Tourmaline Oil Corp

TSX:TOU

Earnings Call Transcript 2018-Q4

[Operator]

Good morning. My name is Amy, and I will be your conference operator today. At this time, I would like to welcome everyone to the Tourmaline Oil Corp. Fourth Quarter and Year-End Conference Call Results. [Operator Instructions] I would now like to turn the conference over to Mr. Scott Kirker. Please go ahead.

[William Scott Kirker, Secretary & General Counsel]

Thank you, Amy, and welcome, everyone, to our discussion of Tourmaline's results for the year ended December 31, 2018. My name is Scott Kirker, and I'm the Secretary and General Counsel for Tourmaline.Before we get started, I refer you to the advisory on forward-looking statements contained in the news release as well as the advisories contained in the Tourmaline annual information form and MD&A available on SEDAR and on our website. I'd like to draw your attention to the material factors and assumptions in these advisories.I am here with Mike Rose, Tourmaline's President and Chief Executive Officer; and Brian Robinson, Vice President Finance and Chief Financial Officer. Mike will start by speaking to some of the highlights of the quarter and the year. And after his remarks, we will be opening for questions. Mike, go ahead please.

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

Thanks, Scott, and good morning, everybody. And we are pleased to review our 2018 financial and operating results.Firstly, just a few of the highlights. Tourmaline delivered full year 2018 earnings of $401 million or $1.48 per diluted share, which underscores the inherent profitability of our core EP businesses. Annual cash flow for 2018 was $1.3 billion or $4.80 per share, and that was 8% higher than 2017 cash flow of $1.2 billion despite lower natural gas prices in '18 versus '17.We had record Q4 '18 cash flow of $391.5 million, that was 36% higher than cash flow from the prior quarter. We realized 9% average production growth in 2018, and that's 23% on the liquids side.We added 338 million BOEs of 2P or proved plus probable reserves prior to production. 2P liquids reserves increased 17% to just over 500 million BOEs or 0.5 million barrels prior to '18 liquids production, that's 21% growth prior to '18 liquids production.2P FD&A cost, including future capital, were $5.15 per BOE, $3.59 if you exclude changes in FDC. Total proved FD&A in '18 was $6.79 per BOE and PDP FD&A was $9.11 per BOE.So after 10 years of operation, Tourmaline has 2P natural gas reserves of 11.7 TCF and 2P liquids reserves of 505 million BOEs oil condensate liquids. We have the largest publicly-reported, independently-assessed 2P natural gas reserves in Canada.Our 2P reserve NPV right now is $58.57 per diluted share. The 2P NPV is $33.67 per diluted share and our PDP NPV is $17.36 per share. In 2018, our 2P recycle ratio was 2.6 on our 2P FD&A of $5.15 per BOE and a cash flow netback of $13.47 per BOE. Total proved recycle was 2, and the 2018 PDP recycle ratio was 1.5.A few more comments on the 2018 financial results in addition to the highlights that I've underscored already. The record cash flows for the company in '18 were realized during the year generally weak natural gas prices. Our gas diversification and hedging strategies provided a realized natural gas price of $2.73 per Mcf, and that's an 81% premium over the full year AECO index price of $1.51 per Mcf.The Q4 2018 operating netback of $15.82 per BOE was 7% higher than the corresponding quarter in 2017. We had full year cash flow of $1.3 billion on full year capital spending of $1.21 billion, generating $89 million in cash flow per calendar '18. And our low cash cost and industry-leading capital execution cost allow us to achieve cash flow per share growth, the generation of free cash flow and the ability to pay a dividend.And as part of our lower-growth sustainability model that we migrated to late in 2017, in 2018 we began paying dividends for the first time and we had a total payout during the year of $100.6 million.Capital spending for '18 included a $110 million in expenditures related to the Gundy deep-cut gas plant, which is currently being built in North East, BC. $35 million was spent in Q4 '18 to accelerate the project, which is now set to be commissioned in June of this year, moved up from the originally planned October 2019 start-up.And that will provide really a double benefit for 2019, and the Gundy plant-related expenditures will be less on the capital side for '19, and very strong 2018 capital efficiencies will be that much stronger in 2019.Exit '18 debt was $1.72 billion, that was down just under $20 million from Q4 of '17 after our dividend payout. Looking at some of the production comments in a little bit more detail. As mentioned, our full year '18 average production of just over 265,000 BOEs a day was 9% higher than our '17 average and was within the guidance range. Q4 '18 liquids production of just under 52,000 barrels per day was 14% higher over the corresponding period in 2017.And for 2019, we're forecasting total liquids production of 66,000 barrels per day, and that represents 39% year-over-year growth, '19 versus '18, which we expect will be one of the highest liquids growth rates posted by the industry this year.Tourmaline has been producing at the first half 2019 guidance range consistently between 290,000 and 300,000 BOEs per day, and we reiterate our full year 2019 production guidance of 300,000 BOEs per day. And that will represent, ultimately, 13% growth this year over '18.And do recall that the Gundy plant, which adds 50,000 BOE per day of new production, will come onstream in June, so we're in a strong production position for the full year 2019 production. On the cost management side, full year 2018 OpEx was $3.33 BOE, that's up 4% over '17, production base grew 9% and our liquids production grew 23%. The low operating cost continue to reflect multiple cost-reduction initiatives, which we've implemented during the year and continue within 2019.Also, note that the majority of the Gundy volumes will begin flowing to our lower-cost facilities in June, so that will help reduce of cost further for 2019.Top quartile '18 cash costs were $7.87 per BOE up from $7.12 in 2017. And that's been described and will be able to take that down somewhat with the start-up of our Gundy deep-cut. Those cash costs also reflect an increase in transportation cost, and that's a result of the company's continued natural gas market diversification strategy and the associated commitments for long-term firm transportation and all the egress options out of the basin right now.Looking at the capital budget. We've updated our 5-year plan in the corporate overview, which is available on the website. We've reduced our 2019 AECO gas price to $1.80 per Mcf and we've also reduced our natural gas liquids pricing. Our forecast '19 cash flow is $1.5 billion, which will generate free cash flow above capital expenditures of $242.6 million prior to dividend payment.In the 5-year plan, the forecast free cash flow over the 5-year period is estimated at $2.2 billion. And for 2019, we're anticipating cash flow per share growth of 15% over 2018.The current full year 2019 capital budget is $1.225 billion, and that reflects the $75 million capital reduction that we announced on January 15 of this year. We expect to spend less than $600 million during the first half of 2019, but also identified a number of further capital cost reductions that may be implemented later in the year contingent upon commodity pricing really in Q2 through Q4 of this year.We expect our 2019 excess debt-to-cash flow ratio to be approximately 1.1x. Moving to some comments on marketing. We currently have 678 million cubic feet per day that's sold at 6 different hubs with gas pricing indexed to the prevailing NYMEX gas price, and those volumes grow to 778 million cubic feet per day in November of this year.Thus far in 2019, we have realized price net of transportation on the Western gas exposure, so that includes Sumas-Huntingdon, Malin and San Francisco City Gate of CAD 6.24 per Mcf Canadian.On the liquids side, we secured multiple long-term liquid processing and handling agreements in BC and Alberta to allow us to achieve premium pricing for our company's future liquid streams, including the large volumes at Gundy and BC. We've entered into a liquids handling agreement with AltaGas for the Gundy propane. The agreement secures Argus Far East Index pricing on an estimated 45% of the propane volume.In 2019, we expect this volume to realize wellhead prices that are in excess of CAD 5 per barrel above Edmonton power prices. And finally, with the healthy free cash flow that we're currently generating, our Board of Directors declared the quarterly cash dividend on its common shares of $0.10 per common share, the same as it was last quarter. And that dividend will be payable March 29, 2019, to shareholders of record at the close of business on March 15, 2019.So that's all I was going to say as far as formal comments. And we're all welcoming questions at this point. Thank you.

[Operator]

[Operator Instructions] Your first question today comes from the line of Aaron Swanson of Tudor, Pickering, Holt.

[Aaron Swanson, Director of E&P Research Canada]

I'm just curious on the thought process around still using third-party processing at Gundy when this facility comes on, I mean, possibly could bridge the gap between sanctioning Phase 1 and Phase 2?

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

We're currently producing, Aaron, between 15,000 and 17,000 BOEs a day at Gundy, and it does go through those our third parties. In our 5-year plan or in our 2019 guidance, those volumes are redirected through our facility so that we realized a net 35,000 BOE per day increase, that's how our guidance is put together for this year. We do have the option to continue producing all or some of those volumes through third parties. And that's a decision we'll make in June, July, August, in part contingent on what the commodity prices look like at the time. But it does give us another production buffer that we can utilize. And yes, you're right, it would bridge the gap between Gundy Phase 1 and Gundy Phase 2, which we have not made our internal FID on yet, but anticipate doing so sometime in the next year or so. Is that good?

[Aaron Swanson, Director of E&P Research Canada]

Yes, perfect. Yes. Just a quick follow-on. You guys mentioned you've changed your NGL price assumptions for 2019, do you mind walking us through what they've changed here?

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

Right and lower. Kind of at course level, in 2018, our average NGL stream achieved about 38% of the WTI price. We've cut that to 27%. And of course, it's all we specifically analyzed each of the pentane, butane, propane, ethane streams and coming up with that. But that's what the percentages of our WTI number that we expect to realize.

[Operator]

[Operator Instructions] Your next question comes from the line of Fai Lee of Odlum Brown.

[Fai Lee, Equity Analyst]

Mike, it's Fai here. I'm just wondering in terms of your kind of when you think about the bigger picture, your 5-year plan and as your free cash flow continues to increase. According to your 5-year plan, do you still see dividends as being the primary method of returning cash to shareholders? Just wondering the context of given where your share price is at these days?

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

Sure. Yes, I'd say that the uses of the free cash flow are the opportunity to modestly increase dividends, pay down debt, possibly sanction new E&P projects if commodity prices improve. Those are the 3 primary uses. If you're referring to a share buyback, it's something that we look at and are still evaluating. And if we did proceed with that, I think if you look in 2020 through 2023 in the 5-year plan, we have significantly more free cash flow on an annual basis. So perhaps it makes more sense then.

[Fai Lee, Equity Analyst]

Yes. I was more wondering about -- when your cash flow in 2020 to 2023, it kind of seems to get there?

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

Yes, it's something we'll certainly have a look at.

[Fai Lee, Equity Analyst]

Okay. And just another question, we've seen in Alberta the production cut -- the mandated production cuts on the oil side. And certainly, from a relative perspective, I don't think the picture is that much better on the gas side for the Alberta government. What's -- where do you think that's heading? Do you think there's anything that can transpire on the gas side similar to what we saw on the oil side or what's your thoughts around all that?

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

We think it's very unlikely that curtailments happened on the natural gas side is just oil was complicated enough. Yes, gas is infinitely more complicated and difficult to instill curtailments on. And hey, AECO is $3.

[Fai Lee, Equity Analyst]

Yes. Well, it'd be great if we -- if it were still $3 in July, I think I'd be thrilled.

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

Yes, that's why.

[Operator]

And your next question comes from the line of Josef Schachter of Schachter Energy Research.

[Josef I. Schachter, Author & President]

I have 2 of them. Were you impacted in Q4 by the BC pipeline disruptions? Did you lose any volumes in that quarter?

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

Yes, we did. And I think we detailed that in the press release that we put out in November. At some point, we did. Yes, we did lose volumes. And we worked that into our kind of revised full year '18 guidance.

[Josef I. Schachter, Author & President]

Do you have an idea if that's undesirable, I can always look but if you have it on the tip of your hand?

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

Some like -- we'd have to look, again. It's something like 25 million cubic feet of gas for the quarter.

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

Yes. In Q4 of the ...

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

It's actually on our November 7 press release, I think, Josef. But we can ...

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

We can take that up, yes.

[Josef I. Schachter, Author & President]

Yes, I can take that out as well. And then the second question I have is, with the problems that Enbridge is having with Line 3 and a 1-year delay, does that impact any of your takeaway capacity in 2019 through 2020? And even though you do have contracted takeaway capacity, given the Enbridge problem, does that, in fact, impact any of your numbers and guidance?

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

No. It doesn't, Josef. We've got firm service arrangements for our piece, our oil that take it out either through the Kinder Morgan line or back on the Enbridge line itself. So I think we're in good shape there.

[Operator]

[Operator Instructions] Your next question comes from the line of Peter Cooke of Logan Capital.

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

Mike, question for you. How much of your production now has been shut in because of the AECO price being as low as this? And impact of the lack of pipeline capacity out there, how big of an impact is that on curtailments?

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

We have some volumes shut-in as we work through our winter programs because not everything is tied in yet. It -- Peter, it's more a function of slowing down activity because of lack of basin egress, and really we initiated that process back in late 2017 where we drastically slowed down the growth of our gas business and chose to grow the liquids business sort of underneath a ceiling of 1.35 Bs a day. We're doing between 1.4 and 1.45 right now. So modest growth from where we were exiting '17, which was kind of always planned coming into 2019. And then when more firm egress options open up, we can obviously accelerate the gas business at that time.

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

Yes. I know in the States it just seems like we're on a more and more of a treadmill at this point. And I assume that's pretty much the same situation up in Canada. And I'm just wondering what the decline curve is that you're experiencing at this point and going forward, is that going to change that much or what?

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

Well, by slowing down, our decline curve kind of shallows, if you like. We're actually excited about the overall North American supply situation that we think a couple of the larger U.S. basins on the gas side may have started to roll over as operators move from Tier 1 to Tier 2 locations or start to experience a lot of parent-child relationships. So we're encouraged by that.

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

Mike, I guess, my feeling down here is so much of the shale is really almost like a Ponzi scheme at this point from lease kind of because they're spending more money on capital and they aren't any cash flow coming back from the projects?

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

Yes. No, I think that's right. I mean, I think you can see from our numbers that we actually do generate earnings and profitable on a full cycle basis...

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

Yes, and you guys are pretty unique.

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

Yes. But we are encouraged because the underlying natural gas demand build in both countries is really phenomenal. And it's on a steady ramp. And a lot of people believe supply is infinite, and you and I know it isn't.

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

No. But natural gas liquids seems to be the area of the export certainly in the States, but that seems to be a big problem for you guys getting any of these pipelines built to export the excess natural gas liquids or the liquefying the natural gas?

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

Yes. Well, the coastal link project is FID-ed. And I believe, they've started some of the construction. I mean, that's 5 to 6 years out, but we're very excited by that. And that will be the next large significant egress line out of the basin. There is a built out on the TCPL system, which adds, I think, 3 Bcf of really egress out the East Gate and West Gate, and some intra-Alberta consumption on the conversion from coal fire to electrical fire generation that is kind of exciting in the short term, sort of bridging the gap until the LNG kicks in.

[Operator]

And there are no further questions in queue at this time. I turn the call back to the presenters for any closing remarks.

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

Thanks, Amy, and thanks everyone for attending our conference call. We'll see you next quarter.

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

Thanks, everyone.

[Operator]

And this concludes today's conference call. You may now disconnect.