MEG Energy Corp

TSX:MEG

Earnings Call Transcript 2019-Q2

[Operator]

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 2019 Second Quarter Results Conference Call. [Operator Instructions]Mr. Derek Evans, you may now begin your conference, sir.

[Derek W. Evans, President, CEO & Director]

Thank you very much, Sylvie, and good morning, everyone, and thanks for listening in on our second quarter 2019 conference call. In the room with me this morning, I have Eric Toews, our CFO; Chi-Tak Yee, our Chief Operating Officer; and Grant Borbridge, our Senior VP, Legal, General Counsel and Corporate Secretary. Just a reminder 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 try to keep my remarks concise to leave time for Q&A. I want to touch on our financial and operating results for the quarter but also give you a picture of where we are today relative to some of the objectives that I laid out for the organization earlier on in the year. As you will have seen from our Q2 news release yesterday, we delivered record free cash flow of $195 million in the quarter. And as promised, we've taken first half 2019 free cash flow and applied it to debt repayment, repaying $285 million post the end of the second quarter. Since we last reported, we've been busy working hard to deliver a very strong operational set of Q2 results, as demonstrated by $227 million of adjusted funds flow in the quarter. Concurrently, through and post the quarter, we worked diligently to put in place a new 5-year credit facility and repaid $285 million of debt. This will not be a onetime event. We remain committed to further strengthening our balance sheet, with debt reduction remaining a top priority for free cash flow. Q2 was a very strong quarter with average bitumen production of 97,288 barrels a day at a steam-oil ratio of 2.16x. Third-party curtailment credits purchased in the second quarter allowed us to opportunistically increase production levels to near our current production capacity of 100,000 barrels a day and enhanced funds flow in a favorable pricing environment despite ongoing Alberta-wide mandated curtailments. Our strong second quarter results illustrate the impressive cash flow-generating capacity of the organization under a more conducive price environment. With cash netbacks of $37.88 per barrel, we generated adjusted funds flow of $227 million in the second quarter of 2019, an increase of $76 million compared to Q1. Taking into account $32 million of capital investments, we generated free cash flow of $195 million in the quarter. Year-to-date free cash flow of $293 million is in stark contrast to the $767 million of negative free cash flow accumulated through the 2016 to 2018 period and dramatically punctuates the change in strategy to a capital program that sustains production levels, with debt reduction remaining a top priority for free cash flow. In Q2, cash flow was positively impacted by the increase in WTI pricing from USD 54.90 per barrel in Q1 to USD 59.82 per barrel and the continued narrowing of the AWD differential (sic) [ AWB differential ] from USD 14.50 a barrel to USD 12.32 per barrel over the same period. However, in addition to the improvement in WTI and AWB pricing is MEG's ability to access the premium Gulf Coast market where we trade relative to global heavy oil prices. Through our 50,000 barrels per day commitment on Flanagan South/Seaway and delivered rail capacity, 1/3 of our barrels realized an average of USD 3.50 per barrel premium relative to those sold within Western Canada after taking into account transportation costs. This advantage will only grow in significance as our commitment on Flanagan South/Seaway grows to 100,000 barrels per day in the second half of 2020. For clarity, this capacity currently exists, and it's not contingent on Enbridge's Line 3 replacement project being placed into service or Enbridge's current contract carriage discussions. By the middle of next year, we will have contracted egress in place for up to 90% of our production to high-value markets. Even with the impact of forecast apportionment, we expect roughly 2/3 of our barrels will reach the premium U.S. Gulf Coast next year where historically, they have realized a USD 5 to USD 7 per barrel discount to Mars. This will reduce our exposure to a landlocked Edmonton price market. Obviously, this -- there is upside going forward as Enbridge's Line 3 replacement and other export pipelines are brought into service. There continues to be a very favorable demand outlook for our barrels at the U.S. Gulf Coast. We continue to see supply under pressure as traditional import sources, such as Venezuela, falter and with Mexican production at record lows. Conversely, demand is strong, with analysts currently estimating an incremental 1.5 million barrels per day of global demand for heavy oil coming onstream in 2019. This is to meet the surge in petrochemical processing capacity being added globally this year as well as demand from traditional refinery projects. I'd like to spend a few minutes addressing what has been accomplished on the debt front. Post the quarter, MEG repaid the remaining balance of its first lien term loan of approximately $285 million. This repayment was made from free cash flow generated in the first 6 months of 2019 and is the initiation of MEG's stated strategy of prioritizing free cash flow to debt repayment. Annual interest savings will be approximately $18 million. Also, post the quarter, MEG successfully completed the amendment and extension of its outstanding credit facilities with a core contingent of MEG's existing bank group. These new -- the new facilities include an CAD 800 million 5-year revolving credit facility and a CAD 500 million LC facility. Because MEG's philosophy has been and remains to not draw on its revolving credit facility, the size of the new facilities was set to provide confidence that MEG continues to have an abundance of financial liquidity in a sustained low cycle pricing environment while providing approximately $14 million of annual go-forward cost savings, primarily from the reduction in the undrawn standby fees. The terms MEG achieved in this financing, while -- which maintain or enhance the company's financial flexibility found in its existing revolving credit facility to execute its business plan, speaks to the quality of MEG's asset-based operational track record, cost reduction strategy and commitment to financial discipline. Combined, the cash cost reduction from the combination of the debt repayment and bank refinancing are approximately $32 million per year, which significantly contributes to free cash flow generation as we move forward. As I stated in our Q1 conference call, one of our key objectives for 2019 was cost reduction. Q2 net operating costs of $4.66 per barrel were down significantly compared to Q1 operating costs of $6.17 per barrel driven by higher bitumen sales and lower energy costs. Q2 G&A expenses of $1.81 per barrel of production represents a 20% decrease from the first quarter of 2019 due to increased production levels and the impact of changes to staffing levels. In the second quarter, we had a onetime after-tax noncash charge against earnings of $228 million that recognized the uncertainty of future benefits associated with certain noncore assets. These noncore assets relate to equipment, materials, engineering costs, a partial upgrading technology and land lease and evaluation costs that will not contribute to the corporation's development plan or cash flow in the foreseeable future. This onetime noncash charge is the result of management's cost structure review. The disposal or sale of these noncore assets is expected to reduce the corporation's go-forward cash costs by approximately $10 million per year. This annual savings in combination with the debt repayment and bank refinance savings total annual savings of $42 million, which will be applied to ongoing debt reduction. Capital spending came in at $32 million in the quarter relative to our capital budget of $200 million. The previously announced 2019 discretionary capital budget of $75 million will not be sanctioned in 2019 given the existing provincially mandated production curtailment, current lack of market access and our ongoing prioritization of debt repayment. The 2019 capital program is primarily designed to sustain production capability at 100,000 barrels per day while completing the in-progress expansion of the oil-treating facilities to 120,000 barrels a day. While we have the ability to produce 100,000 barrels a day of production, the current 2019 production guidance of 90,000 to 92,000 barrels a day reflects the continued impact and uncertainty of the Alberta government's mandated production curtailment. In conclusion, the MEG of today is a very different company than the one of the past. At current strip prices, we anticipate a significant strengthening of our balance sheet, with total net debt to EBITDA to be approximately 3x by the end of this year. And we expect to generate material free cash flow going forward as we shift from a focus on growth and a history of significantly outspending cash flow to harvesting and optimizing the value of our business. As I've said before, our primary focus in the short and the medium term will be debt repayment. We will continue to update you on our progress in that regard. I've had the privilege of leading this company for almost a year. I'm very proud of what we have been able to accomplish in such a short period of time given the distractions of last fall. We are making great progress on reducing debt and cost structures as well as focusing on capital discipline and optimizing revenue through marketing and egress optionality. I look forward to updating you on our progress in the coming months. Sylvie, I think with that, I finished my prepared remarks, and we'll turn it back to the participants in the call for some Q&A.

[Operator]

[Operator Instructions] And your first question will be from Phil Skolnick at Eight Capital.

[Philip Ross Skolnick, Principal & MD Research]

A couple of questions. First, just on the debt reduction, how should we think about it, timing and stuff? Is it going to be -- are you looking to try to do a quarter-by-quarter event? And -- or is it just kind of you wait and see how your free cash flow comes in, and then you work it that way?

[Eric Lloyd Toews, Chief Financial Officer]

Thanks, Phil. It's Eric speaking. Yes, I think the first half of the year is a good example of how we'll look at this on a go-forward basis. We don't want to get over our skis as it relates to not having free cash flow to repay debt. So we're going to watch -- we're going to watch the market, watch the build of free cash flow. And then when we think about what tranches that we're going to repay, we're going to consider things like liquidity, restrictiveness of the covenants, pricing and maturity. So we're working through that right now. But -- so I think the first half of the year is a good example of how we'll think about the rest of the debt repayment.

[Philip Ross Skolnick, Principal & MD Research]

Okay. Great. And second question is, in terms of rail, you've basically stated that rail in the past -- well, in the past, you stated that rail is now going to be more of a permanent part of your marketing strategy. Are you looking to try to get more rail? And if possible, are you looking at the government's rail capacity? Any of that?

[Derek W. Evans, President, CEO & Director]

So Phil, it's Derek. We are looking at the government's rail capacity and trying to understand -- we and others are trying to understand what the contractual obligations and commitments are in that -- at that type of set of assets. I think the other thing, though, that we're continuing to look at and trying to understand -- you know as well as we do, the diluent is a huge part of our business. And so we continue to investigate DRUs, but we also are looking very clearly at sort of technologies that we could use to reduce the amount of diluent that we need and/or diluent -- less diluent that we could put in up at site as we transport our product down and then put it into rail. So it's a big focus of ours in terms of cost reduction, continuing to look at diluent and diluent as it applies to a neater barrel of bitumen and what rail could do for us in that regard. So rail will be a very important part and permanent part of our transportation structure going forward. And for -- the primary reason is we just don't have certainty on when all of these pipes are going to come through. And we think we owe our shareholders the -- we have the responsibility to our shareholders to ensure that we continue to build rail optionality and egress optionality in that regard.

[Philip Ross Skolnick, Principal & MD Research]

Yes, absolutely. And just a final one then, how are you thinking about getting to offshore markets like Asia, places like that?

[Eric Lloyd Toews, Chief Financial Officer]

Phil, it's Eric again. We've done that in the past, and we have access down to the Gulf Coast, both at Beaumont and St. James, and we have loading capabilities. So we continue to watch that. We watch the pricing. The importance for us is getting our barrels known internationally, particularly in Asia. So that's something real that we've been doing, and we'll continue to look at that on a go-forward basis. And we have the infrastructure to make that happen.

[Operator]

Next question will be from Nick Lupick at AltaCorp Capital.

[Nicholas Stephen Lupick]

Two quick questions for me. First one is on guidance. You've reiterated your 90,000 to 92,000 barrel a day guidance range. Year-to-date or the first half of the year, you've done around 90,000 barrels a day, a bit more than that on sales with drawdown on inventory. Just wanted to kind of see your thoughts on second half of the year. Do you have any kind of planned maintenance scheduled? With the curtailment being loosened, I guess, from the first half of the year, where we were in Q1, can we just take the 90,000 to 92,000 to be a relatively conservative estimate given you don't have control over what the government does with the curtailment?

[Derek W. Evans, President, CEO & Director]

I'm going to ask Chi-Tak to address that. He knows more about curtailment than anybody at the table and is driving obviously our production guidance. So over to you, Chi-Tak.

[Chi-Tak Yee]

Thank you, Derek. As you rightly point out, our first half averaged around 92.2 barrels per day -- or 92,200 barrels per day. Our guidance is 90,000, 92,000. At this moment, the government curtailment program, our allocation on that is roughly in that range. That's about a 91,000 barrel range. So it -- that depends on our ability to acquire any additional curtailment credit or not. So at this moment, the 90,000, 92,000 is still well within the range, what we're seeing for the second half of the year. In terms of turnaround activities for the second half, if you recall, last year, because of the very high differential, we advanced quite a bit of the turnaround work from this year into 2018, which turned out to be a pretty good move because it allowed us in Q2 to use our capacity to acquire all those extra barrels. And also because of that, we don't see any more turnaround type of activities for the balance of the year.

[Nicholas Stephen Lupick]

Perfect. Second question I had, and I'm just trying to see if I heard you right, Derek. You've mentioned your expansion on the Flanagan line, 100 -- to 100,000 barrels a day, was not contingent on the Line 3 expansion. Is that to say that you've received assurances from Enbridge that they will honor that agreement even if they run into further headwinds in expanding their Line 3 expansion?

[Derek W. Evans, President, CEO & Director]

So Nick, the capacity, the incremental 50,000 barrels a day on Flanagan South/Seaway, it already exists. Somebody else is using it. It just contractually moves into our name in July of 2020. So it's not contingent on anything Enbridge is doing or not doing today. Somebody else is using that capacity. It just moves into our name in the second half of next year. And that's -- as you rightly point out, one of the big benefits of that incremental 50,000, it's not contingent upon anybody building anything new or any sort of -- nor was it exposed to any sort of concerns from parties that the line may run through.

[Operator]

Next question is from Greg Pardy at RBC Capital Markets.

[Tom Callaghan, Associate]

It's actually Tom Callaghan just on behalf of Greg. Just curious, looking at the $10 million in run rate savings you guys have framed there in terms of the noncore assets, how should we be thinking about when that kicks in? Is that kind of mid-third quarter or something else?

[Derek W. Evans, President, CEO & Director]

Tom, I'll take that. It's Derek Evans. I think you should be -- I would factor that in fully in 2020. And I'd start to bleed it in, in Q3 and Q4. I'd bleed in approximately $5 million of that over the last 2 quarters of 2019.

[Operator]

Next question is from Neil Mehta at Goldman Sachs.

[Emily Christine Chieng, Associate]

This is Emily Chieng on behalf of Neil. You guys have committed to a $200 million CapEx budget for 2019, which, as you mentioned, full -- includes limited maintenance activity. Are you able to give us a sense of what that may look like in 2020? And thinking about the $75 million of discretionary CapEx, does that get pushed into 2020? And I guess how are you seeing sustaining CapEx on a per barrel rate normalize next year?

[Derek W. Evans, President, CEO & Director]

Emily, I'm going to ask Chi-Tak to take a stab at that for us.

[Chi-Tak Yee]

Yes. So this year, we -- year-to-date is around $85 million for CapEx, and this year's a bit different than previous years, and previous year was more front end loaded. This year, because of the government curtailment, that profile's going to change. So we do expect the $200 million of CapEx for the year. For next year, we haven't got firmed-up numbers yet. As you appreciate, that would require Board approval. At this moment, we're looking at approximately in the range of around $300 million. Now obviously, like I said earlier, that's subject to Board approval. So that's kind of the range we are talking about.

[Derek W. Evans, President, CEO & Director]

So Emily, the -- just to -- the other part of your question, we estimate somewhere between $6 and $8 of sustaining capital, so -- and then -- which typically runs you in -- somewhere in the neighborhood of $240 million, $250 million. And then there's an incremental $50 million in there for facility work and sort of growth projects, one of which you would have seen today us talking about 120,000 -- see us in barrels a day of oil production capacity. The -- you'd also asked about the $75 million of incremental capacity. What are we going to do with our capital? What are we going to do with that? We're committed to debt reduction. And until we see curtailment lifted, until we see better egress optionality for those barrels, we're going to continue to work on debt reduction as opposed to building volumes.

[Emily Christine Chieng, Associate]

And just one follow-up. You mentioned a couple of noncore asset dispositions during the quarter. Can you discuss what these assets were and perhaps what else is in the portfolio that could be put up for sale and if there's any time line to achieving this?

[Derek W. Evans, President, CEO & Director]

So there's fundamentally 3 big items. There's some lands in our -- what I would call our fourth growth project in the Duncan area. These are lands that we are dropping. We're not going to renew the leases on them. They were at that point in their lives where the annual rentals on those leases were about to increase in cost. We can't see ourselves getting to those lands in a timely manner. You'll remember that at Christina Lake, we have the ability to go from 100,000 barrels a day up to 200,000 barrels a day. We have our Surmont Project, which will -- is over 150,000 barrels a day; and May River, which is the third piece of our inventory. So this fourth piece of our inventory was something that we felt quite comfortable trimming off and letting those lands disappear. We've also -- are in the process of selling our HI-Q technology. And that's another part of this in terms of G&A and R&D costs. And then our surplus inventory, so we have quite a bit of surplus equipment that we will be moving into the market. But the storage costs on that surplus equipment run us approximately $3 million a year, and they're part of that $10 million. So as we move that equipment out, you'll see reductions in terms of our capital and G&A and R&D costs.

[Operator]

Next question will be from Phil Gresh at JPMorgan.

[Philip Mulkey Gresh, Senior Equity Research Analyst]

A couple of quick questions here. First one, just on the quarter, looking at the results, I saw that the rail costs to the Gulf Coast were up a couple of dollars quarter-over-quarter. And so I just want to understand that change and if this new higher run rate would be the right way to think about it moving forward.

[Derek W. Evans, President, CEO & Director]

Do you want to take that?

[Eric Lloyd Toews, Chief Financial Officer]

Sure, Phil. It's Eric speaking. The primary reason for the increase in the rail -- or the rail cost number is we have some onetime costs related to turning back some leased cars and renewing the fleet to different railcars. So that's the reason for that, and we expect to see it normalize down to that sort of $20 range. But it's a moving target mostly because it depends on utilization of the Bruderheim facility that we're loading at. So you can expect to see a slightly lower delivered rail cost on a go-forward basis, somewhere probably between $18 and $20.

[Philip Mulkey Gresh, Senior Equity Research Analyst]

Okay, okay. Great. Second question, just looking at the cash flow statement, obviously, there was a pretty big working capital headwind in the first quarter. You got some of that back in the second quarter. And I was just curious, as you thought about that leverage target for the end of the year, whether there was any assumption of additional tailwind from working capital or if it's just status quo from here.

[Eric Lloyd Toews, Chief Financial Officer]

Yes, Phil. It's Eric again. Working capital is going to be somewhat normalized. We had a -- in the last year, we had a big reduction in oil price, and we had a reduction in CapEx, which obviously had a big impact on working capital. And we see that much more normalized as we move into the back end of this year and into the first quarter of next year. So we wouldn't expect and we're not modeling a big working capital draw into next year.

[Philip Mulkey Gresh, Senior Equity Research Analyst]

Okay. And then my last question was just to follow up to the prior question around the additional capacity on Flanagan. Just to clarify, if -- would there be any apportionment potential -- if Line 3 is delayed, would there be potential apportionment impacts on your ability to use that full 100,000?

[Derek W. Evans, President, CEO & Director]

Phil, it's Derek. So currently, we are apportioned on that line somewhere in the neighborhood of 40%. So we've got 50,000 barrels a day of capacity currently. And we're running somewhere in the neighborhood of 30 to 33 depending on the level of apportionment in the month. So yes, you should expect that the -- we're going to see apportionment on the other 50,000 barrels a day. And as we model internally and think about where we're going to be, we've just assumed that, that 100,000 will probably be somewhere between -- on an apportioned basis, somewhere between 60,000 and 70,000 barrels a day for us next year. So the second...

[Philip Mulkey Gresh, Senior Equity Research Analyst]

Okay, great. Yes, got it.

[Derek W. Evans, President, CEO & Director]

All right.

[Philip Mulkey Gresh, Senior Equity Research Analyst]

Go ahead.

[Derek W. Evans, President, CEO & Director]

Yes. No, I was just going to say, the whole apportionment piece, we are expecting that apportionment will be relieved and reduced somewhat by obviously incremental rail coming on in the province of -- rail capacity, egress capacity coming on in the province of Alberta in the second half of the year. But also, Enbridge getting the Line 3 replacement up and running will also help with that -- the level of apportionment and obviously lift the apportioned barrels that we'd be able to run on Enbridge Line -- or on Flanagan South/Seaway.

[Philip Mulkey Gresh, Senior Equity Research Analyst]

Sure. Okay. Last one, and this might be a hard one, but I know you're talking about asset sale potential. But I'm just wondering if, in your mind, there's any kind of order of magnitude you might be hoping to achieve over a certain period of time. I know asset sale targets might be kind of tough to quantify sometimes, but if you have any thoughts on that.

[Derek W. Evans, President, CEO & Director]

So there's -- we don't have an asset sale target. We're working bits and pieces of assets. We've sold some land for $5 million in the second quarter. We'll continue to undertake those types of pieces. But -- and they're important work. We're selling inventory out of our warehouses that we're clearly not going to get to. I wouldn't want to put a dollar value on that, but I certainly wouldn't want to leave you with the impression that we're not being diligent about picking up the nickels, dimes and quarters and making sure that they make their way into the bank account. Operator, I think -- I'm being very mindful of people's time. I think we should try and wrap the call up. And I'd just like to thank everybody for participating this morning, and we'll drive forward. And I will be available to answer any questions should they have any.

[Operator]

Thank you, sir. Ladies and gentlemen, this does conclude your conference call for today. Once again, thank you for attending. And at this time, we do ask that you please disconnect your lines. Enjoy the rest of your day.