Q3 2020 Baytex Energy Corp Earnings Call
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Thank you for standing by its just the conference operator.
Welcome to the Baytex energy Corp. third quarter told you 20 adult calls I'd call.
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I would now like to turn the conference over to Brian Ector, Vice President capital markets for opening remarks. Please go ahead.
Thank you Anastasia good morning, ladies and gentlemen, and thank you for joining us today to discuss our third quarter 2020 financial and operating results.
I'm joined today by our executive team and look where our president and Chief Executive Officer, Rod Gray Executive VP and Chief Financial Officer.
Handle Arthur Vice President heavy oil John Kaelle, Mcauley, Vice President Finance.
Lumber Vice President of light oil and Scott Love It our vice President of corporate development.
While listening please keep in mind that some of our remarks will contain forward looking statements within the meaning of applicable securities law.
I refer you to the advisories regarding forward looking statements oil and gas information and non-GAAP financial and capital management measures in Yesterdays press release.
All dollar amounts referenced in our remarks are in Canadian dollars, unless otherwise specified and with that I would now like to turn the call over to Ed.
Thanks, Brian and good morning, everyone I'd like to welcome all of you to our third quarter 2020 conference call I'm very pleased with the tremendous progress we have made to reset our business in the face of extremely volatile crude oil markets.
As we highlighted last quarter, we responded aggressively to the downturn brought on by COVID-19, as we minimize capital spending identified cost savings and maintained our liquidity.
And our third quarter results demonstrate the success of our actions as we generated free cash flow of $60 million and increased our financial liquidity to $344 million.
I'm also especially pleased with our response to the covert pandemic with intensified efforts to improve all aspects of our cost structure and capital efficiencies, while protecting the health and safety of our personnel.
Production during the third quarter average 77800 Boe per day as compared to 72500 BOE per day in Q2 2020, the higher production reflects the restart of previously shut in volumes in Canada, partially offset by lower activity in the Viking and in the Eagle Ford.
Our third quarter production was reduced by approximately 5000 Boe per day due to voluntary shut ins exploration and development spending totaled only $16 million during the third quarter we.
We generated on a product at approximate operating netback of $17 per BOE, we up from $6 per BOE. We in Q2, 2020, and we delivered adjusted funds flow of $79 million or 14 cents per basic share.
For 2020, we expect production to average approximately 80000 Boe per day, which represents the midpoint of our guidance range 78000 to 82000 Boe per day.
And we continue to focus on annual capital spending of $260 million to $290 million and approximate 50% reduction from our original plan of 500 million to $575 million.
As I mentioned at the outset, we continue to emphasize cost reductions across all facets of our organization through the first nine months of 2020, our teams have driven operating cost down to $11, an eight cents per BOE, we despite lower production volumes. This compares favorably to our guidance range of $11.
75 cents per Boe to $12.50 per Boe.
As a result, we are reducing our full year 2020 operating expense guidance by 7% at the midpoint to $11.20 to $11.40 per Boe.
We have also improved our guidance on several additional cost assumptions for this year, which are highlighted in the press release, and all of which play a vital role in driving free cash flow in our business. I'm also excited that after two quarters of little to no capital spending in Canada, we have resumed drilling activity there.
During the fourth quarter in the Viking we have mobilized a completion crew to on stream 29 drilled but uncompleted wells by the end of this year and two drilling rigs to execute a 30, well drilling program and we have completed the to do Vinay wells drilled earlier this year both of which are in.
The core of our play and expected to be on production in November.
In addition, with the increase in natural gas prices, we have identified opportunities in west Central Alberta that Pembina O chiefs to drill natural gas wells with strong economics and capital efficiencies and have two wells planned to be on stream. This winter.
This activity said is all included within our capital spending guidance range for this year.
I will now turn the call over to Rob to discuss our balance sheet and risk management.
Thanks, Ed and good morning, everyone, a key priority for us during through this downturn has been to preserve our financial liquidity and our Q3 results demonstrate our success to date in this regard we generated free cash flow of $60 million and reduced our net debt by $89 million during the third quarter as the Canadian dollar strengthened.
Relative to the US dollar as of September Thirtyth 2020, we had $426 million of Undrawn capacity on our credit facility, resulting in liquidity net working capital of approximately $344 million.
This is up from approximately $300 million of liquidity at the end of the second quarter.
As a reminder, our credit facilities total approximately $1.07 billion and have a maturity date of April 2nd 2024. These are non borrowing base facility and do not require annual or semi annual reviews.
Based on the forward strip, we expect to maintain our financial liquidity and remain on site. Our financial covenants. In addition, our first long term note maturity of US $400 million is not until June 2024.
We also continue to manage our commodity price risk through an active hedging program for the fourth quarter of 2020, we have entered hedges on the majority of our net crude oil exposure. This is comprised of W. T date fixed price swaps on approximately 8000 barrels a day at us $43 per barrel and.
The three way auction structure on 24500 barrels a day that at current oil prices gives eightx W. T plus us 760 per barrel.
In addition, we have started to layer in head protection for 2021 to date, we have added protection at us $45 Wi Fi on approximately 30% of our expected 2021 exposure. We have also done.
W T MSW.
MSW differential hedges on approximately 40% of our expected 2021 Canadian light oil production at Usfive dollars per barrel and and WCS differential hedges on approximately 45% of our expected 2021 heavy oil production at a W. W.
Yes differential of approximately Usthirteen 50 per barrel for further details on our hedge program can be found in our third quarter financial statements and with that I'll turn it back over to add for some concluding comments. Okay. Thanks, Rob I believe our third quarter results demonstrate the benefits of our hard work in a low.
Oil price environment, we have responded decisively to reposition operating activity to maximize our cash flow and minimize the draw on our liquidity and we remain intensely focused on driving further efficiencies to capture and sustain cost reductions identified during this downturn, while protecting the health and safety.
Of our personnel.
Before concluding I would like to take a minute to welcome Steve Reynish to our board of directors. Many of you will know Steve from his time at Suncor and prior to that marathon oil, Canada, and Western oil sands, his strategic perspective, and tremendous breadth of experience across strategy corporate development marketing technology and DSG will.
Serve the board and Baytex well in the years ahead.
And with that.
Well I'll, just say that we are in the process of setting our 2021 capital budget. The details of which are expected to be released in December following approval by our board of directors.
So now I'll ask the operator to please open the call for questions.
We will now begin the question and answer session to join the question queue. You May Press Star then one on your telephone keypad.
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Our first question comes from Manav Gupta with Credit Suisse. Please go ahead.
Hey, guys congrats on the good quarter in a fee cash.
And you still have about 5000 bottoms curtailed in heavy and heavy WCS spread is below and citing $9 and the outlook for Haiti's pretty bullish. So just wondering like is there any you could bring back those battles and what's the reason of keeping them curtailed industry I guess so low.
Oh, you bet Manav. Thanks for the question 5000 was for Threeq two since that time, we brought on some additional barrels and Weve actually said that right now we've only got about 2000 barrels a day curtailed so weve done exactly what your the intent of your question is we continue to layer on.
Shut in barrels and have continued since the beginning of the summer, but we've now got all of our production on outside of 2000 barrels a day, which really requires probably $45 WT.
Consistent level of 45, W. I, but I agree with you on the differentials being tight and our ability to hedge those differentials throughout the summer and and through to today has allowed us with confidence.
To bring on those heavy barrels and increase our margin on it. Thanks. Appreciate your question.
Thank you for taking my question.
Once again, if you have a question. Please press Star then one.
The next question comes from Greg Pardy with RBC capital markets. Please go ahead.
Yes. Thanks, Thanks, good morning.
Ed can you talk maybe just a bit about the durability of the of the operating in and DNA cost as you look into I don't know 2021, and even with Asus say oil goes back up to.
50, 55 Bucks or so is there a lot of durability, because you'd have to do with people or how would you frame them.
Yeah, I would say Greg very good question, we've been thinking a lot about this and do taking action along the way we've been about $11 a barrel Opex company now for the last several years and Thats exactly where we are now we delivered a great quarter to $11.
Eight cents.
So that's where we've been historically, but it's there are increasing cost pressures in various parts of the business. Obviously, so weve been offsetting those with tremendous performance and change. So the things that that we've talked about are up to $100 million that we've now said are.
Assured for the year in terms of cost savings, 70% of those are volume related and 30% of those are cost reductions and of those 30%.
It would be too simple for me to say all of that is labor a lot of that is labor and the way weve altered the shifts in the field the way that weve optimized around a risk based approach to production.
So in other words changing the routes that the field operators go to and offering a bit more technology and support for them to enable those decisions. So fewer people are doing the same amount of work is what I'm trying to say a lot of its labor, but not all of it. So we have seen unit rates come down on some trends.
Rotation and processing for example, we've renegotiated some contracts here and there.
And there are some other smaller aspect, but furloughing 100, some people and not bringing them all back was a big big chunk of what we've seen in heavy oil in terms of the cost savings but.
The 2020 ones coming along and we'll get to that here shortly but.
I think.
Some of those cost savings will stick and others have come back and will continue to be there with the higher volumes for producing today.
Okay, and then when you refer to the bullion.
Let me now they see like volumes your volumes have come down over the course of this year, because I think you're just talking about the.
Merger, just the consolidation you guys went through a couple of years ago that in there.
I'm talking primarily about the volumes that have come down from Q1 at 95000 barrels a day kind of where we've been down to 75000 barrels a day today. So.
So it's about 20000 barrels a day reduction weve with the capital reduction our business now is sized at around 75000 barrels a day. So that is the framework also that I can speak to.
Going into 2021 as well.
Okay.
Second is is that I know you you're alluding to a bunch to come but.
An extra dollar capital.
How does that Cascades, and amongst Eagle Ford biking, hitting heavy in either natural gases.
What would get first call Directionally, given what you you see heading into 2001.
Right.
Yeah. If you ask me the question two weeks ago, I would have said that $45 or 40 to $45. We could sustain the business 75000 barrels a day and generate some modest free cash flow and we would be capitalizing all of our assets. So the first call would be Eagleford second call with the Viking and the third but also important call.
On some capital of around $50 million would be heavy oil we're not at $45. Today. So we're now in a very dynamic process heading in early December we will approve our budget with the board and then announced yet, but we're looking at a $40 sort of a framework today and in that framework, we still believe we.
And that in fact, when we came out of our strategy meeting in September with the board, we published in our IR deck, a page that outlines our capital allocation priorities and framework and its pretty good page in there, but a lot of people are asking us about but it shows a $40 case and yes, we are.
Can sustain the business around Q4 exit rate 70 to 75000 barrels a day operate within cash flow, but there would really be no excess cash flow in that case and there would also be no heavy oil development spending outside of the strategic appraisal well that we want to drill up in the P. Vijay.
Settlement.
So we would not have a meaningful heavy oil development. If we're in a $40 world versus a $45 world that would be the one that would fall off but the ultra high graded program in the Viking that's very very exciting is robust down to $40. So we would capitalize the eagle Ford and the Viking.
In current pricing.
Levels, and we would not capitalize the heavy.
Okay understood and just just the last one from me and you touched on the to do very well. So I guess testing in November can you flush out.
What the game plan is there obviously just.
Hughes limitations and how much capital you can allocate to it but the other part of the equation is just the 7 million dollar well cost what do you think you need to drive those well costs down for this play ultimately become competitive.
Yeah, we're doing a lot of work on that as well. It's a very good question Chad Lunberg here sitting next to me is working on with his team every day and as we're starting to flow back those wells today in fact.
We'll get rates here very shortly but we wanted to demonstrate repeatability of the rate the high rate that we achieved last year around 1000 Boe per day per well and 80% liquids. We felt like we needed repeatability of that effort, we saw last year as well as that line of sight down to seven.
$1 million and I can tell you now that the the cost for these two wells have come in above $8 million each.
Which which is higher than the seven but they're one off wells, we let them sit for six to nine months between the time. They were drilled completed we had some standby charges.
Excess diagnostics, a lot of extra well costs.
A bit of trouble time, we can now see line of sight on these on drilling wells below $8 million call. It between seven and a half to $8 million in a one off development mode. In a full development mode, where we're pad drilling and pad completing wells we've now.
Got line of sight to $7 million.
I think its economic at $50 Wi Fi, but not economic today 40. So if we can achieve these costs that we're talking about and demonstrate those now and announce those hopefully and a line of sight I'm talking to by the end of the year and repeat the rate.
Then we'll have a case to be made that as Wi Fi prices rise towards that $50 range. We would have a highly economic program. We could we could go after the good news here also is that we hold our lands up through 2022.
But but in 2022, we have two regardless will have to drill a couple of wells to hold some key lands, but we've got over 200 sections of contiguous lands at.
And a big position there it looks like we and Crescent point.
I believe will be the the public companies that lead to play and we're really excited about Greg but stay tuned on that let's let's get through these rates and get these wells online get you an IP 30.
Thanks, Thanks, very much and.
The next question comes from Jason.
RBC capital markets. Please go ahead.
Hey, guys. Good morning, Thanks for taking the questions just wanted to.
Again, and maybe a little bit of an update on.
The covenants it.
It sounds like the last we understood.
That any kind of a $40 environment, we were comfortable through 22 in the last week or two we've had a little bit of shakiness in oil markets and dropping down to the.
High Thirtys to mid Thirtys.
What's kind of the sensitivity on that in terms of like timeframe of comfort around covenants with regard to moving oil prices.
I'll take it at a high level and then turn it over to Rod Gray, who you know as well Jason Good question.
We have dropped down in the mid Thirtys, and then pop back to or whatever we were today 38 Bucks a barrel in.
In this capital framework that I, just talked about we speak to remaining on side with financial covenants through 2022, a 40 Bucks as you said and sustaining the business and maintaining our liquidity, but let me turn it over to Rob to talk about sensitivities below that.
Thanks, Thanks for the question Jason right now we currently model that W. T. I would have to average $34. During 2021 for us to see any pressure on our financial covenants and that would be to the end of 2021 and.
And so we're currently not anticipating oil to be $34. So we see line of sight to being on site those covenants well cost 2021.
Okay very good and then if I could just ask one follow up in terms of potential thoughts around.
Around liability management, how do you guys think about the balance of liquidity versus.
Debt reduction in discount debt reduction opportunities.
And then any thoughts around sort of.
Limitations around capability of doing such.
Good question I'd say there is no.
No shortage of advice out there on liability management transactions and what people are doing we're educating ourselves on all of those.
Right now we have two things that are working well in our favor and that is we have the tenor so our credit facilities and our long term bonds are not due until 2024 and we also have the liquidity and you'll see just outlined in our plans that had as alluded to we.
The ability to limit our capital going forward to make sure that we maintain that liquidity balance going forward, obviously into a higher price commodity environment, we're generating more cash flow and we're actually able to de lever there.
There are opportunities out there and people often ask us about capturing the discount on the bonds.
Ultimately, that's something that we balance.
Against our liquidity and our tenor and I think we need a stronger about like commodity price and future commodity price combined with a strong hedging book before we were to undertake any of those those that those types of activities.
Thank you very much and thoughts.
I appreciate the question Thanks, Jason.
The next question comes from Patrick Kealey with HCV <unk> capital markets. Please go ahead.
Hey, good morning, guys very comprehensive discussion so far you've actually I discussed a lot of things I wanted to ask on capital allocation as.
As well as the bonds, there, but maybe I'll ask a little bit of a follow up you talked about furloughing workers.
Sounds like that would be more of a variable cost on the heavy oil side wondering.
If these assets aren't able to compete for capital in the current environment is there any.
You know potential risk on those operating cost improvements that you guys have.
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Didnt very very strong on here.
Well its good question Patrick.
And we have spent a lot of time on the Furloughing of that 100 people that I mentioned.
Not all of those people are coming back to deliver the production that we are delivering today.
So it's a new way of operating both in heavy oil and light oil in terms of altering the shifts and this risk based approach to monitoring wells stripper wells in this environment don't matter as much as they do on a $80 a barrel environment. So it's a it's a risk based approach and it's.
It's one that a lot of the industry is shifting too, but we think we're we're doing a great job in that regard and we're keeping safety and environment right at the top of the Q. So I would start there.
Good.
Are there any other comments from the odd would you like to elaborate.
Patrick is it fair question I think what we do is we continue to monitor all our margins on.
Almost on a well by well basis and definitely by an area basis and make sure that we're generating positive margin. If the production is not sufficient to cover its variable costs, we will shut that production and so that does mitigate some of that debt that exposure I would say that generally tends to be our higher operating cost property.
That gets shut in so if you were looking at a dollar per BOE basis that gives you a little bit of protection to that but you are ultimately losing the.
The production so on a dollar per barrel basis, I think we're probably okay, but we are going to continue to monitor that and we will shut in production. If it is not covering its variable operating costs.
And just add to that one last point the decline rate in heavy oil is a lot lower than Viking or Eagle Ford. So as we take the foot off the gas on capital, it's nowhere near as revealing to the underlying decline as the other assets it's fairly resilient.
In the high teens versus kind of the decline rates that we have in the in the horizontal multistage fracking of Eagle Ford and the Viking.
Okay.
And as you guys have been reactive here on the heavy oil side and shut in you know some economic production here and there and brought it back on are you seeing any reservoir impacts or is the reservoir is performing as you would have expected.
All these wells come back or find we've done this over the years.
We drill and complete wells. These are tied into large facilities. The one I would highlight is corroborated.
We have one Sag D operating project.
Down in South Central Scotland, and we have to be a little more careful with how we ramped that down. So we ramped I would say, we ramped down a little bit less than some of the other areas and didnt fully shut it in.
We wanted to maintain some steaming in there and make sure we didnt get to the.
Any unwanted effects in the subsurface as you say, but were largely a.
Just flowing through our multi.
Multi leg horizontal wells and.
And it's fairly straightforward to shut them down and bring him back without seeing any water koning, earning any other kind of deleterious effects.
Okay, and maybe just shifting gears real quickly here.
Obviously, I don't think we're at a place where you're going to be executing on this today, especially with the you know what I would say is a really good slide in the deck that lays out kind of the guide posts.
In terms of capital allocation span production et cetera, that's on page 10 there.
But just curious is there anything.
In your bank credit facility agreement that would prevent you from buying back your bonds at a discount any sort of.
Limitations there are you free to to draw on that line. If you wanted to to reduce the debt.
Patrick its rod we do have the ability to buyback bonds that we won there are limits to the amount that we could purchase.
And and qualifications that have to be in place in terms of debt to EBITDA ratios prior to exercising no, but I would tell you that we do have the ability to buy back bonds today.
Okay. Thank you very much.
Thank you Patrick.
This concludes the question and answer session I would like.
To turn the conference back over to James.
Any closing remarks.
Okay, great. Thanks anesthesia, thanks, everyone for participating in our third quarter conference call have a great day.
This concludes today's conference call.
May disconnect your lines. Thank you for participating and habits I think.
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