- as we lower the pace just a little bit from the first quarter and we had a few more completions tailing in from the fourth quarter. So I would imagine it will step down and -- so if you take our actuals that he we spent here and use kind of the mid-point of our -- our overall range, you come up with a lower average for the three quarters. And it's pretty balanced Q2 through Q4.

Okay. Perfect. And last two for me. Maybe just a question for Rod. What is your thinking just around cash taxes this year?

Fairly minimal actually. We're looking at recovering some of the taxes that we did pay in 2015. So looking for recovery of about CAD7 million to CAD10 million for the year.

Okay. Great. And last one is just in the release you just flagged some minor asset dispositions. Is there anything underway, [data rooms]. What have you. Right now or is that to come?

No. We really don't have any -- anything that's coming out right away, but we have continued to look at potential sales of some minor non-core properties throughout time and we'll probably continue to do that. It's a pretty bad market right now to be in, Greg, and I -- I really don't want to speculate beyond what I have already said.

Okay. That's perfect. Thanks very much, guys.

You bet. Thank you.

Thank you. The following question is from Dennis Fong of Canaccord. Please go ahead.

All right. Good morning, gentlemen. I just will a quick question on the shut-in volumes. As I recall at the last quarter you were expecting to bring some of those volumes back on partway through the year. Now that we have seen a bit of recovery in the oil price environment, is that still the plan and are there any changes to production guidance? Thanks.

Yes. Dennis, our overall production guidance hasn't changed for -- for the year. Having said that, we are looking at bringing on some of the heavy oil production that was shut-in as we're up substantially from where we were in the first quarter. the first quarter averaged $33 WTI US and we're sitting today at about $43 to $45 per BOE so there -- we're taking a look at it right now and there probably will be some moderate acceleration and when we bring that back online, if prices hold in here. And we would -- we would look to target the -- the most profitable first as you could expect so it will probably be staggered in here throughout the next couple of months if prices hold up. And I would expect to have most of it back online by the beginning of July, with some of it possibly coming online here in May.

Most of the 7500 BOEs a day or as I recall I think there's a little bit associated with Gemini which I wasn't...

No, no, no.

Come back on-stream.

No, no, no. Gemini was shut-in last year. That's not in the 7,500.

Okay.

We put in this year.

Okay. Perfect.

You got that wrong, Dennis.

All right. Thank you.

You bet.

Thank you. The following question is from Patrick Bryden of Scotia Bank. Please go ahead.

Morning, gentlemen. Thanks for taking my calls. Just a couple of quick ones for me. If we try to think about the down spacing of the inventory from 80s to 60s to 40s can you maybe just elaborate for us how you're seeing differences between say incremental versus acceleration?

Yes. Pat, it's -- we're really looking at it differently than the -- the original plan as of a couple of years ago. Because these other layers that we hadn't anticipated to have developed in the upper Eagle Ford, the upper portion of the lower we thought there might be some potential in the chalk and it turns out there's quite a bit of potential in the chalk. So you know the down spacing is happening vertically as well as horizontally, so I would almost need to spend a little bit of time with you and take you through the session and get into the details. But suffice it to say that if you look at our reserve disclosure the total number of potential locations that are did that you add up in P2, P -- or 3P, 2P and the contingent is -- is upwards of 600 remaining locations between all those categories. And when we originally purchased this, we thought it might be -- might stretch to 250 remaining locations across all those categories. So we'll spend some time and get into the spacing because it's not just happening on drilling in between wells. We're drilling above the existing wells in what we believe are shale or ash barriers to find virgin portions of the reservoir and that's really how we're conducting it as we move forward.

Great. Appreciate that. And then maybe if you can just elaborate for our benefit on some of the latest innovations you are seeing on completions in the Eagle Ford. I understand there is fiber fracs and soluble wormhole hydrocarbon effects at play. Any thoughts?

Yes. We're implementing some of those and have been using fiber fracs for quite a while and for those of you who may be listening that don't know it's -- the intent of it is to -- is -- it lowers the overall liquid volume that you put in and the sand volume because the fiber dissolves and the frac is held open by the proppant and the dissolved portion leaves what are believed to be open fairways to the -- from the -- out in the reservoir down through the fractures to the wellbore and enhanced productivity and we continue to use that across quite a few of our fracturing treatments as -- as we continue to -- to develop it and we're continuing to run tests on it as well.

Great. Appreciate that. Just last question is -- I mean always hard to say where the commodity is going to go, but if we see buoyancy down the piece here at what point do you bring components to shut-in volumes back and at what point do you start investing at [indiscernible] again?

In terms of bringing things back like I just mentioned to the previous question, we'll -- we are looking at it right now. We're at the point to where some of the most lower OpEx production that we have shut-in is -- is probably viable -- is clearly viable at these levels above $40 a barrel. So we will be bringing on about 10% of the -- of that production here probably in May and -- and on in through the rest of the -- the -- before we get into the third quarter.

Great. Thank you.

You bet, Pat.

Thank you. The following question is from Sean Sneeden of Oppenheimer. Please go ahead.

Hi. Good morning. Thank you for taking the questions. I guess some of your E&P peers throughout North America have actually been raising a good bit of equity in order to fund CapEx and de-lever their balance sheet. I guess given the rise in -- in oil prices how are you guys thinking about that as a potential tool in your tool box to try to -- to de-lever your balance sheet as you go through the year?

Yes, Sean. At the stages we're at today we don't see that -- that has an option for us at this time so I don't want to get into speculation of when it would or wouldn't be, but we don't see it at this time.

Okay. That's fair enough. I guess maybe thinking about de-leveraging in a different light given that some of your bonds are trading at a decent discount would you are look to repurchase any of them in the open market or are you relatively comfortable with the -- your leverage profile as we go along here.

Yes. We're comfortable with our leverage profile where we're at today, Sean. So I -- we don't have any current plans for that either.

Okay. And then maybe just lastly when do you think about -- or what do you need to see in the forward curve here before you start layering in additional hedges I guess more so for 2017? Is there a specific price point or anything like that that you guys are really thinking about or you want to see first?

Sean, we could hardly hear you. Could you -- were you asking about when we would start layering in hedges?

Yes. That's right. I mean I guess in particular is there a certain price point that you guys are looking for, especially for 2017, that you would feel comfortable layering in additional hedges at this point?

Yes. You can take a look at the -- the best example I can give you is if you take a look at where we were as we reported our fourth quarter results to where we are today, we have layered in additional 2017 and we're kind of targeting that range in using three-way so we can participate in an upside to above $55 or almost near $60. So most of our -- all of our three-ways next year allow that and kind of set a floor if prices are above $35 set a floor for us at around $40, $45 a barrel. And that's kind of the -- that -- that change in the additional hedges we have laid on kind of lays out the plan of when we're doing that. So it's -- it's kind of a target of trying to participate in an upside to $60 while providing some protection in the mid $40s range is really what we have been doing, and so as -- as we have had these various increases in -- in price as it spikes and those are allowable to be put on, we will put a few popular on as we continue to go through the year. And of course if it moves up to where we might get -- let's say we going to towards the fourth quarter towards where we could do a 40/50/60 or a 45/55/65 or something like that, you would want to try to push those upward as you went forward as well.

Okay. That's helpful. Thank you very much.

You bet, Sean.

Thank you. The following question is from Gary Stromberg of Barclays. Please go ahead.

Hi. Good morning.

Morning, Gary.

Two questions. One on G&A. Are there any non-recurring charges in the first quarter? Is that CAD14.2 million in cash G&A a good number going forward?

It could be a good number to use.

Yes. Effective March we did have a 10% refresh your recollection in -- in salaries and in Board retainer fees so it will probably be a little off that, Gary, as we go forward.

Okay. Helpful. And then can you give us a sense on maintenance capital how you think about holding 41,000 barrels a day of Eagle Ford and then I guess it's 35,000-barrels a day of Canada production [indiscernible].

Yes. As we talked about that in the past and we're probably not far off in the capital we're spending today in the Eagle Ford to hold it flat. It will vary and be very lumpy because we bring on large pads so there's periods where you have a month or so that you don't have any wells come online and then you will bring an entire pad on, but throughout a year it's close to that CAD200 million or plus range for just the Eagle Ford.

And then if you look at Canada and we could take you through the math if you want to get with Brian afterwards, Gary, but in general we think about CAD100 million a year would keep Canada flat and, of course, you can balance the two differently. You could also spend less in Canada and more in the Eagle Ford, but you are probably in that kind of a range close to with our capital efficiencies if you it the math off of our published materials to get you into that range of about CAD300 million.

Okay. That's of helpful. And then final one for me is -- is level of oil price you would need to see to return the shut-in production.

Yes. Gary, it's -- we're getting to that level now. So we're investigating it right now. On average as we said when we shut it in it was low margin or negative margin and, of course we only averaged $33 WTI in the first quarter and that was about close to breakeven with the entire mix that we had. And so as we get north of $35 to $38 a barrel it's probably breakeven, but it costs a little bit to bring it on. You want to ensure we feel comfortable prices aren't going to drop back not low $30s again so we have kind of said once we get into above $40 and we think it might be sustained and here towards $43, $44 we're taking a good hard look at it right now and have intention to start bringing some of the most profitable back on in May with tapering more in in June if things hold.

Okay. Great. Thank you.

Thanks, Gary.

Thank you. There are no further questions registered at this time. Actually I'm sorry. We do -- I will now turn the meeting back over to Mr. Ector.

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

Thank you.

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