Baytex Energy Corp.

Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corporation fourth quarter and full year 2020 financial and operating 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 Echter, Vice President, Capital Markets. Please go ahead.

Thank you, Sharice. Good morning, ladies and gentlemen, and thank you for joining us to discuss our fourth quarter and full year 2020 financial and operating results. Today I am joined by our executive team, Ed LaFerre, our President and Chief Executive Officer, Rod Gray, our 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. On the call today, we will also be discussing the evaluation of our reserves at year-end 2020. These evaluations have been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects to United States or other foreign disclosure standards. Our remarks regarding reserves are also forward-looking statements. 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 everybody to our year-end 2020 conference call. I am pleased that in one of the most challenging years experienced by our industry, we delivered on our commitment to preserve financial liquidity, capture cost savings, exceed our GHG emissions intensity reduction target, and generate free cash flow. The COVID-19 pandemic required a dynamic response to the oil price collapse, and our team delivered. In 2020, we reset our business in the face of extremely volatile crude oil markets and intensified efforts to improve all aspects of our cost structure and capital efficiencies while protecting the health and safety of our personnel. We are now benefiting from these actions as we are poised to generate meaningful free cash flow in 2021 and continue our deleveraging strategy. Based on the forward strip, we expect to generate over $250 million of free cash flow or 45 cents per share in 2021 and increase our financial liquidity to over $550 million. Before discussing our year-end results, I'd like to take a moment to comment on the most important asset in our organization, our people. Not only have our field and office teams prevented a COVID-19 outbreak anywhere in our business, they delivered volumes to market in a safe and efficient manner and flawlessly executed our programs. At times this winter, our teams faced unprecedented weather conditions in Alberta and Saskatchewan, with temperatures dropping to the minus 40 to minus 50 degree Celsius range. And as operating activity has ramped up over the past couple of months, we are grateful to all of our employees for their commitment and perseverance to operating safely and reliably through these challenging conditions. The health and safety of our employees and contractors has been and always will be our number one priority. Let's now talk about our results. In 2020, we reduced our capital budget by 50 percent and achieved cost savings of approximately $100 million. We produced 80,000 BOEs per day, 82 percent liquids, with capital expenditures of $280 million in line with our annual guidance. And we hit all of our cost targets with operating expenses averaging $11.35 per BOE, transportation expenses of 97 cents per BOE, and general and administrative expenses coming in under $1.20 per VOE. We generated free cash flow of $18 million and reduced net debt by $24 million. We also negotiated a bank credit facility extension and refinanced our long-term notes, both important measures undertaken to ensure our financial liquidity. Rod will elaborate on this in a few minutes. Our 2P reserves at year end total 462 million barrels of oil equivalent, and we maintain a strong reserves life index of 17.9 years. Our 2020 reserves report does reflect the impact of a materially lower commodity price forecast being utilized by our reserves evaluator, which has WTI down 20 percent from one year ago and not reflective of current spot oil prices. Consistent with the impairment we recorded in 2020, we removed 29 million barrels approved reserves, 65% heavy oil and bitumen, and 41 million barrels approved plus probable reserves, 80% heavy oil and bitumen, which were deemed uneconomic using the reserves evaluator December 2020 commodity price forecasting. At the same time, our future development costs have been reduced by $464 million on a 1P basis and $709 million on a 2P basis, partially due to the reserves being removed, but also due to improved capital efficiencies across our asset base with a significant improvement in the Eagle firm. As part of our core values, we are driven to safely and responsibly develop energy resources while reducing our environmental impact. In 2019, we established a target to reduce our corporate GHG emission intensity by 30% by 2021 relative to our 2018 baseline. We are pleased to announce that we have exceeded this target one year early, achieving a 46% reduction in our GHG emissions intensity through year-end 2020. This is an annual reduction of 1.6 million tons of CO2 equivalent and represents taking 340,000 cars off the road annually. Another key part of our culture is to continue to set the bar higher. We are now announcing a new target to reduce our corporate GHG emission intensity by a further 33% from current levels by 2025. This equates to an approximate 65 percent reduction by 2025 relative to our 2018 baseline. The entire organization is proud of our emissions reduction strategy, which includes gas conservation and combustion, reusing associated gas as fuel for activities, reducing emissions from storage tanks, along with monitoring and preventing fugitive emissions. We look forward to publishing our fifth corporate sustainability report later this year as we remain committed to progressing the environmental and social aspects of our business. I will now turn the call over to Rod to discuss our balance sheet and risk management.

Thanks, Ed, and good morning, everyone. As Ed mentioned, in 2020, we negotiated a bank credit facility extension and refinanced our long-term notes, which gave us the liquidity and and financial flexibility to manage the volatility experienced in 2020. Our credit facilities total approximately $1.03 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. These facilities contain two financial covenants, both of which we are well within as of December 31st. Our secure debt EBITDA ratio was 1.6 times at year end and is allowed to be up to 3.5 times. And our interest coverage ratio, which needs to exceed two times, was 3.9 times. As of December 31st, 2020, we held $367 million of undrawn capacity on our credit facilities, resulting in liquidity, net of working capital of $319 million. At current commodity prices, we expect to increase our financial liquidity to over $550 million in 2021. Now, the refinancing completed earlier in 2020 allowed us to redeem two near-term notes maturing in 2021 and 2022. Our long-term notes are now comprised of two outstanding issues. One, a $400 million tranche bearing interest at 5.625% due 2024, and a second US $500 million tranche bearing interest at 8.75% due 2027. Now turning to risk management. We maintain a consistent approach to risk management and marketing utilizing various financial derivative contracts and crude by rail to reduce the volatility in our adjusted fund flow. These contracts contributed approximately $50 million to our adjusted fund flow in 2020. For 2021, we have entered into hedges on approximately 48% of our net crude oil exposure, largely utilizing a three-way option structure that provides WTI price protection at US $45 per barrel, with upside participation to US $52 per barrel. We have also WTI to MSW differential hedges on approximately 50% of our expected 2021 Canadian light oil production, at US $5 per barrel and WCS differential hedges on approximately 50% of our expected 2021 heavy oil production at a WTI to WCS differential of approximately $13.30 US per barrel. We are also contracted to deliver 5,500 barrels a day of our heavy oil volumes to market by rail. Full details of our hedge program can be found in our year-end financial statements and are available on our website. And with that, I'll turn the call back to Ed to elaborate on our plans for 2021.

Okay, great. Thanks, Rod. In 2021, we will benefit from a disciplined approach to capital allocation, as I've mentioned, as well as our continued drive to improve our cost structure and capital efficiencies. Our high-graded capital program is focused largely on our high net back light oil assets in the Viking and in the Eagleford. In our Q3 conference call, we talked about how activity would be resuming during the fourth quarter, and I'm excited to see the operational momentum we are building as we execute our plan with current production over 78,000 BOE per day. In the Eagleford activity resumed in Q4 2020, with 7.1 net wells drilled and 2.7 net wells brought on stream. The remainder of the wells drilled in the fourth quarter are expected to be on stream in Q1 2021. We expect to on stream approximately 18 net wells in the Eagleford in 2021. In the Viking, we had previously suspended all drilling, and as such, there was limited activity from March through October. We resumed drilling in November with two rigs mobilized to execute a 30-well drilling program. In 2021, we expect to bring approximately 120 net wells on stream, including 43 net wells during the first quarter. On the heavy side, we have scheduled minimal development for the first half of 2021. As we come out of spring breakup, we intend to implement a drilling program in the second half of the year in which we could drill up to 30 net wells at Lloyd Minster and six net wells at Peace River. And we continue to prudently advance our Pembina DuVernay shale light oil play. Our most recent two wells were completed in October. The 10 of 16 well was brought on stream November 2nd and generated a 30-day initial production rate of 1,300 BOE per day, 69% oil. The 11 of 16 well was brought on stream November 17th and generated a facility-constrained 30-day initial production rate of 900 VOE per day, 68% boil. Based on early flowback results, these two wells demonstrate repeatability of our 1130 pad completed in 2019. We have the flexibility in 2021 to drill up to four net wells in the second half of the year. So let me conclude by saying We are executing our plan to maximize free cash flow and accelerate our debt reduction strategy. Our 2021 guidance remains unchanged as we target production of 73,000 to 77,000 VOE per day with exploration and development expenditures of $225 million to $275 million. And as I mentioned at the outset, we are building a strong operating momentum with current production over 78,000 BOE per day, and free cash flow pointing to over $250 million, with financial liquidity increasing to greater than $550 million. And with that, I will ask the operator to please open the call for questions.

Thank you. We will now begin the question and answer session. To join the question queue, you may press star, then 1 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 Greg Pardee with RBC Capital Markets. Please go ahead.

Thanks. Thanks very much. And thanks for the rundown, guys. A couple of questions. The first is, you know, the A&D market has definitely shown signs of falling of late. I'm just curious whether there's anything in the portfolio that you might consider selling to accelerate the debt reduction.

Yeah. We've talked about this before, and I would say we are always in the market looking and trying to understand opportunities in and around our core areas, so tuck-ins and bolt-ons on the acquisition side, and also selling assets that are not necessarily in our core areas. So, for example, I've mentioned our deep basin gas in the past. It's an attractive position with liquids-rich gas in a fair way that We drill one or two wells every couple of years to maximize facilities, but we are pretty well poured up in the three areas that we like, the heavy oil, cold flow, the Viking light oil, light oil in general in southern and central Alberta and Saskatchewan, and then in the Eagleford. So we do three things really well, and we're going to stay focused on that and those parts of the business.

Okay. Thanks, Ed. And then maybe just I'm wondering if you can remind me just where roughly your corporate decline rate would sit and then what does sustaining capital look like just in all these cost improvements that we've been able to go through?

Yeah, well, one of the benefits of not drilling new wells is the base becomes a higher percentage of the total production. And that's not necessarily a great thing, but it is where we came out of 2020 with with low activity. So our corporate decline rate moved from 34% down to around 30%, where we're seeing significant moderation of the declines or turning the decline around the decline curve in both the Eagleford and in the Viking, and our heavy oil is typically running in the 22 to 25% range. So, you know, overall, I would say our decline rates have moderated. That puts sustaining capital probably a little higher than where we are now. We can sustain ourselves by high grading opportunities, bringing ducks into the year from last year, and also reducing our cost structure to a certain extent. And we can probably hold production flat in this kind of 75,000 to 80,000 barrel a day range on our capital that we've shown this year, but only for a couple of years. So I would say sustaining capital, we need to run the numbers for next year, is probably running on the order of 275, you'd have to add probably $50 million to where we are this year. So maybe $300 million would be sustaining capital, somewhere in that range. Okay. Terrific.

Thanks very much.

The next question comes from Patrick O'Rourke with ATB Capital Markets. Please go ahead.

Hey, guys. Good morning. What a change from a year ago. We're talking about capital allocation choices here. I'm just curious. We heard from your operating partner in the Eagleford on their conference call the other day, what I would call emphatic capital discipline, and that I assume you have to fall in line with that. But now that you're thinking about potentially the upper end, of the capital budget of that 225 to 275, which is what it seems like it's angling to in your updated corporate deck here. I'm wondering how you're thinking about capital allocation throughout the rest of the portfolio. You talked about being cored up in your cold flow and your biking, where the DuVernay falls into that, and how you see the outlook for, call it any incremental spending versus the midpoint of the guidance for the rest of the year.

Yeah, well, we have a very phased and, I think, very disciplined approach to our strategy where clearly maximizing free cash flow has been the mantra for some time. So it starts with generating as much free cash flow as we can for now and sustaining the business around that 75,000 barrel a day range. So with the tailwind in oil price, We think that moves our financial liquidity, as we've mentioned, to $550 million. So with that, that's sort of a primary goal. Then we get line of sight to the 2024 bonds are not really an issue. And we've got plenty of runway before those come due anyway, and we would have ample liquidity. Our plan is to continue to delever. We've been very consistent with that strategy. Yes, we may have a few additional choices once we get through these initial steps, but we're very tenaciously focused, I would say, equally to our operating partner down south, that this is going to be about disciplined capital and maximizing free cash flow, certainly for the foreseeable future.

And it's safe to assume, based on those comments, that any free cash flow, at least within the near and medium term, is just going to be directed to the balance sheet?

Yeah, building that liquidity, as I mentioned. So we don't have an issue with the 2024 bonds. I think that's first priority. It does not mean, and I think maybe in the back of your question there is we'll never be able to get to things like the DuVernay. Not true. We think two to four wells this year in the DuVernay are quite possible and likely in our plan. They are in our plan. And there's no reason we couldn't allocate more of the capital that we set out to sustain the business in the following years to grow that production. So that's a choice we'll have. Eagleford is putting on a few more wells this year than last year, at least on our AMIs there. Viking is going to hold pretty flat around this new level of 18,000, 19,000 barrels a day. So I think we're pretty comfortable there. But there's no reason that DuVernay cannot grow some within our capital framework going forward.

Okay. And then maybe just a really final question here in terms of the sustaining capital. You touched on it with Greg there. But did I hear that correctly, that we should be thinking, you know, a number sustaining in that 75 to 80 range? that would keep ducks neutral year over year and allow a little bit of DuVernay spending in somewhere in the 325 range from an organic basis?

Yeah, I think that's a real good way of thinking about it, Patrick. Very good.

Okay, perfect. Thanks a lot.

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

Hey, guys. Thanks for taking the question. It sounds like a bunch of us are along the same path on the Q&A, so just a little bit further clarification. If I recall some conversations from several months ago and maybe even as much as a year ago that the desire was or that there was a little bit more flex upwards in the capital spending budget or hope in the event that we got oil prices to continue to move higher, whereas in the presentation materials it looks pretty clear that that CapEx is going nowhere at higher oil prices. Can you just kind of flip that? Has there been a change in thinking, or am I thinking about that wrong?

I don't think there's been a change in philosophy around being rigorous in our capital program. I do think we've also stated that during spring breakup we will take a pause, as we always do, and look at where we are on capital production, oil price, the macro, and look at what we want to do. And we've got, you know, trending towards 225 now, but we've got an additional $50 million ready to be spent in heavy oil where the margins look extremely attractive right now. And we're well hedged on the differential and have some really good contracts coming out on rail now out of Peace River, which help. So heavy oil is going to look very, very attractive on the current set of numbers that we've pretty well got locked in visibility to. And likewise, as I mentioned, the DuVernay is sitting out there that we do want to further de-risk and further prove up our track record such that we can move into more of a full-scale development mode in the future. So those things are sitting there, and that moves us to high end of guidance at the $275 million level. But those decisions will be taken in around the April-May timeframe for second half of the year. And I think we, yeah, I think I'll leave it at that. We will look at 4Q and exit rate and what we want to bring into 2022, how we want to position for 2022, also starting in spring breakup, but then we kind of wrap up our strategic planning and annual planning exercise by September, and we'll go from there. We'll see if these macro prices hold. It seems structural to us. We expected some positive tailwinds around the macro, but this has exceeded our expectations, so we need to factor that in as well. Great. Very helpful.

Thank you. And then just two quick follow-ups, clean up. The $250 million free cash flow expectation, I don't know if maybe I missed it, but did you give a price act that is based on for oil and for diffs?

Yes, we did. It's in the document. It was based on a couple of days ago. But, Brian, do you have that handy? It's $58 WTI and $12 differentials on the heavy side and $4 MSW differentials. So it's kind of where we were on the spot a couple, three days ago.

Got it. Thank you very much. And then just lastly, the build-in liquidity, just definitionally, that means using the free cash flow towards paying down Revolver and then putting yourself in a position to have the Revolver capacity to deal with the 24s in the event that there's a need to do that. Is that the right thought process?

Yes.

That is correct. Very good. All right. Thank you very much. Thank you.

This concludes the question and answer session. I would like to turn the conference back over to Brian Echter for any closing remarks.

Thanks, Charisse. Thanks, everyone, for participating in our year-end 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.