Tourmaline Oil Corp

TSX:TOU

Earnings Call Transcript 2022-Q2

[Operator]

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q2 2022 Results Conference Call. [Operator Instructions] This call is being recorded on July 28, 2022. I would now like to turn the conference over to Jamie Heard. Please go ahead.

[Jamie Heard, executive]

Thank you, operator, and welcome, everyone, to our discussion of Tourmaline's results for the 3 and 6 months ended June 30, 2022 and 2021. My name is Jamie Heard, and I am Manager of Capital Markets 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 and Chief Executive Officer; and Brian Robinson, Vice President, Finance and Chief Financial Officer. 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. Mike, please go ahead.

[Michael Rose, executive]

Thanks, Jamie. Welcome, everybody, and thanks for dialing in. We're pleased to review our Q2 results and go over the related operational and financial updates. First, the highlights. Second quarter '22 cash flow was a record $1.35 billion, and that's a 137% increase over the second quarter of 2021. Net debt at June 30 was $430 million, which is well below our long-term debt target of $1 billion to $1.2 billion. Second quarter '22 free cash flow was a record $1.1 billion or $3.25 per diluted share, and that enabled us to declare a special dividend of $2 per common share to be paid August 12 to shareholders of record on August 5. Our trailing 12 month of distributed dividends now total $6.28 per share, inclusive of this special dividend, and that's an implied 9% trailing yield.

Second quarter '22 EP capital spending was $229 million, well within guidance, and second quarter '22 net earnings were $823 million or $2.40 per diluted share.

We, with our update, released a new EP growth plan for the period 2022 to 2028. It generates $31.4 billion of cash flow and $18 billion of free cash flow at strip pricing as of July 18, '22 on total EP spending over the period of $12.7 billion. Average annual production growth during this plan is approximately 6%, and the total growth over the period is 40%.

Looking at production briefly. Second quarter '22 production average was 503,000 BOEs per day or 506,000 prior to our Q2 storage injections in Dawn and California and within previous disclosed guidance range. It's a 23% increase over the second quarter of '21 production of 410,000 BOEs per day. The modest EP activity increase post breakup will lead to a higher Q4 '22 production forecast, now 520,000 to 525,000 BOEs per day, and that's up from 510,000 BOEs per day in the previous May plan. A full year '22 average production forecast of 507,000 BOEs per day is now expected.

Full year '22 average liquids production of over 115,000 barrels per day is expected and that's up 19% from average '21 levels, and that's condensate oil and NGLs.

Looking at our financial results in a little more detail. As mentioned, both quarterly cash flow and free cash flow were records. At current strip pricing, the July '18 strip full year '22 cash flow of $5 billion is now anticipated or $14.69 per fully diluted share. Given the strong commodity price outlook and anticipated record cash flow in '22, we intend to return a minimum of 60% of free cash flow to shareholders in calendar '22.

We intend to pay quarterly special dividends through the balance of '22 and now 2023. The magnitude of these special dividends will be a function of commodity prices and available quarterly free cash flow. We do intend to return the majority of free cash flow, so greater than 60% in '22 and a range of 50% to 75% in '23 to shareholders through base dividend increases, special dividends and share buybacks. A component of free cash flow will also be used for modest incremental EP investments, and that includes new pool/new zone exploration opportunities, continued asset acquisitions within existing core complexes and select margin-improving infrastructure investments.

Moving to marketing. Tourmaline currently has 620 million per day access in U.S. markets through long-term firm transport agreements and this volume will grow to 905 million per day by exit 2023. We are amongst the most diversified of all North American large gas producers from a market asset standpoint, and we continue to explore opportunities to expand this export capability.

The company's $140 million per day Gulf Coast LNG deal with Cheniere commences Jan 1, '23, and it provides exposure to JKM pricing over the 15-year term of the deal. The JKM strip was USD 31.88 per million BTU as of July 19, '22.

Realized NGL prices were $51.83 per barrel in Q2 '22, and that's up 99% from the Q2 2021 time period. And we are the largest NGL producer in Canada.

Looking at our longer-term EP strategy. The new EP growth plan extends through '28, as mentioned, and it incorporates the current 12 to 13 drilling rate fleet that we have in our employ through the second half of '22 and through the balance of the plan. And we felt it was prudent to retain the drilling and completion services that we'd already secured on a go-forward basis. The previous plan could be executed with approximately 11 drilling rigs.

The new EP growth plan also includes phase 1 of the Conroy North Montney development project commencing production through new Tourmaline facilities in the first quarter of 2026 and with phase 2 start-up of that project in 2028. The new EP growth plan, '22 through '28, generates $31.4 billion of cash flow and $18 million of free cash flow at strip pricing on total EP spending of $12.7 billion. And as mentioned, the average annual production growth during the plan is approximately 6%.

The updated EP plan will consume approximately 2,500 gross drilling locations through to end '28, and that's only 11% of our current inventory of over 22,000 locations. We believe the modestly increased capital program on very high-return EP projects is a good utilization of free cash flow. And given elevated commodity prices and the related very short payout periods, these incremental expenditures actually increase free cash flow in the year of expenditure.

The total incremental gas production of 250 million per day in the '23-'24 time frame via the expanded program, which is up approximately a net 100 million per day from the previous EP plan, coincides with incremental basin egress, which is consistent with our long-term balance base and supply narrative. Through expansions on the GTN system and the company's Gulf Coast Cheniere LNG agreement, we have 100 -- or sorry, 300 million per day of incremental basin egress commencing in '23. So it more than offset any of the growth that we'll see in '23, '24. And of note, these gas volumes will access the 2 destinations with a sustained premium gas price, international LNG and California.

Tourmaline is able to deliver a strong, sustainable annual return to shareholders, saw greater than 60% of free cash flow in '22, a meaningful sustained annual production growth profile, so 6% over the next 6 years, and continued material value accretion through profitable annual reserve additions.

Looking at our capital spending and our financial outlook. As mentioned, second quarter '22 EP CapEx was $223 million, and within guidance. The full year '22 EP capital budget has been increased to $1.5 billion, and that reflects the increased second half '22 EP program as well as a further contingency for inflation. Our '23 EP capital program is estimated at $1.6 billion. That reflects the 12- to 13-rig program for the full year and a much increased inflation contingency for '23 over what was in the May '22 plan. The EP program is expected to deliver annual production of 545,000 BOEs per day and cash flow at strip pricing of $5.1 billion and free cash flow of $3.5 billion. So not backwardated from the results that you'll see in 2022.

The second half '22 and '23 CapEx programs include up to 10 incremental exploration, new zone or new pool wells and that's following up on multiple successes to date.

Net debt at June 30, '22 was $430 million, well below the long-term debt target of $1 billion to $1.2 billion, and this places the company in an excellent position to concurrently fund the Conroy North Montney development and continue with our free cash flow allocation strategy and returns to shareholders.

A little bit more on the Conroy North Montney development. The new EP growth plan incorporates the full project with January 1, '26 targeted on stream date for phase 1. And the second phase will be on stream in '28. And each phase consists of 50,000 BOEs per day of production. Phase 2 could be accelerated contingent upon commodity prices and overall basin egress considerations.

We've drilled a total of 14 delineation pads within that North Montney project area over the past 18 months, really to confirm well performance and capital costs. Capital costs are definitely on target and well below those of previous operators, and well performance has exceeded original expectation for the vast majority of the new pads. As part of this North Montney development project, we've negotiated a new long-term transportation and fractionation arrangement with Pembina Pipeline Corporation for the incremental or growth condensate and NGL volumes from the project area. And this agreement ensures that all new company liquid volumes will flow upon project startup, along with significant flexibility and strong operating margins for Tourmaline in the overall North Montney development area.

And as part of the long-term associated facility strategy and build-out, we closed the previously announced acquisition of the 50% nonoperated interest in the 2 Aitken area gas plants during the second quarter of '22.

We are also pleased to announce that we've entered into a binding agreement to acquire Rising Star for $194.3 million. Closing is expected to occur in the first half of August of this year. The purchase price includes common shares of Topaz Energy Corp. that we currently own, with the balance paid in cash. Rising Star assets are located within our Peace River High Charlie Lake complex. Current production from the acquired assets is approximately 5,700 BOEs per day, and we estimate 2P reserves at 50 million BOEs. Rising Star has no outstanding debt.

Included in the acquisition are facilities that complement our existing infrastructure and the pooling of land bases will facilitate drilling of much longer horizontals in the lower Charlie Lake that we've been delivering very strong results from recently. And do recall that we kind of invented this play about a decade ago. In a further transaction, we have entered into a definitive agreement to sell GOOR to Topaz on the Rising Star lands, along with a similar GOOR on lands acquired during the past year or so, primarily in the Deep Basin.

Tourmaline will receive cash proceeds of $52 million from Topaz in third quarter of 2022. We may also pursue dispositions of noncore components of the Rising Star asset base during the balance of '22. Specifically on EP in the quarter, we drilled 33.5 net wells and completed 25.5 net wells in second quarter, 26 new net wells were brought on production. A total of 142.7 net wells are anticipated to come on production during the second half of this year, and we currently have 13 drilling rigs and 5 frac spreads active across our 3 EP complexes. We're excited about how the 2.5-year-old exploration program is proceeding. And really, the best way to manage an exploration program is to not say anything until it's worked, and it most certainly has.

The ongoing new pool/new zone exploration effort has yielded 3 significant successes to date. We have 41 successful producing horizontals into a new liquid-rich gas zone in the Alberta Deep Basin, with just under 500 Bcf equivalent of 2P reserves already booked in the December 31, '21 GLJ reserve report. We expect a further 7 horizontals to be drilled into this horizon in the Deep Basin during the second half. We have 7 producing horizontals into new zones in our South Montney BC complex with 318 Bcf equivalent of 2P reserves booked at year-end '21. The third play has no reserves booked yet, but it does have 2 successful horizontals into the same zone 32 kilometers apart, drilled and successfully tested. So on a follow-up plan there. And we have new zone/new play exploration wells planned on the Peace River High and in the Deep Basin in completely different zones during the second half of this year.

Looking at our ongoing environmental performance improvement. We're very pleased that we've received preliminary platinum ratings from Project Canary, the Trustwell assessment of a series of company-operated Northeast BC assets with an average score of 131 achieved. And to our knowledge, we're the first Canadian gas company with a trust well score, and this ranks in the top 10% in all of North American E&Ps.

On the diesel displacement initiative, all of our contracted rig fleet is displacing diesel with nat gas or actually running fully electric. And Tourmaline was operating the available three Cat Tier 4 natural gas-powered frac spreads in Western Canada during July of '22. And this evolving diesel displacement initiative significantly reduces emissions and cost for the company.

And finally, we're also pleased to announce that the TSX has approved the renewal of our normal course issuer bid, and that will be in place for the next year. So that's all I was going to say, and it's a lot. So we can turn it over for Q&A now. And Brian and I and Jamie can hopefully answer your questions.

[Operator]

[Operator Instructions] Your first question comes from Fai Lee, Odium Brown.

[Fai Lee, analyst]

It's Fai here. I just had a couple of quick questions. The first is regarding the capital efficiencies outlook that's mentioned in the press release about that you're looking at about 8,500 per flowing barrel in the out years of your capital plan. I'm just wondering of your -- about your confidence level around that estimate and just given all these concerns about inflation going forward.

[Michael Rose, executive]

Sure. Well, that 8,500 in the out years of the plan includes both a large inflation contingency. And in those out years, that's when the facility dollars are being spent, and so it does drive your 8,500 up. So we're quite confident in that. I mean, as far as executing on the facility piece, what we're putting in place is essentially what we've put in place at Gundy already in two phases. So I mean, we're confident that we can do it. And of course, we'll try and do it for even less than we're currently planning and in shorter time periods.

And kind of the run rate capital efficiency in the years where there aren't significant facility expenditures are kind of in that 7,500 to 8,000 range. And so that's up from -- we were targeting 7,000 to 7,500. And so the difference there is inflation, and we think we've put in a very large contingency for it in the first 2 or 3 years in the plan. Is that helpful?

[Fai Lee, analyst]

Okay. Yes, that's great. And regarding your new plan out to 2028. The -- in terms of the -- I was looking at the price assumptions, and they're obviously a lot higher than, obviously, the natural gas prices [ of coal ] futures curve has moved up. I'm wondering in terms of how you're thinking about it in terms of if the price kind of comes off, how much -- are you sticking with the plan or under what conditions would you read into the plan in terms of the pricing outlook for gas?

[Michael Rose, executive]

Yes. Well, I think -- I mean, you would realize that nothing is ever fully cast in stone. You're right, the out years have been coming up, but the curves are still significantly backwardated. And we would remind all that the world, in general, is short of natural gas. Our timing, though, for the start-up of the North Montney development, both phases, coincides with the startup of LNG Canada, and we've thought for a long time that, that will be a very positive event for AECO and Station 2 pricing because you'll take a basin that is roughly in supply-demand balance, it is now, and we expect that to continue. And then you're going to pull a significant gas volume out and move it west.

So whatever the world price is at that point, I think that will be a very positive local price initiative or development for the basin. But obviously, we'll watch prices and we have the flexibility to slow things down or speed things up, whatever the right thing to do is. And I will remind everyone that a little bit of incremental growth, which equates to about 100 million a day net between '23 and '24 all moves out of the basin. None of it goes to AECO. And our deliveries to AECO or Station 2 in the '23, '24 time period actually drop on a net basis. So we think that's a very responsible way to bring on very high return new production, and we'll move it right out of the basin.

[Fai Lee, analyst]

Okay. Great. And just the last question. Can you maybe just comment on your strategy around using Topaz as funding vehicle? Obviously, you're gaining a lot of cash and you can probably just fund your bolt-on acquisitions with your cash. I'm just wondering how you think about Topaz on the whole -- in your planning capital spending?

[Michael Rose, executive]

Sure. We'll continue to use or look at doing transactions with Topaz to enhance the returns on acquisitions that we may or may not make.

[Operator]

There are no further questions at this time. I will now turn it back to Jamie Heard.

[Jamie Heard, executive]

Thank you very much, operator, and thanks, everyone, for dialing in, and have a great day.

[Operator]

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