Tourmaline Oil Corp. (TOU) Earnings Call Transcript & Summary

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q4 2021 Results Conference Call. [Operator Instructions] This call is being recorded on Thursday, March 3, 2022. I would now like to turn the call -- the conference over to Scott Kirker. Please go ahead.

Thank you, operator, and welcome, everyone, to our discussion of Tourmaline's results for the years ended December 31, 2021 and 2020. 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 in the Tourmaline Annual Information Form and our MD&A available on SEDAR and on our website. I also draw your attention to the material factors and assumptions in those advisories. I am here with Mike Rose, Tourmaline's President and Chief Executive Officer; Brian Robinson, Vice President, Finance and Chief Financial Officer; and Jamie Heard, our Manager of Capital Markets. We will start by speaking to some of the highlights of the last quarter and our year so far. After Mike's remarks, we will be open for questions. Go ahead, Mike.

Thanks, Scott, and thanks, everybody, for dialing in, and we're pleased to go through our strong 2021 results. So lots of highlights. Full year and average '21 production of 441,000 BOEs a day was up 42% year-over-year. Our current production is ranging between 500,000 and 510,000 BOEs a day, and we expect a Q1 '22 exit of between 510,000 and 515,000 BOEs per day. Full year '21 after-tax net earnings were a record $2.03 billion or $6.40 per diluted share. Our full year '21 cash flow was a record $2.93 billion or $9.25 per diluted share and up 147% year-over-year. And importantly, we generated a record $1.49 billion of free cash flow in 2021. Exit '21 net debt was $973 million or below the low end of our range, long-term range, of $1 billion to $1.2 billion. Year-end '21 PDP reserves of 947 million BOEs were up 50% year-over-year, including 2021 production. Total proved reserves of 2.19 billion were up 39% and 2P reserves of 4.24 billion BOEs were up 33% over year-end 2020. We replaced 677% of '21 annual production of 161 million BOEs with 2P additions of a little over 1 billion BOEs. The 2P reserve value equates to $97.54 per diluted share. The total proved reserve NAV equates to $62.70 and PDP $33.77, using the same pricing and discount rates. Tourmaline now has 19.5 Tcf of 2P natural gas reserves. Turning to production specifically. As mentioned, current production ranging between 500,000 and 510,000 BOEs per day. Our full year '22 average production guidance of 500,000 BOEs per day remains unchanged. All 3 of our operated EP complexes are producing at or above full year '22 guidance levels, which, of course, is very encouraging. Looking at some of the financial highlights. As mentioned, full year '21 after tax, net earnings were a little over $2 billion. Fourth quarter '21 cash flow was $968 million, and full year '21 cash flow was that record $2.93 billion. On the shareholder return front, we increased the base dividend 3 times in 2021 to a total of $0.72 per share. So that was a 29% increase over the course of the year, and we paid our first special dividend of $0.75 per share in October of 2021. And we have committed to returning the majority of annual free cash flow to shareholders, and we are executing on that plan. Subsequent to year-end '21, we increased the annual base dividend up to $0.80 per share and paid our second special dividend of $1.25 per share, this time in February. Moving to the budget and the outlook. Q4 '21 EP capital expenditures were $411 million. And as previously discussed, we accelerated the construction of the Gundy Phase II deep cut and the Aitken 46-C expansion into the second half of 2021. Both projects were completed on budget and are currently onstream and at full capacity. In 2022, at current strip pricing, we expect to generate cash flow of $4.05 billion or $11.97 per diluted share, and free cash flow of $2.85 billion or $8.43 per diluted share on unchanged EP capital expenditures of $1.125 billion in 2022. We continue to maintain our strong capital discipline. We always build 2.5% inflation per annum on both capital and operating costs into the company's 5-year EP capital plan. As mentioned, our exit '21 net debt was $973 million or 0.25x '21 net debt to Q4 '21 annualized cash flow and below the company's long-term debt target of $1 billion to $1.2 billion. We had another strong reserve year in 2021. Year-end '21 PDP reserves of 947 million BOEs, as mentioned, were up 50%, including annual production of 161 million BOEs. '21 PDP FD&A costs were $7.27 per BOE, including changes in future development capital, and that yielded a PDP reserve recycle ratio of 2.5. Our total proved FD&A costs in '21 were $5.94 per BOE, and our 2P FD&A was $4.54 per BOE, including changes in FDC. Importantly, we have only booked 3,168 gross locations of a total drilling inventory of 22,715 gross locations. So we have only booked 14% of the overall inventory to achieve our year-end '21 2P reserves of 4.24 billion BOEs. So there's lots more to come. The current FDCs associated with 2P reserves represent only 3 years of prospective cash flow at strip pricing. On the marketing front, in '21, we further diversified the gas marketing portfolio by establishing a U.S. Gulf Coast LNG long-term netback supply agreement with Cheniere Energy. In 2023, Tourmaline will become the first Canadian EP company participating in the LNG business with full exposure to JKM pricing, providing a material increase to anticipated 2023 cash flow. In November 22 of this year, the company will increase gas volumes exported to Western U.S. markets from 345 million to 445 million cubic feet per day, with approximately 67% of that gas accessing the premium-priced PG&E California market. NGL price realizations in the fourth quarter of '21 were up 24% over third quarter '21. And a reminder, we are the largest NGL producer, with anticipated average production levels of over 70,000 barrels per day in 2022. Turning to E&P, we are the busiest operator in the basin. We drilled a total of 280 net wells during '21 for a total of 1.289 million meters drilled. We have systematically increased our lateral length of our horizontals by over 30% since 2018, while simultaneously reducing actual drill complete cost per lateral foot by 30% in that time period. We operated 13 drilling rigs and 4 to 5 frac spreads across the 3 EP complexes during January and February of this year as planned. We continue to operate all 5 drilling rigs in Northeast BC, with multiple high-performance pads at Sundown, Gundy, Aitken and Laprise all contributing a little ahead of expectation. The facility expansions at Gundy and Aitken were accelerated in the second half '21 and completed on budget. The Aitken 46-C expansion and deep cut installation was executed in 120 days for $96.5 million. The previous owner had estimated 270 days for a CapEx of $116 million. We continue to evolve the Conroy/North Montney development project. This minimum 100,000 BOE per day gas and liquids project is currently planned in the '25/'26 time frame, coinciding with the projected start-up of LNG Canada and the anticipated related strong intra-Basin natural gas pricing. And some strong recent pads, the three-well Upper Charlie Lake pad in our Peace River High complex has averaged at a combined production rate of 2,500 barrels of oil per day and a little under 3 million a day of gas over the first 2 weeks of production, it just came on stream, and we had a very strong 2-well Wilrich pad at Smoky in the north end of the Deep Basin Complex which, between the 2 wells combined, tested at over 65 million per day during the testing period. [ A goal ] -- or a good time for some very strong wells. We are updating our exploration program. We've been working on it for over 2 years. We have successfully tested 6 new horizons spread across the 3 operated complexes, so it's working well. In our year-end '21 reserve report, we've already booked 845 Bcf of 2P reserves from the discoveries so far, and further successful delineation drilling is planned in all 3 complexes over the next 12 months. And we will disclose further details in upcoming quarters as we can. And this initiative, we believe, provides shareholders with an additional unique long-term growth and value accretion opportunity on top of the regular EP program. A brief acquisition update. We indicated mid-'21 that we were pausing our larger corporate acquisitions, but we have also indicated that $200 million to $300 million of annual free cash flow could be allocated to further smaller, complementary asset acquisitions within our existing complexes. During Q4 '21 and thus far in Q1 of this year, we completed a number of these small acquisitions that in aggregate we believe are meaningful. So to that end, we've acquired 2,400 BOEs per day of production, an estimated 43 million BOEs of 2P reserves -- those are internal company estimates -- 295 drill sections of land, and that includes land sales that we've gone to, and additional 238 gross drilling locations for total cash outlay between the 2 quarters of just a little under $64 million. So very strong metrics. Looking at environmental performance improvement, we had a very busy and successful year in '21, with multiple initiatives making measurable progress on emissions reduction. We have an engineering team in place and it's been there for over 3 years, developing and implementing new proprietary emission reduction technologies, executing our expanded water management initiatives, managing third-party environmental-related research, evolving a methane testing center and managing an emerging carbon offset business. We are investing $20 million to $40 million per year now on environmental performance improvement activities. We have now displaced diesel with natural gas on all of the drilling rates in the operated fleet. We have, where possible, 1 rig running directly on high line power. And this has provided a significant emissions reduction and cost savings, so a double win for shareholders. During '21, we entered into a JV with Trican to utilize the first Tier 4 natural gas frac unit in Canada, so further work on our diesel displacement initiatives. The company achieved its net 25% methane reduction target in '21, 3 years earlier than anticipated. And we're not done there, and we've set new methane reduction targets, and we'll execute on those as well. In '21, the Emission Testing Center, or what we refer to in our literature as the ETC, it's the first of its kind in the world. It's at the West Wolf gas plant in the Deep Basin and it became fully operational in Q4. And it's critical in evolving new technology and methodologies to materially reduce methane and other emissions across the entire EP business. We did announce that the Board of Directors have declared a quarterly cash dividend on the common shares of $0.20 per common share as anticipated. And finally, related to our emission reduction, natural gas, we see, is the great enabler of our future energy transformation. It will be the largest component of the future energy stack for a very long time, and Canada should be supplying as much of our low-emission natural gas to the rest of the world through a material and growing LNG business. It's the best thing we can do for global emissions and for the Canadian economy. We're more than interested in answering any questions that you might have.

[Operator Instructions] Your first question will come from Joff Schachter.

It's Josef Schachter. Congratulations on a great year, Mike and Scott and Brian, and of course, 2022 looks like an exciting year. I have 2 questions. When you're looking at doing your stock buybacks, your purchase prices last year were 200,000 shares at $32.73, your PDP level. Is that the kind of number you're looking, that whatever the market backs off and it gets to PDP? Or are you looking at some level going forward between PDP and 1P as a purchase price for your share buybacks?

Yes. I think you've probably hit on it, Josef. So we reset our targets with the new reserve report. And so in that range is reasonable, but we're continually evolving our shareholder return equation and how we treat all of the parameters in it. And so we're going to do a mix of all of the identified allocation opportunities or silos. So share buybacks and base dividend increases and special dividends while we have elevated commodity prices.

Okay. And a second question for me. With LNG now, and all the problems in Ukraine and security of supply and shortages around the world, are there any other initiatives that Tourmaline is looking at to get into the LNG space and to a greater degree and being involved in new projects and maybe even owning pieces of it? How do you see, going forward, Tourmaline building up its potential LNG on top of the very attractive deal you did with Cheniere?

Yes. So I mean the Cheniere deal, I mean, I guess we'll be the first Canadian company actually able to ship gas to Europe, and where those cargoes go, we'll see, but that starts up in January of '23. And yes, of course, we're looking at as many other LNG opportunities as we can. And I think the limitations, other than Coastal GasLink and LNG Canada, to grow our Canadian LNG business, we need more pipelines and more projects. But we're looking at all of the various opportunities to move gas offshore and get it to Europe and, of course, Asia, where that's where we can accomplish the greatest emission reduction possible, and it's the best thing, as I mentioned, that Canada can do. So yes, it's encouraging from that standpoint. It's just a bit discouraging that the 10 Bcf a day that could have been on Canadian coasts if we'd done things right in kind of '09 -- 2009 to 2012, it all ended up on the Texas Gulf Coast. And so now it's our turn to build it up in Canada.

Right. Would you look at just being a provider to the LNG projects? Or would you look at having some ownership as well?

I think at this point in time, we prefer to be a provider.

Your next question comes from Fai Lee with Odlum Brown.

Just a quick question, Mike. In terms of this JKM exposure, obviously prices are a lot higher. And I think the future is suggesting they're going to trend down a bit. Wondering how you're building that into your 5-year plan in terms of the pricing?

Sure. So basically, every time we run the 5-year plan, we're running a strip. And the 5-year plan was most recently run on the February 15 strip, at which time the [indiscernible] JKM price was roughly $18. And so we reflect the future strip pricing, which does backwardate. It's $18 and it backwardates from there over the 5-year plan. And that benefit has layered in nicely into the future cash flows. And I'd point out that today JKM 2023 is north of $20. So as we continue to march forward through the year and through the disruptions we've seen in the market, the contract appears to be getting more and more valuable.

[Operator Instructions] Your next question will come from Cam Bean with Scotiabank.

Congratulations on the great 2021 results. Just a quick question on the reserves report. How is the Conroy/Northern Montney project represented in there in terms of FDC and reserve bookings beyond 2025?

Well, it rolled in pretty much as we did the acquisitions in the North Montney. So that includes Polar Star, which was done in 2021, and then Saguaro and Black Swan in 2021. And so those make up the majority of the -- what we will term Conroy, which is a broader kind of Laprise/Aitken development, and we're planning the facilities now and what the liquid infrastructure related to that looks like. But they're in there. And obviously, there's lots of upside. We haven't booked all the locations that came with those acquisitions. But there's a very long runway of further bookings and additional locations to be put in inventory in those areas. Is that helpful?

There are no further questions at this time. Scott Kirker, please go ahead.

Thank you, operator. Thanks, everyone, for listening in, and we look forward to chatting with you all at the end of the next quarter.

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