Tourmaline Oil Corp

TSX:TOU

Earnings Call Transcript 2018-Q2

[Operator]

Good morning. My name is Sharon, and I will be your conference operator today. At this time, I'd like to welcome everyone to the Tourmaline Oil Corp. Second Quarter Results Conference Call. [Operator Instructions] Brian Robinson, you may begin your conference.

[Brian G. Robinson, VP of Finance, CFO & Director]

Thank you, operator. And welcome, everyone, to our discussion of Tourmaline's results for the 3 and 6 months ended June 30, 2018. My name is Brian Robinson. I'm the VP Finance and CFO for Tourmaline.Before we get started, I would refer to the advisory on forward-looking statements contained in the news release as well as the advisories contained in the Tourmaline AIF and MD&A available on SEDAR. I'd like to draw your attention to the material factors and assumptions in those advisories.I'm here with Mike Rose, Tourmaline's President and CEO. Mike will start by speaking to some of the highlights, and after his remarks, we will be open for questions.Mike, please go ahead.

[Michael L. Rose, Chairman, President & CEO]

Thanks, Brian. Good morning, everybody. We're pleased to review our Q2 and 6-month financials and provide a bit of an EP update. So a few highlights. We had 6-month 2018 cash flow of $624.5 million on total EP capital spending of $464 million. We reduced net debt by a further $85 million in Q2 of '18 from Q1 of '18, so down another 5%. And so far in the 6 months, we've reduced net debt by $198.6 million. Given the strong free cash flow, we elected to increase the quarterly dividend by 11% to $0.10 per common share per quarter, and that'll start in the third quarter of 2018. First half '18 production of 264,707 BOEs per day was up 13% year-over-year. We're in a position to increase our 2018 exit production so the range is now 290,000 to 297,500 BOEs per day. Q2 OpEx was $3.18 per BOE, and that's actually down 5% from the prior quarter. And we had after-tax earnings in the quarter of $25.6 million on an average realized total gas price of $2.25 an Mcf, and that's an 89% premium over the average Q2 '18 AECO index price, and that's a function, of course, of our well-diversified marketing and transportation portfolio. Looking at our financial results in a little bit more detail. 6-month free cash flow is up -- essentially $217 million or $171 million after paying dividends of $46.2 million. Q2 cash flow was $272.3 million, and there's no change to anticipated full year '18 cash flow of $1.34 billion. And there's also no change to our full year '18 EP capital budget of $1.08 billion. Net debt has been reduced by approximately $200 million to a 6-month net debt at June 30 of $1.54 billion, essentially making a very strong balance sheet even stronger. We think potentially improving winter oil and, particularly, natural gas prices provide some upside beyond cash guidance for Q4 '18 and Q1 of 2019. Time will tell. And as mentioned, of course, given the strong free cash flow generation and our steadily improving balance sheet, we were able to increase the dividend to $0.10 per common share per quarter. So far in the year, we've completed asset sales of $71 million with 0 production impact and negligible reserve impact. And we are targeting a further $70 million to $80 million of similar noncore asset sales through the balance of '18 and into the first quarter of 2019 and are working on some of those now. Moving to production. Q2 '18 average production of just under 261,000 BOEs a day was below the originally anticipated guidance range for Q2 of 265,000 to 275,000 BOEs per day. Q2 production was impacted by a failed -- compressor failure at the Musreau plant in the Alberta Deep Basin and by multiple unplanned outages, primarily on the Enbridge system in North East, BC and on the Peace River High. The Musreau compressor has been replaced, and that plant is back to full production. We expect full year average production of 267,500 to 275,000 BOEs per day, so a slightly lower range, and that's reflecting the impact of the unplanned outages in Q2 and a little bit in Q3. We'll have a very strong second half. The second half EP program is anticipated to yield Q4 '18 production of between 285,000 and 295,000 BOEs per day. We'll bring onstream approximately 152 wells during that time period. We've been staging the '18 EP program to maximize our production volumes for the winter in order to fully capitalize on what we see as improving winter '18/'19 natural gas prices. A slightly higher '18 exit production range is now in effect, 290,000 to 297,500 BOEs per day and that includes liquids production of 62,500 barrels per day. So essentially, we're exiting '18 above our full year '19 anticipated production of 291,000 BOEs per day, the average for full year '19, so puts us in a really strong position for 2019. Moving to the EP program and a few select updates. On the drilling front, we're currently operating 14 drilling rigs. We'll drill approximately 140 wells in the second half of '18. We currently have 45 DUCs, or drilled uncompleted wells, in inventory, and we're just beginning to ramp up our fracking program, and that'll be fully operational during August. Bringing 152 wells onstream across all 3 core areas with average 30-day IPs in excess of 1,000 BOEs per day, you can see there's a significant amount of production that will be brought onstream. And that production is focused on liquid-rich horizons, so those 4 main liquid-focused facility projects that we disclosed in May remain on schedule for the fourth quarter '18 start-up. And all 4 projects are included in our '18 EP capital program. Specifically, the Doe 2-11 sweetening and debottlenecking project will start up in October, and it will add between 3,000 and 3,500 barrels per day of condensate. We have a number of liquid-rich Montney turbidite wells ready to fill that facility as soon as it is ready. The Spirit River 13-28 compression expansion project is expected to start up in the second half of October, and it will bring onstream between 2,500 and 3,000 barrels per day of new light oil production, and along with that will come 10 million to 15 million per day of liquid-rich natural gas. The Wroe compression expansion project and Cecilia pipeline loop in the Alberta Deep Basin, they focus on some of the liquid-rich horizons that we've been developing over the past 12 months. That will be onstream in the second half of October. Those gas volumes will also access the deep-cut facility at Saturn through the Cecilia plant, so kind of a double win there. And the South Gundy drilling and condensate tie-in project will start up in October as well. It'll add approximately 1,500 barrels per day of incremental condensate production and 20 million to 30 million a day of natural gas. And of course, this project is complementary to the ongoing large deep-cut plant that we're constructing. We provided an update to our Cardium gas condensate play on the western margin of our Deep Basin asset. The next 2 wells in the play, so the fifth and sixth wells overall, have tested at the top end of our performance range. The 13-36 well was testing gas at 26 million a day at a tubing pressure of 11.4 MPa with 846 barrels per day of condensate at the end of the 5-day flow test. Similarly, the 16-2 well was testing gas at 26.5 million at a flowing tubing pressure of 12.1 MPa with 815 barrels per day of free condensate at the end of the test. So very strong wells. To date, 4 of the initial 6 wells in the play have estimated, and these are company estimates, EUR of between 10 and 12.5 Bcf of gas and 250,000 to 300,000 barrels of condensate. So very attractive economic targets as our average completed well costs are about CAD 4 million thus far. Additional delineation wells are planned for this play in the second half of '18 and through into the winter of '19 as we continue to delineate what is a very large-scope play. Turning to Gundy Creek, our BC Montney development. The Phase 1 development remains on schedule for a second half '19 start-up for the 200 million a day deep-cut plant, and we're actually constructing that in the field right now. Phase I development also yields or brings onstream between 15,000 and 17,500 barrels per day of condensate propane and NGLs. So really this is a 50,000 BOE a day growth project that's literally only 12 months away. We also continue to evaluate the final timing for a potential Phase 2 development or a doubling of what's going to be on the ground in a year. It's essentially an incremental 50,000 BOE a day project above and beyond the current 5-year plan when we decide to do it, and we'll be looking at that over the next 6 months or so. So that concludes the formal commentary, and Brian and I are more than happy to take your questions.

[Operator]

[Operator Instructions] Your first question comes from Brian Kristjansen with Macquarie.

[Brian Kristjansen, Research Analyst]

Mike, with respect to exiting '18 over your '19 guidance, should we be telegraphing higher production in '19? Or do you expect to revise guidance for '19 when Q3 comes out?

[Michael L. Rose, Chairman, President & CEO]

I don't know if we do it that soon. I think we'll leave '19 alone for now, but it does provide some upside, but let us get there first would be my answer to that.

[Brian Kristjansen, Research Analyst]

Okay. And then if within the 6 months you decide to double Gundy Phase 2, what would be sort of the earliest time frame you'd expect that to be commissioned?

[Michael L. Rose, Chairman, President & CEO]

Q4 '20/first half 2021. If you look at our 5-year development plan and the capital -- the EP capital spending, you can see that it drops in '20 and '21. So we could accommodate quite easily and still generate a lot of free cash flow if that's where that investment was plugged into the plan. But it also depends on, and we've always been very clear about this, on what the natural gas price strip looks like for 2021, and that's part of that decision-making process.

[Operator]

Your next question comes from Peter Cooke with Logan Capital.

[Peter F. Cooke, MD & Member of Advisory Board]

Mike, what you guys do is very, very impressive. The problem seems to be -- continues to be the whole industry up here is constrained by a lack of pipeline, takeaway pipeline capacity. I was curious if you could sort of talk a little bit about your view on the industry at this point of -- for the next couple of years anyway. It seems like the price of gas just continue to suffer. Any reason to think that we might get a better price for gas over the next year or so?

[Michael L. Rose, Chairman, President & CEO]

Well, there's a few reasons. And your first comment is correct. We struggle with egress issues. We've always been very diligent about ensuring that we have firm service on all the pipelines or egress points that exist currently to sort of handle our production currently and going forward over, I guess, what's in the 5-year plan. And hence, we've taken out firm service. We get gas to California, and we get gas to Chicago, and we get gas to Dawn. We're optimistic that, ultimately, LNG on the West Coast of Canada happens. Obviously, that doesn't provide any new exit points until probably 2023 if someone chose to FID in the second half of this year. There are a couple of pipeline expansion projects. I mean, the tolls are being reviewed and discussed between the pipeline companies and the producers. So using the Energy East pipes for LTFP to take more gas to Dawn is one of those that may happen. You'd have to talk to TransCanada about that. And there's also a potential alliance expansion that I think the tolls are under negotiation. I mean, what encourages us, Peter, is the underlying demand for natural gas, and this is really occurring on both sides of the border, is actually ahead of expectation, and it is expected to grow. And so we think, ultimately, that does drive higher natural gas prices. And it never seems like it's enough, but there has been a producer supply response to these lower prices, so the Canadian rig count gas directed is certainly lower. A number of us cut our gas development budgets for certainly '18 to provide less supply at AECO. And time will tell if that's going to provide improved prices in '19 and '20. It's -- the strip has improved somewhat. It hasn't gotten into the range that we really like over the past 3 or 4 months, but it has kicked off bottom. So we're always optimistic. That being said, of course, we've kept our total corporate gas production flat at our 2017 exit of around 1.3 Bs a day. And we don't really grow those volume again until the Gundy plant comes on in the second half of '19. That'll be our next increment of gas growth. And we, like a lot of other producers in western Canada, have been growing our liquids volumes substantially underneath that sort of gas ceiling, if you like. Does that help?

[Peter F. Cooke, MD & Member of Advisory Board]

Yes. I mean, the comments that obviously is the important thing and gas is the -- you get the gas with the condensate. So continues to trade a -- excess of production of gas.

[Michael L. Rose, Chairman, President & CEO]

Yes. But if you kind of go through the list of the Canadian producers anyway, the gas production really isn't growing. And that's what provides some basis for optimism, even with the addition of liquid-rich gas. The other key, of course, is remain the lowest gas producer. And then you can actually make a return, not as much as you want, but you can make a full cycle rate of return at pretty low gas prices.

[Operator]

Your next question comes from Jordan McNiven with Tudor, Pickering, Holt.

[Jordan McNiven]

My question is about Gundy, how it relates to the timing of the North Montney mainline. Just wondering to what degree growth is dependent on this pipe. And if it comes on early, do you plan to being in a position to capitalize on this? And conversely, if we see construction delays, how much of the growth would be impacted in the second half of '19?

[Brian G. Robinson, VP of Finance, CFO & Director]

Thanks for your question, Jordan. It's Brian responding to that question. As far as our plans we're working towards, as Mike mentioned, early in the second half of '19 to commission the gas plant. We have egress on both systems for the North Montney for our [indiscernible], as you know. And we're also actively positioning ourselves so we have service on the Port Nelson lateral to take the gas to station [ 2 ]. And of course, we'd like to have both options. Over time, I think the key here is that our 200 million a day facility will dedicate gas flows ultimately into the California market because we've been ramping up our GTN position. And you noticed here in the second quarter, we added 100 million cubic feet a day of service, and we were able to deliver that. So we'll bring that gas on into the market, but we map that to that western North American gas market, which is a stronger market. So in the event that the North Montney is delayed, we're still going to be able to ship gas, and we'll be able to access the valuable [ resource ] short term here and the [indiscernible] just the condensate.

[Michael L. Rose, Chairman, President & CEO]

It does impact doubling the size of Gundy, but that's a decision that we don't have to make yet. But the initial 200 million a day deep cut with its liquid is solid and on schedule, and it will produce when it comes onstream.

[Operator]

[Operator Instructions] Next question comes from Fai Lee with Odlum Brown.

[Fai Lee, Equity Analyst]

Mike, it's Fai here. You talked about -- a bit about some producers cutting back production in reaction to the April price. It almost seems like from the higher cost reduction doesn't seem to have reacted to the low prices yet. Do you get the sense that some producers are just waiting until winter, Q2 half until the pricing before they make dramatic moves? Or do you just kind of see it's kind of people are just kind of trying to [ lock ] in terms of the higher cost reduction?

[Michael L. Rose, Chairman, President & CEO]

Yes. Well, Fai, it is hard to speak for others. As far as Tourmaline was concerned, we made the decision last fall not to bring incremental new growth supply into the market for 18 months or so and just keep our plants full and wait for higher prices that way. Each company has a different suite of decisions to make. Some of it relates to firm transport commitments. Sometimes the gas isn't 100%, and you got to deal with partners. So it's almost individual company, individual property decision that gets made. So we're, I think, doing our best to reduce increasing supply by freezing the gas development volumes that are going to come onstream. And really, we can only control what we do. But generally, we are seeing I think -- as I mentioned earlier, it's never as much as you want, but I do think if there is a supply response that's going to help gas prices.

[Fai Lee, Equity Analyst]

Okay. And just a follow-up question. In terms of you raised the dividend and you've paid down a little debt. Can you just talk about your free cash flow allocation priorities? I know on your budget, it tends to emphasize a bit more debt reduction. But I'm just wondering where share buybacks fit in, if at all, going forward?

[Michael L. Rose, Chairman, President & CEO]

We've certainly looked at that. I guess, there's -- with free cash flow, there's kind of 4 silos it can go in. One is modest dividend reduction, one is debt reduction, one is reinvesting in growth again when the commodity price suggests that, that's a good idea and investors are happy with it. And then the fourth silo is share buyback. I think if you look at our 5-year plan and you look at the magnitude of the free cash flow, it starts to get into that $0.5 billion per annum range in the 2020 to 2022 time frame. And that's when we think we can look seriously at share buybacks because we'll have enough free cash flow and could dedicate enough to that silo where we'd make a difference on the outstanding shares. So it's part of that overall decision.

[Fai Lee, Equity Analyst]

Okay, all right. So you're not ruling out share buyback in the future? Okay.

[Michael L. Rose, Chairman, President & CEO]

Sorry, what's that?

[Fai Lee, Equity Analyst]

You're not ruling out share buybacks in the future?

[Michael L. Rose, Chairman, President & CEO]

Oh, no, we're not ruling it out at all. It's just when we need the magnitude of free cash flow where we can make a difference.

[Operator]

[Operator Instructions] Next question comes from Jim Smith, private investor.

[Jim Smith]

Mike, I wanted to congratulate you guys on a fantastic job. I look at a lot of companies, and I think you guys really are focused on the right things. And someday, I think you'll be recognized for that, hopefully soon. I've got a question about your 5-year plan. To me, it looks like a great plan. And toward the end of it, you're getting down to almost a no-debt situation. And I just wanted to get a feel for your comfort level of how much leverage you would like to have at that point because I think your company at that time could support quite a bit of leverage. And if there was an opportunity you saw, would you feel comfortable going to a certain amount of debt level? Could you just comment on that a little bit?

[Brian G. Robinson, VP of Finance, CFO & Director]

It's Brian speaking. Thanks for your question, Jim. As far as where we're at right now, we're about 80% equity, sub-20% debt. We feel comfortable with that ratio. We like the idea of running our business in that band between 1 and 1.5x debt to cash flow. We've done a lot of work to improve our overall creditworthiness. We've got lots of liquidity on our balance sheet, so we have lots of options. We're not going to do exactly what our 5-year plan shows as far as debt reduction, obviously. We understand that it's -- there's a healthy level of debt that one would like to carry on a [indiscernible] balance sheet. But I think the permanent debt level is kind of in that $1.1 billion to $1.4 billion, $1.5 billion range that we would run it out. And of course, that positions us well if there's a gas price improvement that we can respond to and we can do a small acquisition or we can decide to invest more aggressively in our existing drilling inventory, we'll do so and we'll grow the business.

[Michael L. Rose, Chairman, President & CEO]

Does that make sense?

[Jim Smith]

Okay, I appreciate that. Yes.

[Michael L. Rose, Chairman, President & CEO]

You can see that in the right-hand column. That right-hand column in the 5-year plan really it's for mathematical completeness. We need to put the money somewhere, so we just essentially take the debt down to 0. But as Brian points out, that's not what ultimately is going to happen.

[Jim Smith]

Yes. I see that, Mike, and I know it's just a theory -- a theoretical plan. But I don't think people appreciate kind of the capacity that you're going to have in 4 years. I don't think you should go out of your way to point it out, but I think that's something that's underappreciated by investors right now, just how much balance sheet capacity you will have to create a lot of value for the shareholders. And once again, congratulations. I think you guys are the best-run E&P in North America and best of luck to you.

[Michael L. Rose, Chairman, President & CEO]

Well, thanks. Thanks for your comments, Jim.

[Operator]

Your next question comes from Peter Cooke with Logan Capital.

[Peter F. Cooke, MD & Member of Advisory Board]

Mike, just a comment. I'm not a great fan of buybacks, especially for E&P companies. And it seems to be the only time you'd ever want to buy back a stock is when there's a whole lot of pressure out there. I mean, the fact that you're dealing with a commodity leaves you pretty wide open on valuations in the company. I just -- never as I said. I just hate buybacks, especially for E&P companies, because there's such a variable here in the value the company can be based on the commodity price.

[Michael L. Rose, Chairman, President & CEO]

Yes, those are fair comment. And as where we are in our life cycle, we are pretty capital positive now, but it's something that we haven't moved on at this point.

[Operator]

[Operator Instructions] And we do not have any questions over the phone line at this time. I will turn the call over to the presenters.

[Michael L. Rose, Chairman, President & CEO]

Well, thanks, everybody, for dialing in. We look forward to talking to you when we release Q3 in November of 2018. Thank you.

[Operator]

This concludes today's conference call. You may now disconnect.