Tourmaline Oil Corp

TSX:TOU

Earnings Call Transcript 2020-Q4

[Operator]

Ladies and gentlemen, thank you for standing by, and welcome to the Tourmaline Q4 2020 Results Conference Call. [Operator Instructions] I'd now like to turn the call over to your speaker today, Scott Kirker. Please go ahead, sir.

[William Scott Kirker, Secretary & General Counsel]

Thanks, James, and welcome, everyone, to our discussion of Tourmaline's results for the years ended December 31, 2020, and December 31, 2019. My name is Scott Kirker, and I'm the 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 the Tourmaline AIF and our MDA -- MD&A rather available on SEDAR and on our website. I 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; Brian Robinson, Vice President of Finance and Chief Financial Officer; and Jamie Heard, Tourmaline's Senior Capital Markets Analyst. We will start by speaking to some of the highlights for the last quarter and our year so far. And after Mr. Rose's remarks, we will be open for questions. Go ahead, Mike.

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

Thanks, Scott. Thanks, everybody, for dialing in, and we are pleased to review Q4 and full year 2020 results. So starting with the highlights. We achieved record production in Q4 of 2020 and exited 2020 in excess of 400,000 BOEs per day. We had a record 2P reserve addition of 826 million BOEs, 2P in 2020 prior to production and an FD&A cost all-in of $3.80 per BOE. Fourth quarter 2020 cash flow was $397 million or $1.44 per diluted share, and full year cash flow was $1.185 billion or $4.36 per diluted share, and fourth quarter 2020 free cash flow was just under $145 million. In 2021, at current strip pricing, we now expect to generate cash flow of $2.2 billion and free cash flow of $1.1 billion on EP capital spending of $1.075 billion. We increased the dividend in 2020 despite a difficult year for all of us. The fourth quarter increase -- or sorry, the -- that was the fourth increase since inception of the dividend in 2018. And given stronger-than-anticipated cash flow this year and in future years, the company is increasing its dividend from $0.14 per share per quarter to $0.16 per share per quarter, and that'll commence this quarter. Tourmaline completed 4 accretive corporate acquisitions in 2020, and they're estimated to increase the 5-year planned free cash flow generation by over 20% or approximately $200 million per annum starting in 2022. And importantly, we delivered full year 2020 earnings of $618 million. Moving to production specifically. Current production is averaging between 405,000 and 410,000 BOEs per day or at the higher end of our full year guidance, which remains at 390,000 to 410,000 BOEs a day. And despite higher commodity prices and strong production, the company is maintaining previously disclosed guidance, and we're not growing beyond that in 2021. We expect first quarter '21 average production between 400,000 and 405,000 BOEs per day. Q4 2020 average production was 336,000 BOEs, and full year 2020 average production was just over 310,000 BOEs per day, both within guidance. Liquids production in '21 is trending ahead of original guidance. We're now expecting 89,000 barrels per day of oil condensate and NGLs average for the year. Moving on to financial highlights. As mentioned, our full year 2020 after-tax earnings were $618 million or $2.27 per diluted share, as we remain profitable despite a challenging year for everyone. Despite a global pandemic and an oil price crash in 2020, we increased the dividend from $0.12 per share to $0.14 per share per quarter, and that was all fully funded from free cash flow generated in 2020. We achieved a public investment-grade credit rating, and that allowed us to fix $250 million of debt at 2.077% for 7 years. And also during 2020, we successfully completed the initial public offering of Topaz, with the fair market value of Tourmaline's 51.7% equity ownership of the company valued at December 31, 2020, at approximately $800 million. Looking at our 2020 and '21 budgets. We got an early start on the winter '21 EP program by accelerating some activities into December. We ran our drilling rigs through in B.C. and on the recently acquired Jupiter lands rather than take the 2- to 3-week Christmas shutdown, which we often do. We also avoided the January frac crush by doing 2 of the large pads we were planning to frac in that time period, and we did them in December instead. That gives us incremental volumes for all of Q1, and it also allowed us to pull $25 million EP capital spend out of the overall '21 budget. So it's now down from $1.1 billion to $1.075 billion. We generated cash flow of $397 million and free cash flow of $145 million in Q4 2020 on EP capital spending of $244 million. We will generate free cash flow of $1.1 billion at strip pricing in 2021, and that free cash flow is designated for dividend increases, debt reduction, selective accretive acquisitions, further investment in emission reduction technologies and potential share buybacks. Looking at the full year '21 $1.075 billion budget, it consists of maintenance capital of $900 million, and then $175 million directed towards realizing the unchanged 3% to 5% annual growth outlined in the 5-year development plan. The Gundy, B.C. phase 2 deep cut expansion remains the only significant facility project in the 5-year plan, and $100 million of the $175 million of available incremental capital in '21 is directed to that phase 2 deep cut facility construction. That project is on schedule and expected to commence production in Q2 of '22 at 200 million a day of nat gas and 15,000 barrels per day of total liquids. It's also strategically tied to an increase in our gas transportation on the GTN system that ultimately takes our gas to California, 2 tranches of that, one in '22 and one in '23. Strong production so far in the first quarter, along with strong natural gas prices, coupled with the company's long-evolving market diversification strategy, will result in materially stronger Q1 '21 cash flows than originally anticipated. A little bit on our 2020 reserves. There's lots in the press release on that. But our 2P total is now 3.31 billion BOEs, and we got there, for us, with historically low FD&A costs in 2020. Year-end 2020 proved developed producing reserves are now 736.4 million BEs -- that's BOEs, sorry. That's up 61% over year-end 2019, including 2020 annual production of 113 million BOEs. Total proved reserves are now 1.7 billion BOEs. That was up 39.4%, and 2P reserves of the 3.31 billion BOEs were up 31.7%. Our 2020 PDP FD&A costs were $5.46 per BOE. That's a record low, and it yields a PDP reserve recycle ratio of 1.91. Total proved FD&A costs were $4.86 per BOE and 2P FD&A was $3.80 per BOE, including changes in FDC, and that yielded a 2P FD&A recycle ratio of 2.7. We replaced 727% of our 2020 annual production during the course of the year. Our 2P reserve value using the Jan 1, '21 engineering price deck equates to just under $58 per share at a 10% discount rate. Our total proved reserve value is $35 per share, and PDP reserve value, again, with that engineering price deck, is just over $20 per share. So after 12 years of operation, Tourmaline has 15.5 TCF of 2P natural gas reserves, and we view that as one of the largest lowest development cost, lowest emission natural gas reserve basis in North America. And we also have 738 million BOEs of 2P oil condensate and NGL reserves. Importantly, we've only booked 13% of our location inventory of just over 20,000 locations to get to the 3.31 billion BOEs. And for the eighth consecutive year, we enjoyed positive 2P technical revisions in the report. A couple of comments on marketing. Natural gas fundamentals for '21 and '22 have steadily improved, certainly where they were a year ago. Approximately 61% of Tourmaline's natural gas volumes are exposed to spot prices in markets on the western half of the continent. So those include the hubs at PG&E, Malin, Sumas, Station 2 and AECO. And that's where '21 nat gas fundamentals, we believe, continue to be the most supportive. We have sales diversification to the U.S. and other hubs totaling 584 million per day for exit 2021, 705 million per day for exit '22, and it grows to 755 million per day for exit 2023. And our diversified transportation portfolio with associated direct sale opportunities allowed for considerable, realized price and cash flow benefits during the February cold snap we all experienced. A few comments on E&P. We operated 12 drilling rigs and 3 to 4 frac spreads across the 3 operated core EP complexes in January and February. Activity is now starting to taper into spring breakup. So we've been very busy. During 2020, we drilled longer horizontals in all 3 complexes. Average horizontal well laterals were 16% longer, but our average drilling cost for those longer horizontals in '20 were down an average of 6%. Total completion costs for these longer horizontal wells were down 14% over 2019 levels on a completed lateral meter basis. One of the large pads we decided to frac early or in December rather than January was at Spirit River on the 6-10 pads that worked out well for us. That 7 well Montney and Lower Charlie Lake pad has significantly exceeded performance curve expectations, and the current producing rate is just under 3,400 barrels per day of light oil and 31 million a day of natural gas, and that's after 68 days of production. 5 of the 7 wells on that pad ranked as the top 5 oil wells in Alberta for January 2021 based on calendar day production rates. We also completed the phase 1 expansion of our Sundown, B.C. Montney project during the second half of 2020 and then brought production on in Q4 and into Q1. Over the past 5 years, we have been quietly expanding the land position at Sundown, steadily dropping our drill complete capital cost and dropping operating expenses to well below $2 per BOE. We expanded the existing processing facility and drilled one 5-well pad in Q4 and brought on, over the last 3 months, approximately 60 million [ 40 million ] (sic) per day of new production, with a capital efficiency at about 4,500 per flowing BOE, and that includes the facility cost. So that property is now producing over 120 million per day. The next expansion phase will grow production to 250 million per day with similar capital efficiencies. And we will point out that, that second expansion is not in the current 5-year development plan. So it's a growth project sitting outside the plan. Reserves at Sundown are already 1 TCF, and we've only booked 90 of the 857 locations we have in inventory. So plenty of upside there. Safe to say that the Jupiter and Modern assets are amalgamated into our Deep Basin complex, and we continue to realize the anticipated 30% to 40% capital cost reduction for drilling and completion that we envisaged when we embarked on that acquisition. Looking at our environmental performance improvement initiatives. We've essentially had an engineering team in place for over 18 months developing and implementing new proprietary emission reduction technologies, executing expanded water management initiatives, managing our third-party environmental-related research and more recently managing an emerging carbon offset business. We're operating a methane testing and research facility, and only one in Canada to our knowledge, have one of our Ansell-Edson gas plants. And the goal there is to evolve technology that more accurately measures fugitive flare and storage emissions as well as help realize our goal of 0 methane emission well sites. On the diesel displacement front, we've invested $8 million to date building the proprietary unit that we use. The long-term goal is to transition all of our drilling and frac operations to much lower emission natural gas and, where possible, high line power. Our rig in the Peace River High is fully electric and it does operate off the pads we're drilling now off high line power. To date, we've displaced 34.6 million liters of diesel with this initiative. And the net savings so far are $28 million, and that includes the cost of the replacement natural gas that we're running the rigs off. And I think I'll close out by just reminding that the Board of Directors has declared a quarterly cash dividend on our common shares of $0.16 per common share, and that dividend will be payable March 31, 2021, to shareholders of record at the close of business on March 18. And I think that's the end of the formal remarks. So we are more than happy to answer questions that you might have.

[Operator]

[Operator Instructions] Our first question comes from the line of Patrick O'Rourke with ATB Capital Markets.

[Patrick Joseph O'Rourke]

Just curious, you mentioned in the release or in the MD&A here that you sat on about 2.2 BCF of gas in storage at year-end, and it appears that you've drawn that all down. I'm just wondering, when we're thinking about trying to quantify the windfall cash flow there, how that sort of breakdown of the 2-plus BCF looked between PG&E and Dawn?

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

2/3 of it was PG&E and the other 1/3 is Dawn. And so use February prices, and then that will get you kind of what your revenue piece is for those withdrawals.

[Patrick Joseph O'Rourke]

Okay. So that sounds like it could be fairly significant windfall cash flow. And then just wondering, you guys -- in 2020 here, your -- you've executed extremely crisply and advantageously in terms of M&A. We've seen commodity prices firm up here both on the oil and the gas side. Just wondering how your outlook in terms of the M&A landscape is now, and what sort of inning you think we would be in, in that process in the cycle here? I know accretive M&A is one of your higher priorities for your free cash flow allocation.

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

Yes. I'd say, I mean, there still are lots of opportunities. So I'd term it as positive. I mean if oil prices continue to run and solidify, then perhaps that pipeline of opportunity slows down. But right now, we're always busy evaluating, and we only transact on a very small proportion of the things that we look at. So hopefully, that helps.

[Operator]

[Operator Instructions] Our next question comes from the line of Jordan McNiven with Tudor, Pickering, Holt.

[Jordan McNiven]

Two questions for me. First, on NGTL and the removal of the TSP. How much basis risk do you guys see there this kind of summer and fall? And is there an opportunity or an option to schedule your maintenance to align with that to reduce risk?

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

We always schedule our maintenance for the plants that have to turn around during TransCanada's scheduled maintenance cuts. Right now, the depth of those cuts does not appear to compromise IT. And therefore, we expect full access to storage. But that's TransCanada's schedule. So based on the cuts now, we don't anticipate problems on that side. So we expect storage to remain accessible, but we're always planning maintenance around cuts. That's just the right time to do it.

[Jordan McNiven]

Okay. Perfect. And second one for me is just on the shareholder return's angle. I assume there's a ceiling on how high you're comfortable pushing the common dividend given commodity volatility. In this context, does an add-on variable dividend makes sense at some point? And what's your view on a variable and what it makes sense for Tourmaline?

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

It's something we're looking at, Jordan, but have not made any firm decisions on. You're right, we want to make sure the dividend increases that we do proceed with are infinitely sustainable in even the harshest commodity price environment. And our -- the 2 priorities, as you know, for free cash flow right now for us, our dividend increases and debt reduction. And so I think shareholders should look forward to -- well, they've already got the dividend increase for Q1. So we expect to make a meaningful debt reduction payment in Q1 with free cash flow.

[Jordan McNiven]

Okay. And then just maybe one other follow-up for me. Just -- I know you guys have never -- in that priority, never had the buyback kind of ranked near the top. I mean how do you look at this when you look at where your valuation currently trades and the valuation gap versus you guys and your U.S. peers, which just seems stubbornly wide? Does the buyback start to play into that at all? Or is the ranking kind of shift around given this valuation gap?

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

It's something we're always thinking about. You're right, it hasn't ranked at the top of our list, and I would still say that debt reduction and dividend increases after Q1 probably rank ahead of that. We'd also -- if it makes sense, and one of these smaller tuck-in acquisitions materializes, we'd like to be able to pay for that with free cash flow as well. But our thoughts on the buyback has always been more tactical than programmatic, if you know what I mean. So we keep renewing our NCIB, and we have it as an option. Anything you want to add there, Brian?

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

I think you got it.

[Operator]

Our next question comes from the line of Josef Schachter with Schachter Energy Research.

[Josef I. Schachter, Author & President]

Question for me is on the [ GHTEA ] -- [ EHT ] side. You've mentioned, of course, about switching from diesel to natural gas. Looking at the one rig where you mentioned the electric is hooked up. Is there any larger projects where you can go through direct electricity? And then we saw the announcement with CP in Ballard yesterday about locomotives using hydrogen. Is that something that can be done in a large scale at some of your larger facilities? And what other new technology things should we be watching for that might be applicable directly in the field?

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

Well, we're very happy with what's happened with drilling rigs and doing those conversions. There isn't high line power available in all the places we operate. So at that, as the transmission system gets built out, we can migrate more high line power and not use the nat gas component. The next step is removing diesel or displacing diesel in a much larger way on the frac side of the business, and it's coming sort of in sequence after the drilling side of the business. There is always the option for select plant electrification that would really apply to new plants. But again, the transmission systems have to be in place, and we think it's probably a lot easier for CN to convert to natural gas rather than go all the way to hydrogen at this point in time.

[Josef I. Schachter, Author & President]

Okay. Last one for me is we're seeing the service industry talking about needing price increases if they're going to upgrade the equipment to do biofuels and things like that. Are you still starting to see any cost pressure in terms of the outlook for a post breakup? Are you -- and how much do you see us? And where is the worst part of the price pressure coming from?

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

We expect that service costs will come up with the more robust commodity price environment holds. We always build inflation into our 5-year outlook, sort of 2.5% per annum. We haven't had to utilize any of that over the past couple of years. Right now, there's no pressure, but we kind of negotiate post breakup. And so that remains to be seen where that goes.

[Operator]

And there are no further questions in queue at this time. I'd like to turn the call back over to our presenters.

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

Thanks, everyone, for attending, and we'll speak with you next quarter.

[Operator]

Ladies and gentlemen, this does conclude today's conference call. You may now disconnect.