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

Good morning. My name is Pam, and I will be your conference operator today. At this time, I would like to welcome everyone to MEG Energy's 2022 Q2 Results Conference Call. [Operator Instructions] Mr. Derek Evans, CEO, you may begin.

Thank you, Pam. Good morning, 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; 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 would refer listeners to yesterday's press release for more detail beyond the comments we've prepared this morning. Prior to jumping into the details of the quarter, I want to point out that this is Eric Toews' last quarterly conference call before retiring on August 1. On behalf of the entire Board and management team, I want to thank Eric for his dedication and valuable contributions during his time in MEG. Eric has led a number of strategic initiatives, which have transformed MEG's balance sheet, including the sale of the Alliance -- or the Access Pipeline, and the completion of a number of complex refinancing transactions, which have been instrumental in getting us to the place we are today where we're returning capital to shareholders. On a personal note, Eric has been an amazing partner. I'm grateful to have had the opportunity to work alongside him these last 4 years and wish him all the best in the future. In the second quarter, bitumen production averaged 67,256 barrels a day at a steam-oil ratio of 2.46 compared to 101,128 barrels per day at a steam-oil ratio of 2.43 in the first quarter of 2022. Production in the quarter was impacted by the scheduled major turnaround at the Christina Lake Phase 2b facility. Despite a tight labor market and supply chain challenges, the turnaround was completed safely, on time and on budget. Following the turnaround, the Christina Lake facility experienced an unplanned electrical event, which resulted in a slower-than-forecast production ramp-up during the month of June, which impacted full year 2022 average production by approximately 2,000 barrels per day. Christina Lake facility has now returned to full production and MEG's second half 2022 average production levels are expected to meet or exceed the record production levels the corporation reached in the first quarter of 2022. Due to the slower post turnaround production ramp-up, MEG revised its full year 2022 average production guidance to 92,000 to 95,000 barrels a day, from 94,000 to 97,000 barrels per day. MEG also revised its full year nonenergy operating costs and G&A expense to $4.60 to $4.90 per barrel and $1.75 to $1.90 per barrel, respectively, reflecting lower full year production guidance. In the second quarter, MEG initiated its share buyback program and continued to make significant progress on debt reduction. Year-to-date, we've applied over $1 billion of free cash flow to debt repayment and share repurchases. Highlights from the second quarter results include: Funds flow from operating activities of $412 million and adjusted funds flow of $478 million; free cash flow of $374 million; total capital expenditures of $104 million, primarily directed towards sustaining and maintenance activities including approximately 44%, which was directed towards the completion of the major planned turnaround. Net operating costs averaged $12.97 per barrel, including nonenergy operating costs of $5.65 per barrel. Power revenue offset energy operating costs by 30%, resulting in energy operating costs, net of our revenue, of $7.23 (sic) [ $7.32 ] per barrel. Year-to-date debt reduction of USD 700 million, including USD 379 million in the second quarter of 2022. MEG initiated its share buyback program during the quarter and to date has returned $139 million of capital to shareholders through the repurchase for cancellation of approximately 7.24 million MEG common shares. During the quarter, MEG renewed its existing modified covenant-lite facility -- credit facilities, resulting in total available credit of $1.2 billion with a maturity date of October 31, 2023. And on June 16, 2022, MEG announced the hiring of Mr. Ryan Kubik, as the corporation's next Chief Financial Officer, who will succeed Eric Toews effective August 1, 2022. MEG realized an average AWB blend sales price of USD 100.42 per barrel during the second quarter of 2022 compared to USD 83.55 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 14.12 per barrel. MEG sold 79% of its sales volumes in the U.S. Gulf Coast market in the second quarter of 2022 compared to 58% during the first quarter of 2022. The increase quarter-over-quarter is primarily the result of apportionment on the Enbridge mainline being 0% in the second quarter of 2022, compared to 10% in the first quarter. On June 15, 2022, Canada's major oil sands producers announced a combination of 3 existing industry groups, all focused on responsible development into a single organization called the Pathways Alliance. The new organization incorporates the Oil Sands Pathways to Net Zero Alliance launched in 2021; Canada's Oil Sands Innovation Alliance, COSIA, created in 2012; and the Oil Sands Community Alliance, OSCA, created in 2013. The combination of these industry groups integrated into a single organization with combined leadership will enhance the Alliance's collaborative efforts to advance responsible oil sands development and to progress the Alliance's goals including achieving net zero greenhouse gas emissions from oil sands production. Key focus of the new Pathways Alliance will be to continue the considerable work already underway to reduce greenhouse gas emissions from oil sands production by 22 million tonnes annually by 2030, and ultimately achieve its goal of net zero emissions from oil sands production by 2050. MEG's capital allocation strategy is designed to provide increasing return of capital to shareholders as progressively lower net debt targets are reached. MEG reached its USD 1.7 billion net debt target in the second quarter of 2022. At net debt levels between USD 1.7 billion and USD 1.2 billion, approximately 25% of free cash flow generated is being allocated to share buybacks with the remaining free cash flow applied to ongoing debt reduction. In the current commodity price environment, MEG expects to reach its USD 1.2 billion net debt target in October of 2022, and to reach its USD 600 million net debt floor in the second half of 2023. During the second quarter of 2022, MEG repaid $379 million through the redemption -- USD 379 million through the redemption of the remaining USD 171 million of MEG's second quarter -- or second lien notes and through the repurchase and extinguishment of USD 208 million of MEG's outstanding senior secured notes due February 2027. MEG has repaid approximately USD 2.3 billion of outstanding indebtedness since 2018. During the quarter, the corporation initiated its share buyback program. In the second quarter, MEG purchased for cancellation 4.45 million common shares, returning $94 million to MEG shareholders. Year-to-date, MEG has purchased for cancellation 7.24 million common shares returning $139 million to MEG shareholders. During the second quarter, MEG amended and restated its revolving credit facility and its letter of credit facility agreement guaranteed by Export Canada -- Export Development Canada, and extended the maturity date of each facility by 2.3 years to October 31, 2026. Total credit available under the 2 facilities was reduced from $1.3 billion to $1.2 billion and is comprised of $600 million under the revolving credit facility and $600 million under the EDC facility. The revolving credit facility retains its modified covenant-lite structure, meaning it continues to contain no financial maintenance covenants, unless MEG is drawn under the revolving credit facility in excess of 50%. If drawn in excess of 50% or $300 million, MEG is required to maintain a first lien net debt-to-EBITDA ratio of 3.5 or less. MEG continues to have no first lien debt outstanding. 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, we want to thank you for your support. With that, I'll turn the call to our operator to begin the Q&A.

[Operator Instructions] First question comes from Neil Mehta at Goldman Sachs.

Eric, congratulations on your retirement, and thank you for the partnership over the years. The first question is on the macro, Derek. We've been a little surprised to see WCS widen out as much as it has, in light of inventories in Alberta. And I guess part of it is Gulf Coast fuel oil, but part of it seems to be the SPR. Would just love your perspective on the sustainability of that wider differential, how you guys are thinking about the '23 and '24 outlook there? And anything you're seeing real time in terms of being able to get the barrels out of the market.

Thanks for the question. It's a very appropriate and topical one at this time. One of the things that has happened as a result of Russian-Ukrainian sort of conflict is that Russia has had to find a home for its Urals barrels, and it had to find a home quickly. What we've seen happen in the market is the Urals barrels, which are a heavy sour barrel, have been marketed to both China and India. And what we've seen is they've been marketed at a fairly deep discount, a deep enough discount to stop some of those U.S. Gulf Coast barrels moving across the dock and moving to Asian markets, in particular, India. So if we look at the dynamic that existed in late Q4 and early in Q1 of this year, you would have seen 2 million to 4 million barrels a day -- or a month of product, heavy product, moving across the dock to Asia. Those volumes have dried up as Indian companies and Chinese companies source those barrels from the deeply discounted Russian market. So that would be the #1 factor that has driven an increase of, sort of, supply on the U.S. Gulf Coast of our product that has broadened out the differential. You're right, the SPR releases have had an impact, but that impact was about 1 million barrels a day. It's waning as they get towards the end of the program. It's currently down at about 700,000 barrels a day. And in that September 16 to October 21 per period, it's going to drop down to about 550,000 barrels a day of product. And that product is now going to be predominantly light as opposed to heavy. So our view is, on both of these factors, is that a deeply discounted Russian barrel is what you would do if you were Russia and trying to find a home for your product quickly. But we don't think that, that's going to persevere or continue. The market will take or tighten up that arbitrage. And we do believe that Asian suppliers will be back buying product across the dock. And we're seeing early indications of that already in the coming months. With respect to the SPR, that program is winding down. I think the Biden administration pointed to how they were going to start refilling the SPR as early as 2023. So we fully expect that these differential levels will return to where they were prior to the conflict -- the Russian-Ukrainian conflict.

All right. Well, and that's kind of the follow-up is to the extent you think that some of this macro distortion is temporary, and you've seen while the stock has been extraordinary over the last 2 years, it's pulled back meaningfully from -- over the last 6 weeks. How does that influence your thinking around leaning into the buyback and taking advantage of any dislocation?

I think -- well, any dislocation provides an opportunity for us to continue to buy back shares. I don't think we're going to lean in it -- lean into it disproportionately. We have a program that we have articulated to our shareholders that at this juncture, 25% of cash flow goes to share buybacks. And it's very mechanical in terms of -- we look at what we have available in any given month for free cash flow. 25% of that goes into the market. So I'd love to obviously buy back more shares as we've seen this pullback in the market. But we're not timing the market. We have a program that we've articulated and we're going to continue with that.

Your next question comes from Menno Hulshof with TD Securities.

I'll start off with a question on vertical integration. We've seen a big move in AECO and even the [ conde ] premium is sitting at roughly $5 a barrel, which are both obvious inputs in your business. But then there's still this massive [ arc ] between AECO and pretty much every other global benchmark that many think will tighten in the coming years. So I guess my question is, how much time are you spending thinking about vertical integration these days? And would you ever consider an acquisition to hedge out some of the price risk on those key inputs?

The short answer is we have thought about vertical integration in this life and in past lives. And man, I would tell you that we are not in the natural gas business or the condensate business. Yes, they are big inputs, but they are not ones that we feel there's very efficient and effective markets out there. We're delighted with our brethren in the natural gas business. As you look at AECO production today, it's reaching all-time highs, as the natural -- the Canadian natural gas business responds to the very strong price signals that we see. So we're not planning on vertically integrating the business. We are very good and very effective at controlling our cost structure inside of the oil sand space. All that being said, we do look for opportunities to take advantage of dislocations in the market on the condensate side and on the natural gas side. And I think if you -- in reviewing our quarter, you'll see that we've locked in 7,000 barrels a day of condensate prices for 2023 at a very significant discount to the market. And if you're looking for us to take action in terms of how we're going to manage those input costs, it will be through strategic hedging of those and opportunities that -- dislocations in the, sort of, the historic pricing patterns that we can take advantage of.

Got it. Thanks for that, Derek. And then I guess the second question would be related to the federal discussion paper on oil and gas emissions reductions that was recently published. And maybe this is specific to me, but it came a bit out of left field from my perspective, and reopened the debate on cap and trade among other tangents. And certainly surprising given how aggressive the Pathway's targets already are. So how much of a risk is this from your perspective? And how long could this hang out there for? What is your understanding of the next steps?

So Menno, you're not the only person that was surprised last Monday. I think everybody in Calgary is going, where does this come from? We knew there was a -- obviously, the emissions cap paper is -- we expected something. We just did not expect such a strident sort of focus on the 42% reserve targets or emissions reduction targets in that paper. As I -- I guess I'd start off by saying we share the government's goal of tackling the challenge of climate change. I mean the Pathways Group has been upfront. We've been at this now for over 18 months. We've set our own ambitious targets for oil sands sector to achieve a 22-megaton annual reduction by 2030. And that's a very ambitious goal on its own and obviously, the net zero goal by 2050. So -- we're -- we have a plan, and we think it's one of the few plans out there. It's ambitious at 30%. I don't know how we get to 42%. I think that personally is, in my humble opinion, is almost unrealistic. And the -- it's not that we wouldn't want to try and get to 42% if we could, but you can't ignore the reality of the regulatory environment in this country. You can't ignore the reality of the -- what I'm going to say, the carbon pricing regime and the ability to trade carbon credits from a pan-Canadian perspective. And you can't ignore the reality of the fact that the federal government and the provincial government aren't talking. Without those 3 issues being addressed, you can set whatever ambitious plan you want but you're never going to be able to achieve them. And this is where, to me, Pathways has differentiated and distinguished itself. It has a target out there. It's got the 30%. Yet those 3 items that I mentioned stand in our way of us even getting to the 30%, let alone the 42%. So, do I think these things are -- that we can fix these things and move forward? Yes. Do I think we can get to 40%? 42%? Yes, we will get to 42% over time. But unless there is a concerted effort to address all 3 of those issues in the very near term and to bring a sense of urgency to fixing our regulatory environment, better communication between all levels of government and creating a price of carbon that we can take to the bank and finance some of these projects on -- if that does not happen, then these targets are unrealistic.

I agree with all of that. Thanks, Derek.

Your next question comes from Greg Pardy with RBC.

Derek, I hope the press on the line gets that in The Globe and Mail or other papers tomorrow morning to send the message, but -- look, just all the very best, Eric, and welcome, Ryan. Just wanted -- maybe just take it back to the company, maybe just hit 3 things. How are you thinking about hedging TI? Does the dividend become a part of the conversation at that floor level of $600 million? And then how should we be sort of thinking about 2023 CapEx?

Okay. How are we thinking about hedging WTI? No, our philosophy on hedging has not changed. And just to repeat it, we hedge to protect our capital program. And we look at what commodity price, WTI commodity price would have to be for the year. This year it turned out that we'd need an average price of $45 WTI to have sufficient fund flow to [ cover off ] our capital program. We thought that, that was highly unlikely and decided probability of that was very, very low, and we weren't going to hedge. That will be the same way we look at hedging WTI in -- if we are going to hedge WTI on a go-forward basis. So not planning on doing that. But as you would have heard in previous color, where we were talking about condensate and a little bit about natural gas, we will hedge our inputs, if we're provided with sort of a dislocation or an opportunity in the market. Obviously, condensate as we talked -- as you know, is our single biggest cost. So being able to lock down 10% to 15% of your condensate at a significant discount to this historical market prices is important. And on the natural gas side, that's another big operating cost for us. Even though we can mitigate that with our power sales, we will look and continue to look and have targets in place to take advantage of the market should it present the opportunity to do so. With respect to your second question on the dividend, when we reach our net debt floor of USD 600 million, would we look to put a dividend in place? That is absolutely one of the tools that we're going to look at. And we will provide greater clarity on that, obviously, as we move forward and get closer to that target. So you should expect to hear more on us -- on that going forward. Just to elaborate on that a little bit, what -- what we have seen others do is put dividends in place and special dividends in place. We have a unique opportunity to be able to watch and see how those are reflected in the price of the underlying equity of those organizations. So we will -- we're not sitting on our hands over here. We're watching. We're looking at how the market is responding to dividends and special dividends. And those will help inform how we put in place a return of capital-type structure on the dividends when we hit that USD 600 million. On the third part of your question, which I believe was how do we see CapEx at 2023, we're watching inflation very carefully, Greg. Oilfield tubulars, drilling and service completion costs, service rig costs are up and up significantly. Labor, steel, are all continuing to move, and I wouldn't say they've plateaued. So as we think about what our CapEx program for 2023 will be, it's going to be larger than it is today, just on an inflationary basis. But there will also be another element as we move from our existing development area in [ Eau Claire ], we're going to move further south down to [indiscernible], and that will require sort of an incremental level of sustaining capital than what we had in our budget this year as we build the emulsion lines, the steam lines, all the product lines and the infrastructure to move a significant difference. So into a part of the reservoir that is likely going to have a much lower steam oil ratio by virtue of the fact that we don't see any underlying water there. So kind of excited about getting down there and continuing to not only expand the infrastructure but move into another new area.

[Operator Instructions] There are no further questions at this time. Please proceed.

Thanks, Pam. And thank you, everybody, that's joined us this morning for our second quarter call. We're excited about what we've been able to achieve in the first half of 2022 and look forward to reporting on our operational performance and our return of capital program when we release Q3 on November 10. Have a great day.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines. Have a great day.