MEG Energy Corp (OTCPK:MEGEF) Q4 2020 Earnings Conference Call March 4, 2021 8:30 AM ET
Derek Evans - Chief Executive Officer
Eric Toews - Chief Financial Officer
Chi-Tak Yee - Chief Operating Officer
Conference Call Participants
Phil Skolnick - Eight Capital
Neil Mehta - Goldman Sachs
Greg Pardy - RBC Capital Markets
Good morning. My name is Colin, and I'll be your conference operator today. At this time, I'd like to welcome everyone to the MEG Energy 2020 Year-End Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers remarks there will be a question and answer session. [Operator Instructions]
Mr. Derek Evans, CEO, you may begin your conference.
Thank you, Colin. Good morning, everyone, and thank you for joining us to review MEG'S Energy's full year operating and financial results for 2020. And in the room with me this morning are Eric Toews, our Chief Financial Officer; Chi- Tak Yee, our Chief Operating Officer; & 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'll keep my remarks brief today and refer listeners to yesterday's press release for more detail. MEG continues its priority of maintaining safe and reliable operations as we continue to face the hurdles associated with the COVID-19 pandemic. The health and safety of our staff is our top priority. And I commend our teams for exercising diligence and focus as we've operated through the pandemic. We had no lost time accidents for employees in 2020, which is a tremendous accomplishment, particularly given the turnaround activities that were ongoing at site this summer. As well we've not had any COVID-19 outbreak at our site or our office, and our focus remains on keeping each other safe and maintaining reliable operations.
In 2020, notwithstanding the incredibly challenging environment our industry faced, we to continue execute on our strategic focus of overall improving cost efficiencies, preserving financial liquidity and and enhancing MEG's competitive position. In keeping with this strategy, we significantly reduced G&A, repaid indebtedness, extended the maturity runway of outstanding long-term debt and began moving the majority of our barrels to the U.S. Gulf Coast.
In 2020, our emphasis on cost efficiencies saw us decrease our G&A expenses by $19 million, a reduction of 28% compared to 2019. Our net operating costs of $6.18 per barrel were supported by record low nonenergy operating costs of $4.38 a barrel and strong power sales, which offset 45% up per barrel energy operating costs. Free cash flow of $129 million for the year was driven by adjusted funds flow of $278 million and a disciplined cash capital spend of $149 million. We exited 2020 with $114 million of cash on hand and MEG $800 million modified covenant-light revolver essentially undrawn.
Debt repayment remained a priority for us in 2020 with the repayment of $132 million of long-term debt concurrent with the refinancing of USD 1.2 billion of existing indebtedness in January 2020. The subsequent to year-end, we entered into a further refinancing of existing indebtedness with the refinancing of USD 600 million in aggregate principal of 5.875% senior secured notes due February 2029. Post these refinancing, MEG maintains a 4-year runway until its next debt maturity, represented by the remaining USD 496 million, up 6.5% second lien notes due January 2025. The in the last three years, the company has repaid approximately USD 1.5 billion of our initial debt repayment target of USD 2 billion. MEG realized an average AWB blend sales price of USD $28.07 per barrel in 2020 compared to USD 46.19 per barrel in 2019. The decrease in the average AWB blend sales price year-over-year was primarily a result of the average WTI price decreasing by USD 17.63 per barrel.
MEG sold 40% of its sales volumes to the U.S. Gulf Coast in 2020 compared to 33% in 2019. Increase in sales to the U.S. Gulf Coast is primarily a result of Corporation's increased contracted blend transportation capacity on the Flanagan South and Seaway pipeline systems, effective July 2020 from -- moving from 50,000 barrels a day to 100,000 barrels a day. Transportation and storage costs averaged to USD 6.74 per barrel of AWB blend sales in 2020 compared to USD 5.70 per barrel of AWB blend sales in 2019. Increase in transportation and storage cost is primarily due to the fixed costs associated with increased Flanagan South and Seaway pipeline contracted capacity, coupled with lower year-over-year sales volumes. MEG’s AWB blend sales by rail were approximately 17,000 barrels a day in 2020, representing 14% of total blend sales compared to approximately 20,000 barrels, representing 15% of total blend sales in 2019.
MEG is not anticipating -- undertaking any AWB blend sales by rail in 2021. 2020, we continue to advance our environmental, social and governance activities and strategies with corporate commitments to support the Paris agreement, the approval of our long-term ambition of reaching Net zero greenhouse gas emissions on a scope one and scope two basis by 2050. And our commitment to human rights as reflected in the UN Universal Declaration of Human Rights. We remain committed to ESG leadership and look forward to updating our performance in that regard with the release of our 2020 sustainability report mid-2021.
As announced on December 7, 2020, MEG's capital investment plan for 2021 of $260 million includes $245 million to be directed towards sustaining and maintenance capital and the remaining $15 million towards nondiscretionary field infrastructure, regulatory and capital costs -- corporate capital costs, excuse me.
MEG's 2021 annual average bitumen production volumes are targeted to be in the range of 86,000 to 90,000 barrels a day. And the corporation's 2021 nonenergy operating costs and general and administrative expenses are targeted to be in the range of $4.60 to $5 per barrel and $1.70 to $1.80 per barrel, respectively.
To support MEG's 2021 capital budget announced December 7, 2020, MEG entered into benchmark WTI fixed price hedges and enhanced WTI fixed price hedges with sold put options for approximately 47% of forecast bitumen production weighted at 60% in the first half and 30% in the second half at an average price of USD 46.66 per barrel. These hedges were put in place to protect funding of the corporation's 2021 capital program with internally generated cash flow down to USD 30 per barrel WCS price and to protect MEG's balance sheet.
First half weighting of these hedges at approximately 60% of forecast production reflects the first half weighting of mixed capital investment profile as well as the uncertainty regarding the pace of 2021 economic recovery at the time of execution.
As I bring my remarks to close, I again want to thank our team at MEG for their commitment and perseverance through an exceptionally challenging year.
MEG's performance in 2020 demonstrates our resilience and I'm proud of our performance and confident in our ability to continue this momentum into 2021. Looking ahead, we're confident in our ability 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, we will now open the lines for questions.
[Operator Instructions] Your first question comes from Phil Skolnick from Eight Capital. Phil please go ahead.
Can you just talk about your debt reduction policy and? In that same framework, just how you -- what do you need to see to put on that incremental? I think it's $150 million of spend to get to the 100,000 barrels a day, kind of what are the priorities of the use of free cash flow?
Why don't I take the first part, and I'll let Eric takes -- talk about debt. Clearly, we're going to -- at these such commodity prices, Phil, we have incremental free cash flow above and beyond what we're going to need to fund our capital program. People are asking us, well, when would you make any decisions with respect to whether you would put more capital back to work? And quite frankly, we love what we're seeing in terms of commodity prices and differentials, but we'd like to see them for a little while longer to know that they've actually got some staying power. Obviously, we've got an OPEC meeting today, which could be positive or negative or neutral and as to that. But as we think about incremental free cash flow, I think, obviously, there's the opportunity to put a little more money back to work on the business and start that progression from essentially 90,000 barrels a day back to 100,000 barrels a day. We anticipate that capital cost associated with that is somewhere in the neighborhood of $15,000 of flowing BOE. But I would caution that the time lines on putting that capital back to -- from the time we put the dollars to work to when we actually see the production can be anywhere from 12 to 18 months. So to the extent that we started to put some incremental capital back to work, say, in the middle or in the second half of this year, you likely wouldn't see any incremental production til the end of -- or at the end -- early 2023.
So in terms of cost to get us back there, I think that $15,000 a flowing BOE number is a pretty good one. In terms of timing yet to be determined. But I before turning it over to Eric here to talk about -- so we're planning on going in terms of long-term debt targets. The only thing I would say is that we are definitely committed to reducing our debt. And I think one of the key highlights that I hope the market picks up from our press release is the fact that we're a bit of a unicorn this year. We developed -- we not only had free cash flow, but we also reduced our debt. So and I always tell people, you shouldn't listen to a bloody thing we say, you just watch what we do. And I think our track record in terms of debt reduction is something that we're focused on. We told the market that we're focused on and will definitely be part of any plan as we move forward.
Yes, Phil, it's Eric. Just with respect to the debt repayment strategy, it really hasn't changed since 2019 and early 2020. We did the last tranche of debt repayment in January and then got -- the strategy obviously got derailed with COVID, the impact on our oil price. As we head into 2021 and then we see the -- see happening on the oil price front, our plan is to reinstitute the debt repayment. We want to obviously take free cash flow and put that against debt repayment. Our first stopping off point, which we've talked about before, is sort of another USD 500 million. That would get us to the USD 2 billion that Derek talked about. And that's not an absolute target. It's more of a metric target, which is, what, 2.25 times to 2.5 times debt to EBITDA at a trough price of around USD 50 for WTI. So that strategy remains top of mind for us. And I think as it relates to any in increase capital, you'd see, I think we'd tell you that you shouldn't expect to see increase in capital stand-alone. I think you'd see debt repayment beside that or ahead of that.
Your next question comes from Neil Mehta from Goldman Sachs. Neil, please go ahead.
I just wanted to talk a little bit about your hedging strategy. I think in the release, you indicated you're 46% hedged for the 2021 volumes at this point. And how are you just thinking about that program is very much front half weighted. I think in the second half, if commodity prices hold here or go higher, you should have a lot of torque to a more open commodity price environment? And then what's the strategy for '22, given the curve is backward dated and there are a lot of moving pieces. So there's a lot there, Derek, but if you can unpack your hedging strategy, that would be great?
And I think we had a very -- when we hedge, we have to have a purpose, there has to be a reason why we do that. And the hedges that you see, these are weighted about 60% to the first half and about 33% to the second half. So the purpose for putting in place the hedges that we did to support our -- was primarily to support our capital program to ensure that we had a visibility on the cash flow, which was going to be needed to execute the program. And we did that as at the end of last year. We have not hedged WTI since early January. And at this juncture, we don't have any plans to add any WTI hedges in 2021. We haven't looked in great depth at 2022 at this juncture. We haven't -- but I think you should expect to see us, if we do hedge, that we will have a reason for why we hedge. And over the last couple of years, it's been to protect our capital program. So I really can't give you a lot of visibility on '22. Yes, we note that the back -- there's fairly steep backwardation. But as time goes forward, and we've got a better idea of when the Saudis are going to bring our OPEC Plus are going to bring incremental barrels back. We expect some of that backwardation will come out of the market.
That's great. And the follow-up is just around the differential outlook. And just how you're thinking about it, where do you see Alberta inventory levels right now? And then how do you see that playing out over the course of this year as you see it? And then it looks like we've got some egress solution, particularly the 370,000 barrels a day coming in from Enbridge Line 3 at the end of the year. So do you see a structurally tighter differential outlook in Alberta? And if you can weigh in on the U.S. Gulf Coast differentials, that would be helpful as well because of how many of your barrels you're able to export down into the Gulf Coast area.
Neil, it's Eric. Yes, the starting point for differentials is the Gulf Coast. That's been structurally very tight for the last six months. And we don't frankly see that changing. And I think if you look at the strip for WCS and AWB in the Gulf Coast, that would echo that comment. It's around -- WCS is around $3 off WTI in the Gulf Coast. We've seen very -- and our peers have seen very significant demand from Asian refineries from both Chinese and Indian. That's been drawing those barrels out of the Gulf Coast as well as the Pad III refiners. So that -- we don't see that structurally changing as we move through 2021 and frankly, into 2022 and onward. The egress that you talk about out of Alberta, there's been marginal egress improvements, which we've been, I think, those differentials in Edmonton we've been benefiting from, with 50% apportionment in the first quarter, you expect to see dips blow out in Edmonton. We haven't seen that. I think that's because of the incremental storage that's been built as well as the rail capacity, which isn't fully utilized, frankly. So we expect to see differentials in Edmonton around $10 to $13. That's why we've been layering in picking away differential hedges around that $11 range. So we think structurally, there's a lot of tailwinds from a differential perspective. Inventories in Alberta, I think, around 30 million barrels. So we've had -- the storage has been there to soak up the apportionment as has the incremental egress. So very positive from a differential perspective, Neil.
Your next question comes from Greg Pardy from RBC Capital Markets. Greg, please go ahead.
Just wondering if we can shift gears a little bit into technology. Obviously, with 2020, it would have limited the ability for you to do probably as much as you wanted to on things like eMVAPEX and so forth. But I'm just wondering if there's any update there?
Sure. I'm going to ask Chi-Tak Yee, he's the principal driver on eMVAPEX to provide an update.
Yes. We -- on the eMVAPEX front, we finished the propane injection phase now on the soft injection phase now, and we are transitioning to what we call the last phase, what is called a blowdown phase, they try to recover the propane that store in the reservoir and also observe what would the ultimate recovery looks like. So that's really the objective for this year for that eMVAPEX part expired. In terms of technology in general, we are shifting a bit of focus on looking at some of the carbon decarbonization technology to see how we could manage our carbon emissions going forward.
Okay. Terrific. Is there anything specifically, then just on the decarbonation you wanted to highlight? Or is it too early?
I think it's too early to discuss at this moment. We would talk about that into -- in our ESG report that's coming out in the mid year.
Chi-Tak. Last question is, what are you targeting then as a recovery rate in the propane?
Well, we hope to get to ultimately, probably about 80%, 85% recovery at the end of the process.
[Operator Instructions] It appears there are no further questions at this time. Please proceed.
I have just a quick thank you for everybody that's joined us for the call this morning. As I have indicated we are very positive not only about what we've been able to do, but also more about the macro environment. Eric alluded to it a little bit in his remarks here with respect to the fact that I think our business has seen fairly significant headwinds for the last six years, and it feels like those headwinds have come around and are becoming tailwinds. So we look forward to bringing you up-to-date on our progress in the quarter in the coming quarters. So thank you for joining us and listening to our call this morning. Good day.
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.