MEGEF Q3 2019 Earnings Call

Operator: Good morning. My name is Jessica, and I will be your conference operator today. At this time, I would like to welcome everyone to the MEG Energy’s 2019 Third Quarter 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] Thank you. Mr. Derek Evans, CEO, you may begin your conference.

Derek Evans: Thank you, Jessica, and good morning, everyone, and thanks for joining us for our third quarter 2019 conference call. In the room with me this morning, I have Eric Toews, our CFO; Chi-Tak Yee, our COO; and Grant Borbridge, Senior Vice President, 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. This is a relatively straightforward quarter. Instead of rehashing the press release in the MD&A, I’ll limit my remarks to a few of the key aspects of the quarter to leave more time for Q&A. We had an excellent quarter with record low operating costs, free cash flow of $152 million and additional debt repayments, bringing year-to-date debt repayment to $481 million. We remain committed to applying all free cash flow after sustaining capital to further debt reduction and we’re laser focused on reducing all cost structures. Bitumen production in the third quarter was impacted by ongoing Government of Alberta mandated curtailment. We purchased third-party curtailment credits of approximately 3,100 barrels a day in Q3 versus approximately 8,500 barrel a day of credit in Q2 allowing us to increase production levels to 93,278 barrels a day in Q3 versus Q2 production of 97,288 barrels a day. In Q3, fewer third-party curtailment credits were available to purchase. MEG realized the third quarter 2019 average AWB blend sales price of US$45.63 per barrel compared to US$51.72 per barrel in the second quarter of 2019. The change in average AWB blend sales price per quarter-over-quarter is primarily due to a US$3.37 per barrel reduction in the benchmark WTI index combined with WTI AWB differentials at Edmonton widening to US$14.52 per barrel from US$12.32 per barrel; and at the U.S. Gulf Coast widening to a discount of US$2.50 per barrel from a premium of US$1.64 per barrel. MEG sold 33% of its sales volumes to the U.S. Gulf Coast market in the third quarter of 2019 compared to 34% in the second quarter of 2019. Excluding transportation and storage costs upstream of the Edmonton index sales point, MEG’s net AWB blend sales price at Edmonton average US$41.60 per barrel in the third quarter of 2019 compared to the average AWB index price at Edmonton of US$41.93. Notwithstanding that Enbridge mainline apportionment averaged 44%, MEG was able to capture pricing in-line with the Edmonton index highlighting the value of MEG’s North American marketing strategy. Adjusted funds flow for Q3 was $192 million or $0.63 per share with $152 million of free cash flow after taking into account $40 million of capital expenditures. For the nine months ended September 30, we have generated free cash flow of $443 million. As of October 30, we have repaid $481 million of outstanding long-term debt in 2019, including $385 million during the third quarter of 2019 and $88 million subsequent to quarter-end. Annualized interest savings from these repurchases are expected to be $30 million. These annualized interest savings, when combined with the annualized $14 million of credit fee savings associated with the amendment of MEG’s revolving credit facility brings the aggregate credit-related cash cost savings contribution to annual free cash flow to approximately $44 million. In the first nine months of 2019 capital expenditures total of $126 million relative to MEG’s 2019 capital budget of $200 million, which was set during the implementation of the Alberta Government’s mandated production curtailment program in January 2019. Over the course of 2019, MEG has been successful in finding capital cost savings and undertaking minor scope changes that will allow the Corporation to deliver the original $200 million budget for approximately $170 million. As a result, based on the expected operational benefits, including plant integrity and turnaround management, MEG has shifted into 2019 approximately $30 million of expected 2020 capital expenditures to accelerate the completion of the Corporation’s in-progress brownfield project at the Phase 2B central processing facility, which includes incremental steam generation, water handling and oil treating capacity. This project is expected to be completed in the first half of 2020. And just as a point of clarification, what we’re talking about here is the central processing facility. There is no incremental capital associated with growing our production in this additional $30 million. Third quarter 2019 non-energy operating cost of $4.22 per barrel and strong power sales had the impact of offsetting 95% per barrel energy operating rig costs, resulting in a net energy operating expense of only $0.08 per barrel resulting in a record low net operating cost of $4.30 a barrel. During 2019, the Corporation has been able to purchase third-party curtailment credits, which have positively impacted the Corporation’s production and sales results compared to the original guidance assumptions based on results achieved to date the Corporation has revised its 2019 annual guidance. Production volumes are now targeted to be in the range of 92,000 to 93,000 barrels a day and non-energy operating costs in the range of $4.75 to $5 per barrel. General and administrative expense remains unchanged in the range of $1.95 to $2.05 per barrel. The Corporation’s operational guidance assumes the Government of Alberta mandated production curtailment program remains in place for 2019 and into 2020. In conclusion, we remain focused on driving efficiencies in our business from an operational and cost perspective, and we’ll continue to direct all free cash flow to debt repayment. Our focus on debt reduction will preclude us from growing our production capacity until such time as we see at the end of curtailment and additional egress pipelines built. We’re making great progress on reducing debt and our cost structures as well as focusing on capital discipline and optimizing revenue through marketing and egress optionality. We look forward to providing the market with our 2020 guidance on November 21 of this year. With that, Jessica, I will turn the call back to you and to our listeners for their questions.

Operator: Thank you. [Operator Instructions] All right. Your first question comes from Phil Gresh of JPMorgan. Please go ahead.

John Royall: Hey, good morning, guys. This is John Royall filling in for Phil. So, with the pull forward of the $30 million of brownfield growth CapEx into this year, how much spend would be left in 2020 to complete phase 2?

Derek Evans: Hello.

John Royall: Yes. Sorry, can you hear me?

Derek Evans: Sorry. I know we just got disconnected there for a second. Can you just re-ask your question?

John Royall: Yes. No problem. Sorry, this is John Royall filling in for Phil, just had a question on the CapEx. So, with the pull forward of the $30 million in brownfield growth, how much would be left in 2020 to complete phase 2?

Derek Evans: So, when we talk about phase 2, we’re just talking about tax CPF side of Phase 2, and there would be approximately $20 million worth of capital left to be completed in sort of the first four months of 2020.

John Royall: Okay, great. Thank you. And then given your capital efficiency in 2019, can you give your way to thoughts on the run rate level of sustaining CapEx in the business?

Derek Evans: I think the easiest way to think about the run rate on sustaining capEx is really to think somewhere between $6 and $8 a barrel. There’ll be fluctuations on a year-to-year basis given timing, but as we model the business going forward, we kept it, we use about a $7 a barrel sustaining capital number.

John Royall: Great. Thank you very much.

Derek Evans: Thank you.

Operator: Your next question comes from Emily Chang of Goldman Sachs. Please go ahead.

Emily Chang: Good morning. just following up on the CapEx question, I guess with the pull forward is $30 million into 2019, should we therefore expect sort of $30 million reduction out of the 2020 budget from current levels?

Derek Evans: I think it’s fair to assume, Emily that we’ve been modeling sort of $300 million up to this point. So, I think as we move towards reducing our 2020 – producing our 2020 guidance, you should assume that that guidance for 2020 on a capital basis is likely to be $270 million or less.

Emily Chang: Got it. That’s helpful. And just one follow-up please on condensate. Can you remind us again, your ability to import from the U.S. Gulf Coast given I guess the strength of local condensate pricing and how should we think about the progress you guys have made when it comes to under blending barrels ahead of rail? Are there any sort of cost saving targets that you guys looking at when it comes to condensate management here please?

Derek Evans: Let me handle the last half of the question, then I’ll ask Eric to talk about the first part. But we continue to work on the three initiatives that we have on the go in terms of under blending. And yes, the one with that near-term potential is the butane blending. And we’re working with our partners both on the pipeline and the owners of the pipeline to advance that as quickly as possible and realize the significant savings associated with that. So, I think it’s fair to say that butane blending will be up and running in 2020. Some of us would like to see it up and running a lot sooner than where it’s currently scheduled at. And I know there’s a meeting next week to try and advance that a lot faster than what is currently on the books, which is to have it on in the second half of 2020 this point.

Eric Toews: And Emily, it’s Eric; we move a half of our condensate up out of the Gulf coast on Southern lights and then the other half we source in the local markets.

Emily Chang: Great. Thank you.

Operator: Your next question comes from Phil Skolnick of Eight Capital. Please go ahead.

Phil Skolnick: Yes, thanks. A couple of questions. One, it was reported in Bloomberg last week that there was some Canadian access Western Blend that was shifted West coast and India. Just seeing if that was anything from your production and how do you see that progressing from your standpoint?

Derek Evans: That was not our production going to India. So that limits the number of players somewhat substantially. But I think more to the point; it’s a very interesting market as is China and Asia in particular on that accrued oil to chemicals business. We see this as a growing market and as we said before, a part of the reason we’ve added two tankers on the U.S. Gulf coast. And they have the ability to lift cargos out of the U.S. Gulf Coast as we believe that that market could get overrun as with incremental volume. So, the development of overseas markets I think is very, very important in terms of the long-term viability of the AWB product.

Phil Skolnick: Okay. just back on the 2B facilities. So next year, I guess, you’re going to be having a turnaround like how does – this should – does this provide any kind of flexibility in terms of steam and being able to use that to, I guess, offset some of the impact on the production side of the turnaround?

Derek Evans: Absolutely. And so the – there is the Phase 2B facilities that includes an evaporator in two drum boilers – two new drum boilers. And I think those drum boilers are about 13,000 barrels a day of steam oil. So, there’d be somewhere in the neighborhood of three – well three times that. So almost 40,000 barrels a day of steam, so that is highly valuable as we go through that turnaround, because that part of the facility doesn’t get turn around and it allows us to continue to produce steam while the other part of the facility is down in that. Just for clarity, we’re not taking the whole facility down. We’ll be taking a portion and we’ll provide greater clarity as to what that turnaround could fundamentally look like in terms of time. And also, the amount of oil we’ll have off production as we drive towards our 2020 guidance release on November 21.

Phil Skolnick: Okay. And then just finally, the Alberta government just announced the curtailment relief for rail shipment literally when your conference calls started, any – I mean, I’m assuming that you had been talked with them. Any thoughts in terms of like what the upside is on your production levels based on this?

Eric Toews: Hey, Phil, it’s Eric. We are – we saw that come across the wire, we’re – we have a sense it’s going to be based off Q1, obviously. So, we know what that number is. It might be 8,000 to 10,000 barrels a day for us potentially. We have to work to that with our team here with the government.

Phil Skolnick: Is that a blend number or is that a bitumen number?

Eric Toews: Blend.

Phil Skolnick: Okay. Thank you. That’s it for me.

Operator: [Operator Instructions] All right. It appears there are no further questions at this time. Please proceed.

Derek Evans: Well, Jessica, thank you, for the people that joined us on the call, thank you very much. I hope everybody has a great day and look forward to talking to you next quarter.

Operator: Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.