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 a listen-only mode and the conference is being recorded. [Operator Instructions] I would now like to turn the conference over to Brian Ector, Vice President of Capital Markets for opening remarks. Please go ahead.

Thanks 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 am joined today by our executive team: Ed LaFehr, our President and Chief Executive Officer; Rod Gray, Executive VP and Chief Financial Officer; Kendall Arthur, Vice President of Heavy Oil; Chad Kalmakoff, Vice President of Finance; Chad Lundberg, Vice President of 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’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 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 Eagle Ford. 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 netback of $17 per BOE, up from $6 per BOE in Q2 2020. And we delivered adjusted funds flow of $79 million or $0.14 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 BOEs per day to 82,000 BOEs per day. And we continue to focus on annual capital spending of $260 million to $290 million, an approximate 50% reduction from our original plan of $500 million to $575 million. As I mentioned at the…

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 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 totaled approximately $1.07 billion and have a maturity date of April 2, 2024. These are not borrowing base facilities and do not require annual or semi-annual reviews. Based on the forward strip, we expect to maintain our financial liquidity and remain onside 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 options structure on 24,500 barrels a day that at current oil prices give Baytex WTI plus US$760 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 for further details on our hedge program going to 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 intentionally 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 wealth in the years ahead. And with that, we – 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.

[Operator Instructions] Our first question comes from Manav Gupta with Credit Suisse. Please go ahead.

Hey, guys. Congrats on the good quarter and a free cash flow. I’m trying to understand you still have about 5,000 barrels curtailed in heavy and the heavy to WTI’s trade is below 10. So, 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 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 your – 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.

[Operator Instructions] The next question comes from Greg Pardy with RBC Capital Markets. Please go ahead.

Yes, thanks. Thanks. Good morning. Ed, could 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 as I say, well goes back up to $50, $55 or so. Is there a lot of durability, because you’d have to do with people or how would you frame them?

Yes, 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 that’s exactly where we are now. We delivered a great quarter to $11.08. So that’s where we’ve been historically, but it’s – 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 its 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 a hundred 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 the 2021 is 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 we’re producing today.

Okay. And Ed, when you refer to the volume, I mean obviously, like volume – 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 of 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. We’ve – 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 the Eagle Ford, Viking, Canadian heavy and even natural gas is, what would get first call directionally given what you see heading into 2021, right?

Right. Yes. 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 Eagle Ford, second call would be Viking and the third, but also important call on some capital 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 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 it’s 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, 70,000 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 and 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 the last one for me, I mean, you touched on the two Duvernay, so I guess testing in November, but can you flesh out what the game plan is there. obviously, 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 cost. What do you think you need to drive those well costs down for this play ultimately become competitive?

Yes. 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 rates 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 costs for these two wells have come in above $8 million each, which is higher than the seven, but their 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 $7.5 million 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. So, if we can achieve these costs that we’re talking about and demonstrate those now, and announce those hopefully, and 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, we have to – 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 leave the play. And we’re really excited about it, Greg, but stay tuned on it. So, let’s get through these rates and get these wells online, get you an IP 30.

Thanks. 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 2022. 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?

Yes. 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 to being on-site those covenants well past 2021.

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 – get 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 doing 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 delever. 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 bow like, commodity price and future commodity price combined with a strong hedging book before we would 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 O'Rourke with ATB Capital Markets. Please go ahead.

Hey, good morning guys. very comprehensive discussions so far. you’ve actually discussed a lot of the things I wanted to ask 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 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 of 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 and this risk-based approach to monitoring wells, stripper wells in this environment don’t matter as much as they do in a $80 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 from, 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 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 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 $1 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 Eagle Ford. So, as we take the foot off the gas on capital, it’s nowhere near as revealing to the – 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 multistage fracing of the Eagle Ford and the Viking.

And as you guys have been reactive here on the heavy oil side and shut-in, subeconomic 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 wrapped, I would say we ramp it down a little bit less than some of the other areas, and didn’t pull these shut it in. We wanted to maintain some steaming in there and make sure we didn’t get any unwanted effects in the sub-surfaces, as we say. but we’re largely, just flowing through our multi-lake horizontals, and it’s fairly straightforward to shut them in and bring them back without seeing any water coning or any, 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 – 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. 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 draw on that line if you want it to reduce to that?

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.