Tourmaline Oil Corp

TSX:TOU

Earnings Call Transcript 2021-Q4

[Operator]

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q4 2021 Results Conference Call. At this time, all lines are on listen-only mode. Following the presentation, we will conduct a question-and-answer session. [Operator Instructions] This call is being recorded on Thursday, March 3, 2022.

I would now like to turn the conference over to Scott Kirker. Please go ahead.

[William Scott Kirker]

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'm here with Mike Rose, Tourmaline's President, 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.

[Michael L. Rose]

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 2021 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 2022 exit of between 510,000 and 515,000 BOEs per day. Full year 2021 after tax net earnings were a record CAD 2.03 billion or CAD 6.40 per diluted share. Our full year 2021 cash flow was a record CAD 2.93 billion or CAD 9.25 per diluted share and up 147% year-over-year, and importantly, we generated a record CAD 1.49 billion of free cash flow in 2021.

Exit 2021 net debt was CAD 973 million or below the low end of our range, long-term range of CAD 1 billion to CAD 1.2 billion. Year-end 2021 PDP reserves of 947 million BOEs were up 50% year-over-year including 2021 production. Total proved reserves of 2.19 billion BOEs were up 39% and 2P reserves of 4.24 billion BOEs were up 33% over year-end 2020.

We replaced 677% of 2021 annual production of 161 million BOEs with 2P additions of a little over 1 billion BOEs. The 2P reserve value equates to CAD 97.54 per diluted share. The total proved reserve NAV equates to CAD 62.70 and PDP CAD 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 2022 average production guidance of 500,000 BOEs per day remains unchanged. All three of our operated EP complexes are producing at or above full year 2022 guidance levels, which of course is very encouraging.

Looking at some of the financial highlights, as mentioned, full year 2021 after tax net earnings were a little over CAD 2 billion. Fourth quarter 2021 cash flow was CAD 968 million and full year 2021 cash flow was at record CAD 2.93 billion. On the shareholder return front, we increased the base dividend 3 times in 2021 to a total of CAD 0.72 per share, so that was a 29% increase over the course of the year, and we paid our first special dividend of CAD 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 2021, we increased the annual base dividend up to CAD 0.80 per share and paid our second special dividend of CAD 1.25 per share this time in February. Moving to the budget and the outlook, Q4 2021 EP capital expenditures were CAD 411 million, and as previously discussed, we accelerated the construction of the Gundy Phase 2 deep cut and the Aitken 46-C expansions into the second half of 2021. Both projects were completed on budget and are currently on stream and at full capacity.

In 2022 at current strip pricing, we expect to generate cash flow of CAD 4.05 billion or CAD 11.97 per diluted share and free cash flow of CAD 2.85 billion or CAD 8.43 per diluted share on unchanged EP capital expenditures of CAD 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 five-year EP capital plan.

As mentioned, our exit 2021 net debt was CAD 973 million, or 0.25 times 2021 net debt to Q4 2021 annualized cash flow and below the company's long-term debt target of CAD 1 billion to CAD 1.2 billion. We had another strong reserve year in 2021. Year-end 2021 PDP reserves of 947 million BOEs. As mentioned, we're up 50%, including annual production of 161 million BOEs.

2021 PDP FD&A costs were CAD 7.27 per BOE, including changes in future development capital and that yielded a PDP reserve recycle ratio of 2.5. Our total approved FD&A costs in 2021 were CAD 5.94 per BOE and our 2P FD&A was CAD 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 2021 2P reserves of 4.24 billion BOEs. So, there's lots more to come. The current FDCs associated with 2P reserves represent only three years of prospective cash flow at strip pricing.

On the marketing front in 2021, we further diversified the gas marketing portfolio by establishing a US 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 2022 of this year, the company will increase gas volumes exported to western US 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 2021 were up 24% over third quarter 2021, 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 2021 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 costs per lateral foot by 30% in that time period.

We operated 13 drilling rigs and four to five frac spreads across the three EP complexes during January and February of this year as planned. We continue to operate all five 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 2021 and completed on budget. The Aitken 46-C expansion and deep cut installation was executed in 120 days for CAD 96.5 million. The previous owner had estimated 270 days for a CapEx of CAD 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 2025-2026 timeframe coinciding with the projected startup 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 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 two weeks of production. It just came on stream and we had a very strong two-well Wilrich pad at Smoky in the north end of the Deep Basin complex, which between the two 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 two years. We have successfully tested six new horizon spread across the three operated complex, so it's working well. In our year-end 2021 reserve report, we've already booked 845 Bcf of 2P reserves from the discovery so far, and further successful delineation drilling is planned in all three complexes over the next 12 months, and we will disclose further details in upcoming quarters as we can, and this initiative, we believe, provide 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-2021 that we were pausing our larger corporate acquisitions, but we have also indicated that CAD 200 million to CAD 300 million of annual free cash flow could be allocated to further smaller complementary asset acquisitions within our existing complexes. During Q4 2021 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 gross sections of land, and that includes land sales that we've gone to an additional 238 gross drilling locations for total cash outlay between the two quarters of just a little under CAD 64 million. So, very strong metrics.

Looking at environmental performance improvement, we had a very busy and successful year in 2021 with multiple initiatives making measurable progress on emissions reduction. We have an engineering team in place and it's been there for over three 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 CAD 20 million to CAD 40 million per year now on environmental performance improvement activities.

We have now displaced diesel with nat gas on all of the drilling rigs in the operated fleet and we have, where possible, one 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 2021, we entered into a JV with Trican to utilize the first Tier 4 nat gas frac unit in Canada, so further work on our diesel displacement initiatives. The company achieved its net 25% methane reduction target in 2021 three 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 2021, the Emission Testing Center or what we refer to in our literature is 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 CAD 0.20 per common share as anticipated.

And finally, related to our emission reduction natural gas, we see as 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, the best thing we can do for global emissions and for the Canadian economy.

So, we're more than interested in answering any questions that you might have.

[Operator]

Thank you, ladies and gentlemen. We will now begin our question-and-answer session. [Operator Instructions] Your first question will come from [ph] Josef of Schachter (15:54). Please go ahead.

[Josef Schachter, Analyst, Schachter Energy Research Services Inc.]

It's Josef Schachter there. I'll – that'll be me. Good morning, everyone and congratulations on a great year, and Mike and Scott and Brian, and of course, 2022 looks like an exciting year. I have two questions. One, you're looking at doing your stock buybacks, your purchase prices last year were 200,000 shares at CAD 32.73 your PDP level. Is that the kind of number you're looking that whenever 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?

[Michael L. Rose]

Yeah. 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.

[Josef Schachter, Analyst, Schachter Energy Research Services Inc.]

Sure. And 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 into 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?

[Michael L. Rose]

Yeah. So, I mean, the Cheniere deal, I mean, I guess, will 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 2023. And yes, of course, we're looking at as many other LNG opportunities as we can. And I think, you know 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, yeah, 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 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.

[Josef Schachter, Analyst, Schachter Energy Research Services Inc.]

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

[Michael L. Rose]

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

[Josef Schachter, Analyst, Schachter Energy Research Services Inc.]

Okay. That does it for me. Thanks very much and again congratulations.

[Michael L. Rose]

Thank you.

[Operator]

Your next question will come from Fai Lee with Odlum Brown. Please go ahead.

[Fai Lee, Analyst, Odlum Brown Ltd.]

Hi. Thank you. Fai here. [ph] Just a quick (19:36) question, like in terms of this, the JKM exposure, obviously, prices are a lot higher and I think the future [indiscernible] (19:43) a bit. Wondering how you're building on to your five-year plan in terms of the pricing?

[Michael L. Rose]

Sure. So, basically, every time you run the five-year plan, we're running a strip and the five-year plan was most recently run on the February 15 strip, at which time the [ph] California 3 JKM price is roughly CAD 18 (20:01). And so we reflect the future strip pricing, which does [indiscernible] (20:08) from there over the five-year plan and that benefit has layered in nicely into the future cash flows. And I would point out that today JKM 2023 is north of CAD 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.

[Fai Lee, Analyst, Odlum Brown Ltd.]

Okay. Great. Thank you. [Operator Instructions]

[Operator]

Your next question will come from Cam Bean with Scotiabank. Please go ahead.

[Cameron Bean, Analyst, Scotia Capital, Inc.]

Hey, guys. 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?

[Michael L. Rose]

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 that – 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?

[Cameron Bean, Analyst, Scotia Capital, Inc.]

Yeah. Thank you very much.

[Operator]

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

[William Scott Kirker]

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

[Operator]

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