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Good morning. My name is Anes, and I will be your conference operator today. At this time, I would like to welcome everyone to the MEG Energy 2021 Second Quarter Results Conference Call. [Operator Instructions]Mr. Derek Evans, CEO, you may begin your conference.
Thank you, Anes, and good morning, everyone, and thank you for joining us to review MEG Energy's second quarter operating and financial results. In the room with me this morning are Eric Toews, our Chief Financial Officer; Chi-Tak Yee, our Chief Operating Officer; and Lyle Yuzdepski, our General Counsel and Corporate Secretary. I'd like to remind all of our listeners that this call contains forward-looking information. Please refer to the advisories in our disclosure documents filed on SEDAR and on our website. I'll keep my remarks brief today and refer listeners to yesterday's MD&A, financial statements and press release for more detail. MEG continues to proactively respond to the safety challenges associated with COVID-19 and remains committed to ensuring the health and safety of all our personnel and the safe and reliable operation of the Christina Lake facility. I want to commend our teams for the outstanding diligence and focus that they've exercised in helping to ensure that the health and safety of all our employees and contractors remains a top priority. MEG had a strong second quarter from both a financial and operational perspective. On the financial side of the business, we benefited from both the strength in the global oil market dynamic as well as the structural invented heavy oil differentials. We remain very constructive that these changes will persevere and that the headwinds we've battled over the last 6 years with respect to egress and weakness in oil prices will abate and become tailwinds, that will continue to drive significant free cash flow from our low decline, low-cost asset base. On the operational front, the second quarter was another strong quarter for MEG, giving us the confidence to increase our full year 2021 production guidance, begin the work to bring the Christina Lake facility back up to full capacity and reinitiate debt reduction. Our strategy remains unchanged. We remain focused on executing on our capital program as efficiently and as effectively as possible, continuing to work on all of our cost structures and using free cash flow to reduce debt. Second quarter financial and operating highlights include: adjusted funds flow of $166 million or $0.53 per share, impacted by our realized commodity price risk management loss of $87 million; quarterly production volumes of 91,803 barrels per day at a steam-oil ratio of 2.39; net operating costs of $5.54 per barrel, including nonenergy operating costs of $3.84 per barrel; power revenue offset energy operating costs by approximately 60% in the quarter, resulting in a net impact of $1.70 per barrel; sale of noncore industrial lands near Edmonton for cash proceeds of $44 million; total capital investment of $70 million in the quarter directed to sustaining and maintenance capital, resulting in $96 million of free cash flow in the quarter and $153 million of free cash flow in the first half of 2021. In June 2021, MEG along with 4 other oil sands operators who collectively represent 90% of Canada's oil sands production formed the Oil Sands Pathway to Net Zero Alliance to work collectively with the federal and Alberta governments to achieve net 0 greenhouse gas emissions from oil sands operations by 2050. Subsequent to the end of the quarter, MEG issued a notice to redeem USD 100 million of MEG's 6.5% senior unsecured second lien notes due January 2025. MEG realized an average AWB blend sales price of USD 56.41 per barrel during the second quarter of 2021 compared to USD 48.39 per barrel in the first quarter. The increase in average AWB blend sales price quarter-over-quarter was primarily a result of the average WTI price increasing by USD 8.23 per barrel. MEG sold 45% of its sales volumes into the premium-priced U.S. Gulf Coast market in the second quarter of 2021 compared to 38% in the first quarter. Inclusive of the noncore $44 million asset sale, MEG generated approximately $200 million of cash in excess of invested capital in the first half of 2021. Of this amount, the corporation will direct an additional $75 million to MEG's 2021 capital investment program. This $75 million of capital investment represents the majority of the estimated $125 million of incremental well capital necessary to allow the corporation to fully utilize the Christina Lake facility's oil processing capacity of approximately 100,000 barrels a day, prior to any impact from scheduled maintenance activities, turnarounds or outages. The estimated $125 million total cost is less than MEG's previous estimate of $150 million due to year-to-date field-wide production outperformance resulting from increased steam utilization, improved field reliability and completed an ongoing well optimization and recompletion work. This year-to-date outperformance provides the confidence for the company to increase full year 2021 average production guidance from 88,000 to 90,000 barrels a day to 91,000 to 93,000 barrels a day. MEG expects to invest the estimated $50 million of remaining incremental well capital required to return the Christina Lake facility to full utilization in the first half of 2022. Based on this level of incremental capital investment, the corporation expects to be able to fully utilize the oil processing capacity at its Christina Lake facility in the second half of 2022, post the planned turnaround at MEG's Phase 2B facility in the second quarter of 2022. Turnaround, which is scheduled for May of 2022, is currently expected to impact full year '22 production by approximately 5,000 barrels a day. MEG announced yesterday that the corporation has issued a notice to redeem USD 100 million of MEG's 6.5% senior secured second lien notes due January 2025 at a redemption price of 103.25% plus accrued and unpaid interest to, but not including the redemption date. Redemption is expected to be completed on or about August 23, 2021. Based on the current commodity price environment, MEG anticipates generating approximately $275 million of free cash flow in the second half of 2021, which will be directed to further debt repayment. Based on better-than-expected production performance in the first half of 2021, MEG is revising its full year 2021 average production guidance to 91,000 to 93,000 barrels a day. We're increasing the 2021 capital program by $75 million to a full year 2021 CapEx budget of $335 million as we add incremental well capital to return the Christina Lake facility to full utilization. G&A expense is now targeted to be in the range of $1.65 to $1.75 a barrel and nonenergy operating costs are now expected to be in the range of $4.40 to $4.60 per barrel. As I bring my remarks to a close, I again want to thank our team at MEG for their commitment, perseverance and hard work through these exceptionally challenging times. I'm proud of our performance and confident in our ability to continue this momentum throughout 2021. Looking ahead, we remain confident in our ability to continue to execute on our business plan and remain committed to sustainable, innovative and responsible energy development. We look forward to updating you on our progress in the coming quarters. With that, operator, we'll now open the line for questions.
[Operator Instructions] Your first question comes from Phil Gresh with JPMorgan.
First question here just around the CapEx plans. Is there a way to think about the 2022 CapEx all-in at this point? Obviously, you're spending the incremental $50 million of the growth capital, which is actually less than this year's $75 million of growth capital, but maybe some color around sustaining CapEx or just all-in thoughts. I know it's a little bit early.
It is a little bit early. So anything I say has got major error bars around it. But Phil, we generally talk about sustaining CapEx starting at about $300 million in any given year. So I think at this stage, and it's very early on, we're really looking at something in that $350 million range. So $300 million is sustaining, plus the incremental $50 million that we will need to invest as we bring that facility back up to full utilization.
Okay. Got it. And then on the production side, obviously, you continue to have strong performance this year, and then you're going to be ramping up to the full amount. But I was just curious if through the experiences of this year, if you might actually be able to debottleneck even a bit more than 100,000 barrels a day given you're already tweaking up into the low 90s?
Phil, it's a good question. A lot of the work that is being done is being done on the field side as opposed to the facility side. So it's really continuing to ensure that we're getting full utilization of all the steam that we're creating out of the field -- out of the facility, that would be the facility component, but also making sure that the field is operating at as close to 100% reliability and availability as we possibly can. And then there's a significant component to our production outperformance that we've seen year-to-date, which really is continued work on downhole or subsurface side of the business where we're seeing significant improvements and some exciting technological innovation.
Okay. My last question would just be with your free cash flow you're talking about for the second half. I think you're pretty rapidly approaching the interim target leverage that you've talked about. So any additional thoughts you'd have on capital deployment opportunities in 2022?
Phil, I can take you back to last November when the -- and how quickly our business changes in the last 6 months. We haven't given a huge amount of thought to where we might be in the middle of next year, which is really what I think you're alluding to that we could have enough free cash flow to have met that USD 500 million for stopping off point in terms of debt reduction. It's important to us, obviously, to execute on that and we'll be delighted when we get there. But I think the one thing that I would want our listeners to take away is that we are committed to debt reduction, continued debt reduction. And even though we're going to get to that target, looks a lot sooner than we had originally thought, you should expect that incremental free cash flow after that will -- there's a disproportionate amount will go towards debt reduction.
Your next question comes from Greg Pardy with RBC Capital Markets.
Yes. Maybe to follow up a little bit on what Phil is asking. Could you frame what the plan is for the balance of the year, Derek, maybe just in terms of like well pairs? It sounds like all of this is just going to be in the field. You've already got capacity at the plant.
So Greg, thanks for the question. It's really business as usual, and it will be more well pairs. All of this work, the 2B, 2X facility is now up and running. So we've got our incremental boiler capacity and the steam and we're now going to utilize that steam on to help us get back to that full facility utilization on the oil production side of 100,000 barrels a day. So all of the work now is really directed towards incremental well pads.
Okay. Terrific. And then with -- let's just assume Line 3 is on at the end of the year. What does -- or is the expectation then that you'll be able to fully utilize your access to the Gulf Coast next year [ a lot earlier ]?
Well, why don't I let Eric take that one.
Yes, Greg, I think once Line 3 comes on, we expect a portion to be less than 20%. That's sort of a consistent message we've had. What that is under 20%, don't know, but that would be the application against 100,000 barrels a day, and our plan remains to get as many barrels as we can down to the Gulf Coast. We're still making premium dollar on those, we're selling in Edmonton. So we will continue to get -- work to get as many barrels we can down the Gulf Coast.
Okay. And last question for me is, obviously, the big announcement, the Pathways to Net Zero, there's a consultation period going on. MEG is a part of this quintet. Just any thoughts around that process, what this means? Pretty open-ended question, but interested.
So this is an unprecedented alliance among 5 oil sands companies that represent 90% of the production, but it's not just the oil companies. This alliance is working collectively with both the federal and the provincial governments to try and get carbon capture and storage and greenhouse gas emissions reductions, 68 million tons per annum of CO2 sequestered or abated by 2050. Big deal, huge project, unprecedented level of sort of commitment and working together collaboratively to make this happen. The first stage of this is a very important enabling piece of infrastructure, a 400-kilometer pipeline from Fort McMurray all the way down to Cold Lake, where the sequestration of this CO2 is going to happen. This is a bold plan. It's bold action. And I would -- this is something that we all believe. I'm speaking for everybody that's involved in this alliance, it's something that we need to get done and get done as quickly as possible. And it will be very exciting to get this first stage of this project up and running with this enabling pipeline and storage facility.
We have the following question from Neil Mehta with Goldman Sachs.
Congrats on a strong start to the year. So I just wanted to build on the question around the Western Canadian oil macro. How do you think about differentials, Derek, as you get into 2022? You have a bunch of OPEC barrels coming back to the market. But at the same time, you have Line 3. Do you see the curve as relatively fairly priced? And then to build on that, on the flat price broadly, do you think about -- how do you think about hedging '22? The curve is decently backwardated here, but how do you think about managing risk?
Neil, thank you for those questions. I'm going to ask Eric Toews to take both of those.
Just first on the hedging piece. As Derek said, we're refining our 2022 steam capital. And when we look at the supply-demand fundamentals for 2022, our current intention right now is not to hedge 2022 benchmark WTI prices. And on the differential side, the -- I guess, talking about the current differentials and the current apportionment on the mainline, which I'll get to that point about 2022, we saw an obvious 54% apportionment on the mainline. That's actually as far as we know, a record apportionment on the mainline. What's interesting about that though is inventories in Western Canada went down in May from 38 million barrels down to 35 million barrels. Rail is running less than 100,000 barrels a day. And the post-apportionment market in August is trending sort of below $2 off the index, which is at the low end of sort of the historical range of apportionment pricing. So when we think about differential, what you're seeing in the market is the pricing in Edmonton versus the Gulf Coast is still within pipeline economics, which makes sense given the narrative I just went through. As we move through this year, we start to see differentials for the back end of this year at about $13.50 to $14 in Edmonton, that's WCS differential. And then as we go into next year with Line 3 coming on in Q4, which is our expectation, we expect apportionment to drop below 20%. So we would see differentials should tighten against what we're seeing for the back end of this year. But your point about Saudi barrels coming on, a lot of that's going to be heavy. So we would expect to see differentials maybe gap up a little -- maybe $1, $1.25 on the back of that. So net-net, we still see differentials in 2022 in that sort of $13 to $14 range.
That's great. And then just following up on Greg's question about decarbonization here. One of the areas that seems like it could be particularly successful in Western Canada would be carbon capture and sequestration. Can you talk specifically about whether that's an opportunity for MEG? And as you think about financing any projects, is it best to be done within your existing house? Or is the optimal financing structure a tracking company or an independent company outside MEG, if that makes sense, Derek?
Very interesting question. Let me start with the first part. So carbon capture and storage is the single biggest lever we have to decarbonize today. You're familiar with MEG's history in reducing intensity, greenhouse gas intensity and our sort of leading sector performance in that regard. You should expect that as we start to look at finding ways to decarbonize that, that same sort of innovation and execution will prevail. And we will be finding -- looking and finding ways to do that cheaper and faster as we get this enabling piece of infrastructure, the pipeline from Cold Lake down to -- or from Fort McMurray down to Cold Lake and the sequestration facility in place. The -- it's -- there's lots of challenges around the financing of this. The sequestration -- not the sequestration, but the capture part is the most expensive part of this. And we have yet to look at what the most optimal way of financing this is. I'd say we're looking and hoping for some degree of support from both federal and provincial governments to help us get started on the learning curve on this. But it may make sense for us to use a different vehicle that will be able to attract green financing to the sequestration part of this as opposed to utilizing the existing MEG sort of capital structure.
Your next question comes from Dennis Fong with CIBC.
Maybe just to follow on the lines of what Phil Gresh was discussing at the very beginning of the question period. When we think about the focus on debt repayment, how should we be thinking about the potential, I guess, immediate allocation towards repaying additional tranches of your term debt, especially as we think about free cash flow allocation beyond the end of this year into '22 and beyond? And I have a follow-up.
Dennis, it's Eric Toews speaking. The way -- we've been pretty consistent with the messaging around that. And what we look at is a number of things with respect to debt repayment. Firstly, how restrictive the covenants are; secondly, the term of the debt; and thirdly, the price of the debt. So I think you'll see us continue to do that as we look at further debt repayment.
Great. And then just maybe on Derek's comments with respect to some of the improvements that you're seeing in well performance as well as the focus on downhole optimization. Can you maybe talk towards how that could potentially impact sustaining CapEx costs, especially as we look into the back half of next year, once you've ramped back up to 100,000 barrels a day? I know you indicated around $300 million is the number that you have prescribed as being traditional and sustaining CapEx. But can you maybe discuss some of the items that could drive that number potentially lower, especially with some of the well performance that you're seeing more recently with the optimization that you've seen kind of at the beginning of this year?
So I'm going to ask Chi-Tak to talk a little bit about the optimization work that we've been doing and whether that's going to grow or -- but -- and then I'll jump on and talk about how we're going to -- how that's going to impact the macro at the sustaining capital level.
Yes. It's Chi-Tak Yee here. So a few things that really got us the better production this year and Eric, I think, spoke to most of them already. The main thing, obviously, we have a very great, good planned reliability this year as well as the uptime has been quite strong. The other thing that we spend a lot of time is to work on the downhole aspect of these wells. As you know, these wells are very long. So the real key part is to get the whole well bore contributing to production, and we've been doing the work both on the producer and also on the injector to optimize that production and the steam injection performance. And we're also trying some newer completion technique for some of the new wells going forward and try to promote that type of performance, the realm of performance even faster than we have seen historically. So that obviously have indication on how many well pads we need going forward on a capital sense. Do you want to comment on the -- yes, go ahead.
Sure. Thanks, Chi-Tak. So as we think about this notional $300 million that we -- is our sustaining CapEx, there's a lot of puts and takes in it. So I think what Chi-Tak talked to and provided you some color on is some excellent work that we're doing on the subsurface side, ensuring that we're spreading the steam as uniformly across the reservoir and improving not only the rates, but the recovery factor. The one big piece though that we need to be thinking about and are spending some time working on is really the inflation impact. As we drive forward, we're seeing services starting to -- the cost of services increasing. And we think that the potential impact for inflation will have a much bigger impact on that $300 million sustaining capital program that -- than some of the improvements that we're making. So currently, we're estimating it somewhere in the neighborhood of potentially 10% of the capital program. So we're trying to refine that number. But that is going to be one of the big drivers that we haven't seen for a long time as we move forward next year.
There are no further questions at this time. Mr. Evans, you may proceed.
Thank you very much, operator, and thank you, everyone, who joined us on the call this morning. I hope you all have a great day, a great weekend and enjoy their remaining summer. And we look forward to updating you again on our progress at our next conference call with the -- or with the release of our third quarter results. Take care, everybody. Be safe.
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.