Tourmaline Oil Corp

TSX:TOU

Earnings Call Transcript 2019-Q3

[Operator]

Ladies and gentlemen, thank you for standing by, and welcome to the Tourmaline Oil Corp. Q3 2019 Results Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. [Operator Instructions]I would now like to hand the conference over to your speaker today, Scott Kirker. Thank you. Please go ahead, sir.

[William Scott Kirker, Secretary & General Counsel]

Thank you, operator. And welcome, everyone, to our discussion of Tourmaline's results for the quarter and 9 months ended September 30, 2019. My name is Scott Kirker, and I'm the Secretary and General Counsel for Tourmaline.Before we get started, I refer you to the advisories 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 also draw your attention to the material factors and assumptions in those advisories.I'm 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 for the quarter. And after his remarks, we will be open for questions. Go ahead, Mike.

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

Thanks, Scott. Good morning, everybody. Thank you for dialing in. And Tourmaline is pleased to review financial and operating results for the third quarter of 2019. We'll start off with some highlights. We are on a strong liquids growth ramp. Q3 '19 was up 23% from the same quarter in 2018 and 7% from the prior quarter, Q2 of 2019. Average September total liquids production of just over 60,000 barrels per day is on track with the full year average. Overall, Q3 production was just under 290,000, at 289,578 BOEs per day. And that included the impact of natural gas storage injections at Dawn and California during the third quarter and continued natural gas price-related activity deferrals. We were up 3% from the Q2 average production and 14% from the same quarter in 2018.We did generate free cash flow in Q3 of just over $14 million, even with extremely weak AECO natural gas prices, and we did that on capital spending of $201 million. Fourth quarter '19 free cash flow is expected to appreciate, and we're currently estimating that at $50 million or more based on strip pricing.We have been utilizing our NCIB. The company bought back a total of 863,000 common shares for just over $10 million at an average price of $12.10 per share.During the quarter, we acquired an incremental working interest in the Peace River High complex for $175 million. That included 5,600 BOEs per day of production and $40 million to $45 million of incremental annual cash flow. We continue to reduce operating cost. They averaged $3.11 in Q3, and that's down a full 10% from the previous quarter. And of note, we continue to manage capital spending down. Our 2019 estimated EP capital spending has been reduced by a further $90 million adding on to the $180 million that we reduced it by up until this point.Looking at production in a little bit more detail. Third quarter '19 production, as mentioned, averaged just under 290,000 BOEs a day. As with the previous quarter, Q2 of '19, we deferred a lot of dry natural gas completion activities due to particularly low natural gas prices. And that reduced Q3 production by approximately 3,500 BOEs per day. Majority of these wells are being stimulated during the fourth quarter and will be brought on production into this much improved AECO gas price environment. And given that appreciation in the AECO price so far, this looks like a good strategic move. The company expects to average 295,000 to 300,000 BOEs per day for full year '19, so essentially within the original guidance range. We will bring approximately 75 wells on production during the fourth quarter and that includes the DUC inventory created by the natural gas price-related program deferrals during the summer, Q2 and Q3.Our Dawn and California storage positions that were built in Q2 and Q3 of this year will be sold during the winter. If these volumes are all sold during the fourth quarter, they'd add approximately 3,500 BOEs a day to our fourth quarter production. And we expect to exit '19 at production levels of between 315,000 and 320,000 BOEs per day.September liquids production was 60,138 barrels per day. That was a record for us and on track with the full year average. We expect exit '19 total liquids production of 68,000 barrels per day, and the Q4 '19 liquids production growth being driven by a number of factors, including the ability to produce our new Gundy deep-cut plant at full volume that started in September; incremental natural gas condensate volumes from 3 additional pads in the Gundy complex that will access third-party processing options; the start-up of 12 new oil wells on the Peace River High complex, and some of that activity was also moved out of Q3 into Q4 that includes the new high-rate 11-2 pads that we detail a little later; the impact of the aforementioned Peace River High acquisition for the full quarter, the fourth quarter; and strong liquids production from new horizons in the Alberta Deep Basin complex.Looking at our financial results. Third quarter earnings were $15.8 million, bringing year-to-date earnings to $258 million or $0.95 per diluted share, and that does underscore the inherent profitability of the ongoing EP business even in extremely low natural gas and NGL pricing environment.Third quarter '19 cash flow was $224 million or $0.82 per diluted share with the corresponding AECO natural gas price of $0.92 an Mcf. 9-month cash flow for 2019 was just under $870 million compared to 9-month EP capital spending of $766 million.Q4 '19 and winter AECO natural gas prices have improved dramatically since third quarter and that's expected to drive a material increase in our fourth quarter cash flow. We will have between 375 and 400 million per day exposed to these improving winter AECO prices and full year 2020 AECO prices to be completely accurate. Our long-term natural gas volumes on the GTN system, which goes out the west gate and connects to the PG&E system, have increased from 200 million per day to 300 million per day this month. That's part of the TC NGTL build out program. San Francisco city gate prices have remained one of the premium priced U.S. hubs during '19. For reference, the October average of that hub was USD 3.15 per MMBtu. The change in the NGTL system protocol during summer maintenance periods that Tourmaline helped develop and implement is expected to yield stronger and less volatile summer 2020 AECO gas prices as well.A big highlight for us was our third quarter '19 OpEx was $3.11 per BOE, well below our full year guidance of $3.45 per BOE. And September '19 operating costs were actually $3 a BOE for the whole company. Remember that includes an oil complex as well. These sustained lower costs will enhance overall 2020 realized cash flow.Our quarterly dividend of $0.12 per common share per quarter will be paid on schedule.Moving to the 2019 capital program. Third quarter CapEx -- EP CapEx was $201 million, and that's down a full 50% from Q3 of 2018, but we still delivered growth. The company continues to ensure that EP capital spending is less than cash flow. Continuously improving capital efficiencies primarily through reductions in drilling and completion capital cost has allowed us to systematically reduce our original '19 EP capital spending by $180 million year-to-date. And in addition, we're going to reduce Q4 capital spending by approximately $19 million, bringing total '19 CapEx on the EP front down to $1.035 billion. Full year capital efficiencies of approximately $8,000 per flowing BOE per day will be delivered by the EP program in 2019, and that's a record low for the company.We estimate, as mentioned, Q4 '19 free cash flow of approximately $50 million or better, and that's based on stripped pricing. And that's due to the aforementioned stronger nat gas prices and continued capital discipline with the Q4 EP program.Turning to 2020. We approved, with the Board, a 2020 EP capital program of between $900 million and $925 million, which will yield 2020 average production of between 315,000 and 322,500 BOEs per day. So unchanged from prior 2020 production guidance.The 2020 EP capital program is approximately $100 million to $125 million less than our previous guidance, and that's a function of the continually improving capital efficiencies. We expect a step change increase in 2020 free cash flow generation based on current natural gas strip pricing. And we will provide a full 5-year plan update and finalize 2020 guidance and our 5-year commodity price assumptions in early December.Moving to the Peace River High. We're pleased to report we reacquired the 25% working interest in that complex for $175 million. The acquisition adds approximately 5,600 BOEs per day of oil and natural gas production that's currently operated by us, and net 2P reserves of approximately 62 million BOEs. This acquired asset was originally sold by us in Q4 of 2014, and it was producing about 3,000 BOEs a day with 2P reserves of 24 million BOEs at that time. We estimate that the acquired asset will add $40 million to $45 million of incremental cash flow in 2020, providing a net free cash flow yield of 14% for that acquisition. And it's being financed by the aforementioned discussed reduced '19 and '20 EP capital spending targets.Brief update on Topaz. Our previously announced purchase by Topaz Energy Corp. of certain assets of Tourmaline and the financing of Topaz remain on schedule to close November 14, 2019. At closing, Tourmaline will receive from Topaz approximately $200 million in cash and Topaz common shares representing 75% of the total equity interest of the company.Moving now to some EP highlights. Starting off with Gundy in North East, BC. The C-60-A deep-cut plant was ramped to full volume of 200 million per day and total liquids of 12,500 barrels per day in September, and that was without access to the North Montney TransCanada pipeline, which has been delayed. So we got the full volume without that. An incremental 3,000 barrels per day of liquids are expected from the Gundy complex during the fourth quarter. Very strong new well performance continues. Sustained liquid rates of 90 to 100 barrels per million are being realized from the wells, particularly in the southern half of the property. We have repeatable sustained drill, complete, equip capital cost of less than CAD 3 million now. And our current Gundy complex OpEx is $2.25 per BOE. So the economics of this overall Montney project are absolutely best-in-class.The Gundy Phase II expansion at C-60-A from 200 to 400 million per day is currently planned for late 2021 or early 2022. We have secured an additional 150 million per day of firm, long-term transport on the GTN and PG&E system that accesses the lucrative Pacific Northwest and California markets. So total Tourmaline natural gas volumes accessing these markets will reach 450 million per day in the 2022, 2023 time frame. So that basically handles all 400 million per day plus that will ultimately come out of the Gundy complex.Moving to the Alberta Deep Basin. Our successful exploitation of new liquid-rich horizons continues. The Anderson 7-11 Cardium well was producing just over 24 million per day of gas and 724 barrels per day of condensate at the end of the 5-day test in October. The initial -- and we put a new slide in the COV, or an updated slide. That initial Anderson Cardium development block, which is a small subset of the identified natural gas condensate play trend, is currently producing 86 million per day and just over 2,000 barrels per day of condensate and NGLs from a total of 17 Cardium wells, both horizontal and vertical. So it's kind of a decent little company in its own right.The Wroe 15-8 Falher D pad with 3 wells came on production in October and after 2 weeks is producing at a combined rate from all 3 wells of 27 million a day of gas, 536 barrels per day of condensate and just over 2,100 barrels per day of NGL. So just an excellent pad. We'll have 8 more Falher D wells coming on stream over the next 6 months. So it's a sizable new opportunity, liquid-rich in the Deep Basin.And finally a very high rate pad on the Peace River High. The new 11-2 four-well Upper Charlie Lake pad came on production in October, and it's currently producing just over 2,800 barrels per day of oil and 2.3 million a day of gas from the 4 wells combined. So it does provide growth and further upside to our overall liquids growth strategy.So that's the end of the formal comments for the conference call, and all 3 of us are more than willing to answer any questions you might have.

[Operator]

[Operator Instructions] Your first question comes from the line of Jordan McNiven from Tudor, Pickering, Holt.

[Jordan McNiven]

Just wondering if you could speak to the supply/demand fundamentals in Northern California. And obviously, you guys like this market and have made significant commitments there. We do hear from some investors who have a bit of concern with the news that comes out on Berkeley and San Jose, where they're banning gas hook-ups into new homes. Now obviously, it's a small part of the market, but just appreciate your views on that market more broadly.

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

I'll jump in on that. Thanks for the question, Jordan. We really find it an attractive market regionally because it is a demand since there's not a lot of local supply there. Our main competitor is the Rockies in the United States that we compete with. That tends to be a drier hydrocarbon sequence. And along with that, the economics aren't quite as strong. In addition, our role is often largely to backstop the growth in renewables so that the demand load during peak loading of natural gas in that region is actually substantial. In fact, it's higher than the intra-Alberta demand. So we love the market. We're going to continue to grow as a percentage of that total market. So we are a dominant supplier there. And we've also got a sophisticated marketing arrangement, where we're able to access multiple buyers of our gas. And we do have a strong storage position there as well. So there's a lot of regional -- regions we like. And you're absolutely right, some of these stories you hear about some of the municipalities and the subdivisions prohibiting natural gas are true. But I think they're -- as you pointed out, they're relatively small. I mean it's an enormous part of the U.S. population wise. And we're also able to -- over longer term periods get gas into the Washington area, too, we believe. So there's all kinds of good advantages for us.

[Jordan McNiven]

Okay. That's perfect. And then just another related-type question. Are you able to provide an update on the latest commentary around timing of North Montney?

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

What we heard publicly was early January of 2020.

[Operator]

Your next question comes from the line of Patrick O'Rourke from AltaCorp Capital.

[Patrick Joseph O'Rourke]

Good quarter. Just a couple of questions on Gundy here and just wondering if maybe you could provide some perspective in terms of the liquids cuts. I know you've pointed to the South being more liquids-rich than the north. But we do have the a -- one of the recent pads here, the B48 at the North, looks fairly good in terms of the condensate yield. Amongst the lobes, the condensate yields seem to vary less than, say -- you would think that they're varying aerially? And I'm just wondering kind of what's the nuance that's going on there between a B48 and A78.

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

We are learning as we drill more wells, and we're actually accessing 5 different lobes. So there actually is some vertical and aerial variability to it. They're nice consistent liquid cuts as we produce the wells, and your comment that generally it's been more liquid-rich to the South is absolutely true. But bear in mind, it's an enormous piece of real estate. And we don't know everything yet, be the first to admit that. But so far, it's kind of all been really good, and the best part of the story, of course, is the cost side when you look at it. So being able to do these wells now equipped for under $3 million -- I mean when we took the property over, it was just a smattering of wells. I mean, just the drill complete costs were around $5 million each, so that's kind of where we're at now.

[Patrick Joseph O'Rourke]

Yes. And in terms of the ramp-up here, your facility is full. Just wondering what sort of volume through third-party infrastructure you have access to.

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

We have access to a lot of volume if we want to use it, and we've negotiated, we think, pretty good pricing on that, and so that's through third-party options. And -- the volume that we ultimately add is really a function of price. Obviously, the economics in our own plant are better. And so we'll continue to utilize both.

[Operator]

[Operator Instructions] We have no fuarther questions at this time. I'll turn the call back to Scott Kirker for closing remarks.

[William Scott Kirker, Secretary & General Counsel]

Thanks, everyone, for calling in, and we'll talk with you at year-end. Signing off.

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

Thanks, everybody.

[Operator]

Ladies and gentlemen, thank you for your participation. This concludes today's conference call, and you may now disconnect.