MEG Energy Corp. (MEG) Earnings Call Transcript & Summary

Good morning. My name is Sylvie, and I will be your conference operator today. At this time, I would like to welcome everyone to the MEG Energy's 2023 Q2 Results Conference Call. [Operator Instructions] Thank you. Mr. Derek Evans, CEO, you may begin your conference.

Thank you, Sylvie. Good morning, everyone, and thank you for joining us to review MEG Energy's 2023 Q2 operating and financial results. With me on the call this morning are Ryan Kubik, our Chief Financial Officer; Darlene Gates, our Chief Operating Officer; and Lyle Yuzdepski, our General Counsel and Corporate Secretary. 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 will keep my remarks brief today and refer listeners to yesterday's press release for more detail. Our top priority at May is our focus on health, safety and the environment that ensures nobody gets hurt, eliminate serious incidents and delivers operational excellence. I'm extremely proud of the safety, operating and financial performance delivered by our team. Their focus on plant reliability, steam utilization and ongoing well optimization are all contributed to a strong operational quarter. I want to congratulate and thank the MEG team on the execution of a safe and successful second quarter turnaround despite the labor market and ongoing supply chain constraints. Before I turn the call over to Darlene and Ryan to share details of our results, I'd like to briefly touch on the second quarter highlights. Bitumen production in the second quarter averaged 86,000 barrels a day, a 28% increase over Q2 2022. In the quarter, our bitumen realization after net transportation and storage expense of $57.64 was a 33% increase over the first quarter and was primarily driven by an almost USD 10 per barrel improvement in the WCS differential since Q1. These excellent operational results enable our ongoing commitment to debt reduction and share buybacks. In the first half of 2023, we have repurchased USD 126 million or CAD 171 million of the outstanding 7 and 8 senior unsecured notes. Share buybacks in this period totaled $169 million through the repurchase and cancellation of 8 million shares. Free cash flow remained allocated at 50% to debt reduction 50% to share buybacks. Once the USD 600 million debt repayment target is achieved MEG will return a 100% of free cash flow to shareholders. We anticipate achieving the $600 million debt mid-2024. I will now ask Darlene Gates, our COO, to speak to the operating results and has Ryan Kubik, our CFO to talk to our financial results. Before I open the call to questions, I'll provide an update on the Pathway Alliance's efforts this quarter. Darlene, over to you.

Thanks, Derek, and good morning, everyone. Our priority at MEG remains Health, Safety and Enviromental performance. This quarter we continued to advance our operations excellence and safety leadership development program. It is our approach to continuous improvement that enables us to be a leader in responsible and sustainable energy development. Production of 86,000 barrels per day in the second quarter was delivered at a top tier steam oil ratio of 2.25 and includes the completion of a major turnaround. This resulted in a quarterly production impact of approximately 20,000 barrels per day. Operating expenses, net of power revenue averaged $6.63 per barrel in the quarter. This is a 48% reduction from the same period last year. The completion of our second scheduled turnaround was a key a key milestone in the quarter. It was the largest in our history in terms of work hours at just over 220,000 hours and was completed on schedule with 0 recordable injury to 0 recordable spills. Increase on costs in the second quarter reflect a larger planned turnaround spiller. Increased turnaround costs in the second quarter reflect a larger planned turnaround scope, found work, inflationary pressures on labor costs and supply chain challenges. I want to take this opportunity to thank our maintenance, operations and contractor crews for their commitment to delivering and executing a phase turnaround. Moving forward, we are focused to optimizing second half productions which is forecasted to be approximately 105,000 barrels per day. Third quarter volumes will be impacted by planned by planned facility and infrastructure and field infrastructure projects required to distribute high pressure steam to the field -- the future well paths. This was partially offset by the start-up of infill and redevelopment wells drilled earlier this year. Steam injection to our newest pad in the third quarter will also commence and ramp up to its full production by year-end. We expect a strong finish to the year again with an exit rate of 110,000 barrels a day. With that, I'll turn it over to Ryan to provide the Q2 financial results.

Thanks, Darlene. MEG's cash operating netback in the second quarter of this year was $42 per barrel, generating $278 million of adjusted funds flow in the quarter or $0.96 per share. As Darlene mentioned, our production averaged 86,000 barrels per day during the quarter. And with significantly improved differential since the start of the year, our Q2 bitumen realization after net transportation and storage expense was $57.64 per barrel. Nonenergy costs averaged $5.66 per barrel in the second quarter consistent with $5.65 per barrel in Q2 2022. Energy operating cost, net of power revenue, however, declined to $0.97 per barrel from $7.32 per barrel in Q2 last year, reflecting low 2023 natural gas prices. In addition, we continue to enjoy strong power revenue from our co-generation facilities, which offset 75% of energy operating cost in the current quarter. Our Christina Lake project reached post-payout royalty status this quarter, resulting in an increase in the effective royalty rate to 13% of bitumen realization after the transportation and storage expense. After funding $149 million of capital expenditures, about 45% of which was related to the turnaround, MEG generated $129 million of free cash flow. That free cash flow was used to buy 3.1 million MEG shares for $66 million and repay USD 40 million of senior notes in Q2. We ended the quarter with just under $1 billion of net debt and still forecast reaching our U.S. $600 million net debt target around mid next year at current oil prices. With production forecast average about 105,000 barrels per day in the second half of this year, we've maintained our 100,000 to 105,000 barrels per day annual guidance range, but will trend to the low end of that range. Per barrel operating cost and G&A guidance is also unchanged, but we'll trend to the top end of those ranges under the current production forecast. With rising second half production and continued strong oil prices MEG is now positioned to generate even more fREIT call flow in the second half of this year for share buybacks and debt reduction. Thanks. And with that, I'm going to hand it back to Derek.

Thanks, Ryan. Before we move on to questions, I'd like to share an update on the Pathway Alliance. MEG along with its Pathway Alliance peers is progressing prework on the proposed foundational carbon capture and storage project, which will transport CO2 by a pipeline from multiple oil sands facilities to be stored safely and permanently in the Cold Lake region of Alberta. During the second quarter of 2023, the alliance continued to evaluate its proposed storage shops and is working to obtain a carbon sequestration agreement from the government of Alberta by year-end 2023. In addition, the Alliance continued to advance engineering and field work related to the proposed CCS project in order to support a regulatory application anticipated in the fourth quarter of 2023 for the CCS network. Formal consultation with about 25 indigenous groups along the proposed CO2 transportation and storage network corridor has commenced and follows early engagement with these groups over the last 2 years. The Alliance continues to work collaboratively with both the federal and Alberta governments on the necessary policy and co-financing frameworks required to move the project forward. The government of Alberta recently recognized that a coordinated approach with the federal government and industry is needed to compete with the United States, Europe and others for investment in wide-scale carbon capture and storage deployment, which is essential to achieve emissions reductions goals. The Alberta and federal governments are in discussions relating to the formation of a bilateral working group to incentivize carbon capture and storage and other emissions reduction technologies. As I bring my remarks to a close, I once again want to extend my thanks to our team for their commitment and perseverance. I'm proud of what we've been able to accomplish and confident in our future and our commitment to sustainable, innovative and responsible energy development. On behalf of MEG's Board of Directors and our management team, I want to thank you for your continued support. With that, I'll now turn the call back over to Sylvie to begin the Q&A.

[Operator Instructions] And your first question will be from Menno Hulshof at TD Securities.

So you touched on this in your opening remarks, but can you elaborate on what drove the decision to adjust the -- I would look to the low end of production guidance range? And I guess more specifically, what's changed in the plan relative to the beginning of the year? And then finally, and I think the answer to the last part is no. But is there any sort of a knock-on effect into 2024.

Thanks, Menno. It's Darlene. I'll take that one. When I look at what's changed our planned facility and field infrastructure projects, as I mentioned, require tie-in and that limits our steam availability to the field. If you look at when we were in the turnaround, our hope was to bring that into the turnaround scope so it didn't impact production in Q3, Q4, and we were not able to do that based on some of the supply chain challenges that we were experiencing. That's really the key difference when I look at what's different from the second half to what we were hoping to achieve in versus what is in the plan now.

Okay. And so if you look at similarly on G&A and OpEx at the higher end of the range, I'm assuming a lot of that is volumetric, but it sounds like there's a bit of an inflationary component in there as well.

Yesl. We're managing the inflationary pressure, but for sure, it's really more the production impact that you're seeing that's driving that metric.

Okay. Darlene, and then finally, could we just get a refresh on your expectations for the trajectory for sustaining capital on a dollar per barrel basis and maybe the base decline in the SOR over the next couple of years as well?

So Menno, I'll take that. I mean I think you should expect we'll -- our sustaining capital will be somewhere in that $400 million to $425 million on a go-forward basis absent any adjustment for inflation that may be required. And I think as we think about some of the pressures we've seen on G&A and operating costs, the single biggest inflationary pressure is coming from the people cost of all those business, which we have seen a sustained and unrelenting pressure in that regard.

And then the base decline in the SOR.

Sorry. Yes. base decline is relatively stable in that probably closer to 15% range and the SOR continues on its downward trajectory. I think Darlene talked about the fact that we're looking to exit an exit rate of 110,000 barrels per day, which would indicate that our SOR will be somewhere in the 2.2% range at exit.

Next question will be from Greg Pardy at RBC Capital Markets.

If -- I guess there's probably a question directly towards -- on the ops side. But if we fast forward to year-end when you're at 110,000 barrels a day. When you look at how much field capacity you have, how much horsepower there is to actually produce bitumen in the field and then compare that with what the processing facility going to take right now, which I think is 110,000 barrels a day. What does that balance look like? And then what is the plan or is there a plan to debottleneck the facility? And what would that involve?

I'll take that one, Greg. It's Derek. I think this year, we have figured out and really hit the top end of the facility capacity, which is really in that 110,000 to 100,000 -- a little over 110,000 barrels a day. So fundamentally, we can achieve that when we're bringing on new wells, new pads, which is what we're planning on doing as we move through the second half of the year at low steam oil ratios. But as we've talked about in the past, we're going to have to add a third processing train the facility, and we've talked about not doing that until we hit our $600 million debt target. But that once we got there, it's somewhere in the neighborhood of $250 million to $300 million to move that field productive capacity -- or not field -- facility productive capacity from 110,000 to about 125,000 BOEs a day, and we'll take somewhere in the neighborhood of 3 years to do that. So I've talked pretty well exclusively about the facility. Obviously, as we would have -- as we're investing to put that third processing train in place, we would also incumbent in that $250 million to $300 million is the new well pads that we would be drilling to fill that production and grow that production to that level as well.

Okay. And then I'll maybe just completely shift gears on you a little bit. But just curious what you're seeing in the Gulf Coast right now as it relates to AWS and WCS vis-a-vis WTI? Are you sending cargoes to China, India right now? Like what's the international appetite? And then I think just more broadly, what happens -- what's your view, I guess, on spreads with TMX next year?

So a bunch of questions in that question. So let me start with where we see the differential today. Now that WCS differential appears to be in that in [ 1550 ] in Edmonton, quite a move from the $10 that we saw earlier. We think part of the rationale or the reason for that is that -- there was a lot of production off-line in that July, August period and BP Whiting, probably, they moved their turnaround up from September into August, and we think that really impacted the amount of crude that I would call a semi-distressed situation in terms of having a lot more heavy oil on the market, which really pushed that differential down. And I think it's a very good indication of what's going to happen in PAT 2 to those differentials once we bring TMX on. So good color there as we think about what TMX may do in terms of bringing differentials down. I think as we look to that differential going forward, for the remainder of the year. I think we're pretty comfortable that it's widened out as much as it's going to and already has some -- what we would call winter effects in it as we've got more condensate in the product going forward. Typically, you see it widen out through the fourth quarter.