Baytex Energy Corp.

Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corporation third quarter 2020 results conference call. As a reminder, all participants are in listen-only mode and the conference is being recorded. After the presentation, there will be an opportunity to ask questions. To join the question queue, you may press star then 1 on your telephone keypad. Should you need assistance during the conference call, you may signal an operator by pressing star and zero. I would now like to turn the conference over to Brian Ekster, 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, Ed LaFerre, our President and Chief Executive Officer, Rod Gray, Executive VP and Chief Financial Officer, Kendall Arthur, Vice President Heavy Oil, Chad Kalmakoff, Vice President Finance, Chad Lundberg, Vice President Light Oil, and Scott Lovett, 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 laws. I refer you to the advisories regarding forward-looking statements, oil and gas information, and non-GAAP financial and capital management measures in yesterday's 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 am 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 minimized 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 COVID 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 averaged 77,800 BOEs per day as compared to 72,500 BOEs 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 Eagleford. Our third quarter production was reduced by approximately 5,000 BOEs per day due to voluntary shut-ins. Exploration and development spending totaled only $16 million during the third quarter. We generated an approximate operating net back of $17 per BOE, up from $6 per BOE 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 80,000 BOEs per day, which represents the midpoint of our guidance range, 78,000 to 82,000 BOEs per day. And we continue to focus on annual capital spending of $260 to $290 million, an 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 costs down to $11.08 per BOE, despite lower production volumes. This compares favorably to our guidance range of $11.75 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 for BOE. We've 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 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 two Duvernay 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 at Pembina O'Cheese to drill natural gas wells with strong economics and capital efficiencies and have two wells planned to be on stream this winter. This activity set is all included within our capital spending guidance range for this year. I will now turn the call over to Rod to discuss our balance sheet and risk management.

Thanks, Ed, and good morning, everyone. A key priority for us 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 U.S. dollar. As of September 30, 2020, we had $426 million of undrawn capacity on our credit facilities, resulting in liquidity net of 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 2, 2024. These are not borrowing-based facilities 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 WTI-based fixed price swaps on approximately 8,000 barrels a day at US $43 per barrel, and a three-way auction structure on 24,500 barrels a day that at current oil prices give Batex WTI plus US $7.60 per barrel. In addition, we have started to layer in hedge protection for 2021. To date, we have added protection at US $45 WTI on approximately 30% of our expected 2021 exposure. We have also WTI MSW differential hedges on approximately 40% of our expected 2021 Canadian light oil production at US $5 per barrel and WCS differential hedges on approximately 45% of our expected 2021 heavy oil production at a WTI to WCS differential of approximately US $13.50 per barrel. 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 Ed for some concluding comments.

Okay, thanks, Rod. 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 Reinish 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 ESG will serve the board and Baytex well in the years ahead. And with that, 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. You will hear a tone acknowledging your request. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star then two. We will pause for a moment as callers join the queue. Our first question comes from Manav Gupta with Credit Suisse. Please go ahead.

Hey guys, congrats on the good quarter and the free cash flow. I'm trying to understand you still have about 5,000 barrels curtailed in heavy, and the heavy to WTI spread is below 10. It's, I think, $9, and the outlook for heavy is pretty bullish. So just wondering, like, is there a way you could bring back those barrels, and what's the reason of keeping them curtailed when the spread is so low?

Well, you bet, Manav. Thanks for the question. 5,000 was for 3Q. Since that time, we've brought on some additional barrels, and we've actually said that right now we've only got about 2,000 barrels a day curtailed. So we've done exactly what the intent of your question is. We continue to layer on these shut-in barrels and have continued since the beginning of the summer. But we've now got all of our production on outside of 2,000 barrels a day, which really requires probably $45 WTI, consistent level of 45 WTI. But I agree with you on the differentials being tight. And our ability to hedge those differentials throughout the summer and through to today has allowed us with confidence to bring on those heavy barrels and increase our margin on it. Thanks. Appreciate the question.

Perfect. Thank you for taking my question.

Once again, if you have a question, please press star then 1. The next question comes from Greg Pardee with RBC Capital Markets. Please go ahead.

Yeah, thanks. Thanks. Good morning. Ed, can you talk maybe just a bit about the durability of the operating and G&A cost as you look into, I don't know, 2021 and even with, let's just say, well, it goes back up to 50, 55 bucks or so. Is there a lot of durability because these 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 taking action along the way. We've been about an $11 barrel OPEX company now for the last several years, and that's exactly where we are now. We delivered a great quarter at $11.08. So that's where we've been historically, but there are increasing cost pressures in various parts of the business, obviously, so we've been offsetting those with tremendous performance and change. So the things that we've talked about are of the $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 we've altered the shifts in the field, the way that we've 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 it's labor, but not all of it. So we have seen unit rates come down on some transportation and processing, for example. We've renegotiated some contracts here and there. And there are some other smaller aspects. But furloughing 100 and 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 2021's coming along and we'll get to that here shortly. I think some of those cost savings will stick and others have come back and will continue to be there with the higher volumes we're producing today.

Okay. And Ed, when you refer to the volume, I mean, obviously your volumes have come down over the course of this year, but I think you're just talking about the merger, just the consolidation you guys went through a couple years ago. Is that it or?

I'm talking primarily about the volumes that have come down from Q1 at 95,000 barrels a day, kind of where we've been down to 75,000 barrels a day today. So it's about a 20,000 barrel a day reduction. With the capital reduction, our business now is sized at around 75,000 barrels a day. So that is the framework also that I can speak to going into 2021 as well.

Okay. Okay. The second is, and I know you're alluding to a budget to come, but with an extra dollar of capital, how does that cascade then amongst Eagle for Viking, Canadian Heavy, and even natural gas? What would get first call directionally given what you see heading into 21?

Right. Yeah, if you asked me the question two weeks ago, I would have said that $45 or $40 to $45, we could sustain the business at 75,000 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 would be 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 into early December where we will approve our budget with the board and then announce it. But we're looking at a $40 sort of a framework today. And in that framework, we still believe we can, 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 it's a pretty good page in there that a lot of people are asking us about, but it shows a $40 case. And yes, we can sustain the business around Q4 exit rates, 70 to 75,000 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 a strategic appraisal well that we want to drill up in the Peavine 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 Eagleford and the Viking in current pricing levels and we would not capitalize the heavy.

Okay, understood. And just the last one for me, I mean, you touched on the two Duvernay wells, so I guess testing in November, but can you flesh out what the game plan is? There are huge limitations in how much capital you can allocate to it, but the other part of the equation is just the $7 million well costs. What do you think you need to drive those well costs down for this play ultimately to become competitive?

Yeah, we're doing a lot of work on that as well. It's a very good question that Chad Lundberg 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 1,000 BOEs 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 $7 million. And I can tell you now that the cost for these two wells have come in above $8 million each, 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 and 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 drilling wells below $8 million. Call it between $7.5 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 it's economic at $50 WTI, but not economic today at $40 WTI. So if we can achieve these costs that we're talking about and demonstrate those now and announce those hopefully in the 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 WTI prices rise towards that $50 range, we would have a highly economic program we could go after. The good news here also is that we hold our lands up through 2022. But in 2022, regardless, we'll have to drill a couple of wells to hold some key lands. But we've got over 200 sections of contiguous lands and a big position there. It looks like we and Crescent Point, I believe, will be the public companies that lead the play. And we're really excited about it, Greg, but stay tuned on it. Let's get through these rates and and get these wells online. Get you an IP30.

Thanks very much, Ed.

The next question comes from Jason Mandel with RBC Capital Markets. Please go ahead.

Hey, guys. Good morning. Thanks for taking the questions. Just wanted to get maybe a little bit of an update on the covenants. It sounds like the last we understood that in a 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 the oil markets and dropping down to the high 30s to mid 30s. What's kind of the sensitivity on that in terms of like timeframe of comfort around covenants with regard to moving oil prices?

Yeah, 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-30s and then popped back to whatever we are today, $38 a barrel. In this capital framework that I just talked about, we speak to remaining onside with financial covenants through 2022 at $40, as you said, and sustaining the business and maintaining our liquidity. But let me turn it over to Rod to talk about sensitivities below that.

Thanks for the question, Jason. Right now, we currently model that WTI 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 so we're currently not anticipating oil to be $34, so we'd see line of sight being on side those covenants well past 2021. Okay.

Okay, very good. And then if I could just ask one follow-up in terms of potential thoughts around liability management. How do you guys think about the balance of liquidity versus debt reduction, discount debt reduction opportunities? And then any thoughts around sort of limitations around capability of doing such?

Good question. I'd say there's 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 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 Ed has alluded to, we have 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 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'd need a stronger commodity price and future commodity price combined with a strong hedging book before we were to undertake any of those types of activities. Thank you very much for the thoughts. Appreciate the question. Thanks, Jason.

The next question comes from Patrick Oroki with ATB Capital Markets. Please go ahead.

Hey, good morning, guys. Very comprehensive discussion so far. You've actually discussed a lot of the things I wanted to ask on on capital allocation as well as the bonds there, but maybe I'll ask a little bit of follow-up. You talked about furloughing workers. Sounds like that would be more of a variable cost on the heavy oil side. Wondering if If these assets aren't able to compete for capital in the current environment, is there any potential risk on those operating cost improvements that you guys have been very, very strong on here?

Well, it's a good question, Patrick, and we have spent a lot of time on it. The furloughing of that 100 people that I mentioned, not all those people are coming back to deliver the production that we're delivering today. So it's a new way of operating both in heavy oil and in light oil in terms of altering the shifts in this risk-based approach to monitoring wells. Stripper wells in this environment don't matter as much as they do in an $80 a barrel environment. So it's a risk-based approach and it's one that a lot of the industry is shifting to, but we think we're doing a great job in that regard and we're keeping safety and environment right at the top of the queue. So I would start there. Are there any other comments? Rod, would you like to elaborate?

Patrick, it's a fair question. I think what we do is we continue to monitor all our margins 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 in, so that does mitigate some of that exposure. I would say that generally tends to be our higher operating cost properties that get 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 production. So on a dollar-per-barrel basis, I think we're probably okay, but we're going to continue to monitor that, and we will shut in production if it is not covering its variable operating costs.

And just to add to that one last point, the decline rate in heavy oil is a lot lower than Viking or Eagleford. So as we take the foot off the gas on capital, it's nowhere near as revealing to an 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 horizontal multi-stage fracking of the Eagleford and the Viking.

And as you guys have been reactive here on the heavy oil side and shut in, you know, sub-economic production here and there and brought it back on, are you seeing any reservoir impacts or is the reservoir performing as you would have expected?

All these wells come back fine. We've done this over the years. We drill and complete wells. These aren't tied into large facilities. The one I would highlight is Kerrobert. We have one SAGD operating project down in south central Saskatchewan. And we have to be a little more careful with how we ramp that down. So we ramped, I would say we ramped down a little bit less than some of the other areas and didn't fully shut it in. We wanted to maintain some steaming in there and make sure we didn't get any unwanted effects in the subsurface, as you say. We're largely just flowing through our multi-leg horizontals. It's fairly straightforward to shut them in and bring them back without seeing any water coning or 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 what I would say is a really good slide in the deck that lays out kind of the guideposts in terms of capital allocation, spend, production, et cetera, that's on page 10 there. 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 draw on that line if you wanted to reduce the debt?

Patrick, it's Rod. We do have the ability to buy back bonds if we want. There are limits to the amount that we could purchase and qualifications that have to be in place in terms of debt to EBITDA ratios prior to exercising those. 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 the presenters for any closing remarks.

Okay, great. Thanks, Anastasia. Thanks, everyone, for participating in our third quarter conference call. Have a great day.

This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.