© 2024 Alpha Spread Limited. All Rights Reserved.
www.alphaspread.com is not operated by a broker, a dealer, or a registered investment adviser. Under no circumstances does any information posted on www.alphaspread.com represent a recommendation to buy or sell a security. The information on this site, and in its related newsletters, is not intended to be, nor does it constitute, investment advice or recommendations. The information on this site is in no way guaranteed for completeness, accuracy or in any other way. In no event shall Alpha Spread Limited be liable to any member, guest or third party for any damages of any kind arising out of the use of any content or other material published or available on www.alphaspread.com, or relating to the use of, or inability to use, www.alphaspread.com or any content, including, without limitation, any investment losses, lost profits, lost opportunity, special, incidental, indirect, consequential or punitive damages. Past performance is a poor indicator of future performance.
You don't have any saved screeners yet
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good morning. My name is Miranda. I will be your conference operator today. At this time, I would like to welcome everyone to the MEG Energy 2021 Third Quarter Results Conference Call. [Operator Instructions]Thank you. Mr. Derek Evans, CEO, you may begin your conference.
Thank you, Miranda. Good morning, everyone, and thank you for joining us to review MEG's third quarter operating and financial results. In the room with me this morning are Eric Toews, our Chief Financial Officer; Lyle Yuzdepski, our General Counsel and Corporate Secretary; and Darlene Gates, our Chief Operating Officer. Darlene joined MEG in September, and we're very pleased to have her on our leadership team. I'd like to remind 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 press release for more detail. MEG continues to proactively respond to the safety challenges associated with the COVID-19 pandemic. Our priority of maintaining safe and reliable operations at the Christina Lake facility remains a top priority. I want to thank our teams for their diligence and focus as we've operated throughout the pandemic. MEG had an exceptional third quarter from both the financial and operational perspective. We benefited from both the strengthening global oil market as well as the improvement in heavy oil differentials. Our team's focus on plant reliability, steam utilization and ongoing well optimization have contributed to a strong operational quarter. Third quarter financial and operating highlights and corporate developments include the appointment of Darlene Gates to Chief Operating Officer in September 2021. And Darlene joined MEG from ExxonMobil and brings 26 years of domestic and international industry experience to MEG. Chi-Tak Yee, our former COO, has transitioned to the role of Chief Technology Officer, where he'll continue in developing new technologies and practices to drive MEG's top-tier operational performance. Free cash flow of $155 million for the quarter, driven by adjusted funds flow of $239 million or $0.77 a share. The adjusted funds flow was impacted by a realized commodity price risk management loss of $66 million or $0.21 a share in the quarter. Quarterly production volumes of 91,506 barrels per day at a steam-oil ratio of 2.56. Based on this strong operational performance, we are once again revising our annual production guidance from 91,000 to 93,000 barrels a day to 92,500 to 93,500 barrels a day. Capital expenditures of $84 million were directed towards sustaining and maintenance activities as well as incremental well capital necessary to fully utilize the Christina Lake central plants oil processing capacity. Net operating cost of $7.17 per barrel included nonenergy operating costs of $4.46 per barrel, power revenue offset energy operating costs by 43%, resulting in a net impact of $2.71 per barrel in the quarter. Debt repayment remains a top priority. And during Q3, MEG redeemed USD 100 million of MEG's 6.5% senior secured second lien notes due January 2020-'25. MEG released its 2021 ESG report in August. The report focuses on priority topics and outlines the ESG activities across our business including a formal emissions reduction target on net 0 emissions, Scope 1 and Scope 2, by 2050 and a midterm target of 30% reduction in bitumen greenhouse gas emissions intensity, Scope 1 and Scope 2, by 2030.MEG also continued its involvement in the Oilsands Pathways to Net Zero Alliance. Recently, the alliance provided a detailed update of its 3-phase plan to achieve net 0 greenhouse gas emissions by 2050. The alliance continues to advance its foundational carbon capture and storage project, which includes a 400-kilometer pipeline from Fort McMurray to Cold Lake and associated sequestration facilities in the Cold Lake area to gather CO2 for more than 20 oil sands facilities. We're pleased to have ConocoPhillips join the alliance, which now operates facilities representing approximately 95% of Canada's oil sands production. MEG realized an average AWB blend sales price of USD 59.15 per barrel during the third quarter of 2021 compared to USD 56.41 per barrel in the second quarter. The increase in average AWB blend sales price quarter-over-quarter was primarily the result of the average WTI price increasing by USD 4.49 per barrel. MEG's sold 38% of its sales volumes at the premium priced U.S. Gulf Coast in the third quarter of 2021 compared to 45% in the second quarter as a result of higher apportionment levels on the Enbridge mainline. MEG continues to execute on its debt repayment strategy, and during the quarter, redeemed USD 100 million of the corporation's 6.5% senior secured second lien notes due in January 2020-'25. This brings MEG total debt repayment to USD 1.6 billion since the beginning of 2018, contributing to our short-term debt repayment target of USD 2 billion. All available free cash flow generated in Q3 and Q4 will continue to be directed to further debt repayment.Based on the strong operational performance this year, MEG is upwardly revising its full year 2021 average production guidance from 91,000 to 93,000 barrels a day to 92,500 to 93,500 barrels a day. G&A expenses are now targeted to be in the range of $1.65 to $1.75 per barrel and nonenergy operating costs are now expected to be in the range of $440 million to $450 million. MEG invested $84 million of capital in the quarter with the majority focused on sustaining and maintenance activities as well as the incremental well capital to fully utilize the Christina Lake's oil processing capacity of approximately 100,000 barrels a day. Corporation expects full facility utilization in the second half of 2022, post the planned turnaround in the second quarter of 2022. In the third quarter, we continue to advance our ESG activities and release our 2021 ESG report. This is MEG's second ESG report and demonstrates our commitment to providing our stakeholders with disclosures and meaningful updates about our ESG commitments and priority topics. The report is available online at www.megenergy.com. Continue to demonstrate our commitment to decarbonization by joining the Oilsands Pathways to Net Zero Alliance in June 2021. This collaboration of Canada's 6 largest oil sands producers will work collectively with the federal and Alberta government to achieve net 0 greenhouse gas emissions from oil sands -- 2050. Last week, we were pleased to have ConocoPhillips Canada joined the alliance in this effort. As I bring my remarks to a close, I again want to thank our team at MEG for their commitment and perseverance. I'm pleased to see increasing signs of industry recovery from COVID-19 and the challenging commodity prices of 2020. MEG's performance demonstrates our resilience, and I'm proud of our performance and remain confident in our ability to execute on our business plan and remain committed to sustainable, innovative and responsible energy development. We look forward to releasing our 2022 capital program and operational guidance on November 29 as well as continuing to update you on our debt repayment progress. With that, we'll now open the line for questions.
[Operator Instructions] Your first question will come from Phil Skolnick with Eight Capital.
I have a couple of questions. Just first, because you are coming close to that total debt repayment. What were your thoughts on next? Is it some form of return of capital to shareholders? And how are you thinking about that?
Yes, we are getting close to our -- that initial target of the USD 500 million debt repayment, Phil. We're coming out with our capital budget in November -- around November 29, and we'll have more details around that. So we're still working through that, but we -- you will expect us to talk more about that in November 2019.
Okay. Cool. And just finally, just -- this is the third time you've raised your '21 production guidance. Number one, what has been driving that? Has it been reservoir or a combination of that and things that you're doing as well? And does that have any downward implications to your maintenance CapEx?
Phil, it's Derek. Yes, it is the third time we've increased our guidance. I'm pretty sure we're not going to increase our guidance again. What you're seeing is sort of the cumulative efforts on 3 different fronts: one, trying to ensure that every ounce of steam that we produce is being used to achieve the maximum benefit it can in terms of liberating oil inside of the reservoir. You're also seeing the impact of improving our efficiency and uptime utilization of our facility as well as some innovative technology that we've been putting to work downhole controlling where that steam goes to, ensure that it is impacting the best parts of the reservoir to improve production performance. So those are the 3 big drivers on the performance side. As you think about, does it change the -- or bring down our sustaining capital, absolutely. It helps, but it's not going to offset the impact that we're seeing from inflation and the continued work we have to do on the facility side to continue to move increased volumes.
Your next question comes from Phil Gresh with JPMorgan.
I guess just a follow-up on the first question that was asked. I know you'll give your capital budget later this month. But beyond the capital budget, as you think about other capital allocation options, whether it be a dividend or a share buybacks or incremental debt paydown. Just if you could walk through how you're thinking about the various priorities on maybe a multiyear basis?
Yes, Phil, it's Eric. As I mentioned on the first question, just be patient, we'll talk about that at the back end of this month when we come with our capital budget. We're not prepared to speak to that yet. We have to work here a little bit more on that.
Okay. Okay. And then on the last call, there was some discussion around some inflation that you're beginning to see. I think, Derek, you might have mentioned 10% inflation, if I recall correctly. So what are your latest thoughts on the inflationary environment?
We're still seeing and don't believe we're in a stabilized sort of position to talk to what that inflation is going to be. But obviously, earlier on this year, we saw big increases in the price of steel. Iron ore prices have almost dropped in half in the last couple of months. So we expect that steel will not be as big a problem going forward as we've seen, but there's probably 3 big issues. Obviously, the supply chain issues, the inflationary issues associated with costs and the one on chemicals and on products but also on people and availability of people.I'd say when you multiply all of those things together, some of it's cost and some of it will turn into incremental cost, some of it will turn into sort of a decrease in efficiency and longer time line. So it's something that we've got a sharp eye on, and we're continuing to try and figure out what are some of the techniques that we could use to make sure that we mitigate those impacts. I'll give you an example. This year, we've been running up to 3 rigs at site, and those rigs would run for a month or 2 months and then be shut down. Next year, it's fully our intention to keep one rig running throughout the year. And the -- there's cost savings associated with that. You can guarantee the rig company years worth of work, and that should generate a better rate for you. Probably the biggest upside is though the crews, the crews know that they have steady and sort of a continuous paycheck, and that is a very big deal for people on the oil sands on the service side. So that's a good example of not only sort of the cost impact, but if you can get that same crew coming back week after week, you're not going to have as many safety incidents and you're going to see great efficiencies.
Got it. No, that's very helpful. My last question would just be on pipeline takeaway down to the Gulf Coast. Obviously, Line 3 are started up, which should give you more capacity to move barrels. Enbridge is also talking about potentially expanding some of those downstream pipelines. So would that have any meaningful impact on the way you look at things? Or are you comfortable with the commitments that you have?
So we're comfortable with what we have today. We've got 100,000, as you know, going down to the Gulf Coast. We'll have another 20,000 in plan when TMX comes on. So we view, obviously, the increase in egress very constructively, but we don't have any intention to change in sort of our sales market mix on a go-forward basis.
Your next question comes from Greg Pardy from RBC.
So maybe I'm jumping ahead here. But on -- just with the turnaround second quarter next year, should we be thinking about that as a typical 3-week or will it be longer just given the tie-in that you need to go through with bumping capacity?
So Greg, it's a bigger turnaround than -- not so much just on time. So this will probably be 28 days, as we've currently estimated it, but it's our Phase IIb, which is the biggest component. We've got Phase I, Phase II and Phase IIb, and Phase IIb is the biggest contributor of our production. So the impact is going to be much larger than it would be for -- if we're taking down or turning around Phase I or Phase II.
Okay. Okay. Good to know, and I'm sure we'll get the details with the budget. Shifting gears, maybe, Derek, is I want to come back a little bit to Pathways, but not so much progress on that as maybe just the degree of appetite you're finding for CCS, I'd say, not just in Canada but elsewhere just given some of your recent travels.
The appetite for CCS is growing massively. I think people are finally realizing that the single biggest lever that we have to pull in terms of decarbonization is carbon capture and storage. It's not a new technology. It's been one that's been around for a while, and it's got -- the technical bugs are all worked out. The real challenge is trying to find the appropriate sort of economic terms to get it underway, but people are very comfortable with the technology. They see it as being sort of the, as I say, the single biggest lever that we can pull to have an impact on driving -- actually decarbonizing. It's really coming down to what we call the fiscal and regulatory regimes that are going to be present for us to create conditions to get this infrastructure in the ground up and running.
Your next question comes from Neil Mehta from Goldman Sachs.
This is Nicolette Slusser on for Neil Mehta. So we would just be curious about your views on Line 5. We recognize this is a light oil line, but if the pipeline had lower flows, you could have barrels back into Alberta. Is this something we should be concerned about? Or do you think the status quo will prevail?
Nicolette, it's Derek Evans. Line 5 does not carry a huge amount of volume. And I think it's about 330,000 barrels a day. It tends to be light product. I would say our view on Line 5 at the current time with Line 3 up and running, the replacement, we don't expect if Line 5 got shut down. Those volumes would back into -- would negatively impact the -- our ability to continue to move heavy oil down to the U.S. Gulf Coast. I guess the one thing we would point to is, with Line 3 now up and running, there actually appears to be incremental space on the light system that heavies can utilize with the way that line is now configured. So you could -- we're even more comfortable today that the shutdown of 5, Line 5, won't -- wouldn't negatively impact our long-haul capacity.
Okay. That's great. And then just a follow-up on production here. We were curious if there are any thoughts to raising production above the targeted 100,000 barrel per day level or if there were any optimization projects underway in addition to ramping production to that full processing capacity?
We have no plans to grow our production at this time beyond the 100,000 barrels a day of steam day capacity.
[Operator Instructions] Your next question comes from Menno Hulshof from TD Securities.
I'll just start with one on the mainline renegotiation. My understanding is that a ruling is expected, give or take, by the end of this month. So could you just walk us through the range of outcomes? And more specifically, what are your expectations for apportionment and your own Gulf Coast access in Q4 and into 2022?
Yes, Menno, you know as much as we do about the mainline contract. And so I'm not sure you want to speculate on the range of outcomes at this point in time. We do expect, like you mentioned, here outcomes on the back end of this month. So we'll wait to hear that.
Would you be like to take a stab at a apportionment into the end of the year in 2022? Or is it just -- it's too uncertain at this time?
I'm sorry. I missed that question, Menno. Yes, the end of the year, we -- look, it was 12% in November. We think it's sub-10%, maybe even 5% in December. And then as we look into next year, it's probably -- it's less than 20%, maybe it's 10% on the mainline, but we'll see what that looks like as we move through 2022, but we've seen it come down quite sharply over the last couple of months.
Okay. That's great to hear. And then I guess my second question just relates to earlier stage pilot activity. Can you just remind us of some of the earlier stage pilots that you currently have underway and how they would tie into your 2030 target of a 30% emissions intensity reduction?
Sure. We're just -- Menno, it's Derek. We're in the process of winding down our eMVAPEX pilot that was the Sullivan pilot that we have been running, and we're just looking at where the recovery factors are going to play out in terms of resource recovery, but also in terms of solvent recovery, what are we leaving in the reservoir. So depending on how that all looks, that could be a technology that we put to work in terms of meeting our 2030 targets. We have a project called ERASE, which is a shallow sequestration initiative that we would receive some funding for on -- from the government of Alberta. And that is something that also could be very impactful in terms of finding sort of a more local area in which to decarbonize or at least a disposal of CO2. Other projects that we have on the go would be ones where we're looking at reducing the amount of diluent that we currently use. So we got a low-temperature, low-pressure sort of upgrading technology that would allow us to cut the amount of diluent by almost half. So obviously, the greenhouse gas emissions associated with the diluent would be significantly reduced, but also there would be fairly significant cost savings to the corporation in terms of diluents. As you know, diluent is probably our single biggest cost. So that's another initiative that we have on the go.One initiative that we had talked about in the past is the facility where we were going to inject butane to trim blend the viscosity reduction to enter the -- our long-haul pipelines, that is up and running as of the third quarter and is -- will generate somewhere in the neighborhood of probably $1 million of incremental cash flow on a monthly basis as we supplement butane for condensate.
Your next question comes from Patrick O'Rourke from ATB markets.
It's Patrick O'Rourke, ATB Capital Markets. Just curious here in terms of the Gulf Coast marketing, we've seen a little bit of widening of the differential down on the Gulf Coast for heavies to WTI. Wondering if you can give us a bit of an outlook there. I think that the common thinking is that maybe increased natural gas prices are leaning on heavy refinery margins? And what you see the outlook for that heading into 2022 is?
Yes, Patrick, I guess from our perspective, just generally what we see driving December -- we're in the December sales cycle right now, and it is wider than we would have normally expected to see it probably by $2 to $3. And we think that's primarily driven by elevated levels of storage in Western Canada, and that was driven, we believe, by planned and unplanned outages in PADD II refinery. So we expect to see that inventory get drained. And given the steepness of the WCS curve, we expect that to happen reasonably quickly. So we believe it's transitory. We expect to see it normalize at least by the end of the year. We will get back to sort of that range of $5 to $6 where we think we should be trading against WTI -- WCS against WTI in the Gulf Coast?
There are no further questions at this time. Please proceed.
Thank you, operator, and thank you, everybody, for joining us for our third quarter call and update. I'd remind you to look for our 2022 capital program and operational guidance, which we plan on releasing on November 29. And wish you all a pleasant and profitable day.
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.