Tourmaline Oil Corp.

Good morning, ladies and gentlemen, and welcome to the Tourmaline quarter two results conference call. At this time, all lines are in listen only mode. Following the presentation, we will conduct a question and answer session. If at any time during this call you require immediate assistance, please press star zero for the operator. This call is being recorded on Thursday, July 29th, 2021. I would like to turn the conference over to Scott Kirker. Please go ahead.

Thank you, Operator, and welcome everyone to our discussion of Tourmaline Oil Corp's results for the three and six months ended June 30, 2021 and 2020. My name is Scott Kirker, and I'm the General Counsel of 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 Forum and our MD&A available on CDAR 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 of Finance and Chief Financial Officer, and Jamie Hurd, Tourmaline's Senior Capital Markets Analyst. 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 review our second quarter results and answer questions that shareholders may have. Starting out with the highlights, second quarter 2021 cash flow was $1.89 per diluted share. We had record-free cash flow of $343.9 million on production of 410,339 DOEs per day, which exceeded the high end of production expectations despite challenging operating conditions with June's heat wave. The updated five-year plan at current strip pricing delivers $1.8 billion of free cash flow in 2022 and $7 billion over the full five-year duration of the plan. We received a credit rating upgrade from BBB to BBB High in July of 21 by DBRS Morningstar. We now expect to achieve our year-end 21 net debt target of approximately $1 billion or 0.4 times debt cash flow and less than one times annual free cash flow prior to year end. With incremental volumes on the GTN Malin PG&E systems and the company's recently announced Gulf Coast LNG pathway in 2023, Tourmaline will have $905 million a day exposed to export markets on firm long-term transport agreements by exit 2023. Our largest export market, PG&E California, is currently trading at $5.50 per MMBTU in U.S. dollars. Looking at production in a little more detail, as mentioned, second quarter, 21 average production was a little over 410,000 BOEs per day and a little over 414,000 BOEs per day prior to storage injections into our storage reservoirs in California and Dawn. So that's a 37% increase over the prior year, Q2 2020. We anticipate third quarter average production will range between 450,000 and 460,000 VOEs per day. We expect to reach the 500,000 VOE per day production milestone in Q2 of 2022, primarily through the completion of The Gundy Phase 2 project, the Neat Creek expansion project, and the ongoing LaPree's development program. 2021 average production for the year remains estimated at 430,000 to 445,000 BUEs per day. Looking at our very strong financial results, second quarter 21 cash flow was $570 million compared to $225 million or $0.83 per diluted share in Q2 2020. Second quarter 21 after-tax net earnings were very strong at $428 million or $1.40 per diluted share, and that compares to $20 million or 7 cents per diluted share in the second quarter of 2020. We delivered free cash flow of $344 million on EP capital spending of $216 million in the second quarter. Full year 21 cash flow of $2.78 billion is now expected with estimated free cash flow for 21 of $1.47 billion. We received the credit rating upgrade in July of this year following the close of the Black Swan acquisition, moving up to BBB high from BBB for both the issuer rating and the senior unsecured notes. The credit rating upgrade is expected to result in lower effective interest rates on company debt which already are extremely low and in the top tier at 1.72% for the second quarter. Revisiting the capital program and the financial outlook, second quarter 21 E&P capital spending was on target at 216 million. Full year 21 E&P capital spending remains at 1.27 billion. Net debt at June 30th of this year was 1.7 billion. which excludes the two Northeast BC transactions with Tobas, which yield 390 million in cash, both of which will close in the third quarter of 21. Exit Q3 21 expected net debt is approximately 1.4 billion, including the impact of all acquisitions completed to date in 2021. We now expect to achieve the year-end 21 net debt target of approximately 1 billion As at July 15, 2021, Tourmaline's Topaz equity ownership was valued at $934 million, which essentially offsets the estimated 21-year-end net debt. As mentioned, the updated five-year plan and current strict pricing now delivers $1.8 billion of free cash flow in 2022 and $7 billion over the full five-year duration of the plan. Looking at a little bit more detail at the growing free cash flow outlook and our plans, our consistent 2021 narrative has been that our top two priorities are modest sustainable dividend increases and continued debt reduction to our long-term debt target of 0.5 times debt to cash flow. So far in 21, we've used free cash flow for two dividend increases, and we now expect to hit that long-term debt target during Q4 of this year. As we look out to 2022 and the full five-year plan, the vast majority of the free cash flow will be returned to shareholders. We'll provide more detail on the mix of the return opportunities over the upcoming two to three months, including continued sustainable base dividend increases, special dividends, and share buybacks where appropriate. We see special dividends matching up well to periods of elevated commodity prices and the excess free cash flow generated during those periods. Recall that our annual EP program generates 3% to 5% annual growth, and the only significant facility project of size in the current five-year plan is the Gundy Phase II expansion, and it will actually be done by the end of this year. The balance of the program in the out years is thus very capital efficient and will continue to generate significant free cash flow. The next large facility project is the Conroy North Montney development, which we've matched up to the LNG Canada startup when we expect very strong Western Canadian gas pricing. That time frame is 25-26. Hence, this project's not in the current five-year plan. It could be as large as $800 million per day. It will be a very strong utilization of free cash flow in the 26-27 time frame. We also have an initiative to capture more margin in our liquids business. and are currently evaluating strong return projects to that end and this new business segment. These projects will compete for a portion of the free cash flow in the 24-25 timeframe. A brief marketing update. The average realized natural gas price in Q2 21 was $3.25 per MCF, as we've benefited from rising commodity prices, select hedging, and our broad natural gas market diversification portfolio throughout North America. The accelerated Gundy phase two expansion project is expected to be on stream in January 22 so as to take advantage of potential winter gas price premiums. And we made that acceleration decision a couple of months ago as we were ahead of schedule on the facility pre-bill. The PG&E California market continues to be very strong an average Q2 benchmark price of $4 for MMDTU US and strip pricing at July 23rd, 21 of 548 per million BTUs US for the remainder of 21. NGL price realizations in Q2 21 were up 130% over Q2 2020. We are Canada's largest NGL producer, averaging 55,500 barrels per day during the second quarter. and the NGL pricing outlook continues to improve. Briefly, some comments on the EP program. We drilled 114 net wells in the first half, and we expect to drill approximately 250 net wells for full year 21, completing approximately 220 of these by the end of this year. We are currently operating 12 drilling rigs, and we'll add an additional rig on the former Black Swan lands in September as originally planned. We expect to bring approximately 140 net wells on stream through the balance of this year. Improved drilling time and cost performance for D and C operations has largely offset modest inflationary cost pressures that we are all observing. Drilling times have been materially reduced in all three core complexes through the application of multiple evolving technologies that we continue to trial. Recent horizontals in the LaPree, BC, Montney area are now being drilled to TD in five days. Overall, the second half 21 EP capital program is being executed slightly ahead of schedule. Moving to our environmental performance improvement initiatives, we intend to invest 20 to 40 million per year in these initiatives, primarily in the areas of diesel displacement for EP drilling and completion operations, methane emission reduction and ultimate elimination projects, gas plant emission reduction and associated waste heat recovery installation, and our multiple water management projects. The majority of these environment-related capital investments do indeed generate a modest positive return. We estimate that environmental initiatives to date have reduced our annual emissions by approximately 250,000 tons per year so far a meaningful accomplishment. We have now installed over 200 zero emission electric chemical injection pumps, providing an estimated GHG reduction of 40,000 tons of CO2 equivalent per year. The first hybrid gas tier four frac unit has been delivered and will be pumping on our BC Montney pads in the second half of 2021. Evolving zero methane emission technology is being implemented on all new well sites in all company-operated areas. And finally, the engineering design has been completed for the NGIF Emissions Testing Center. That East Edson facility is expected to be fully operational later on in Q3 of this year. And this center will be evolving the next generation in emission reduction in the field These are all technologies to be put in place during the next two to five years.

We're not waiting for 2050. And that's the end of the formal comments. So, we've got several of us here to answer any questions shareholders might have.

Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star, followed by the 1 on your touchtone phone. You will hear a three-tone prompt acknowledging your request, and your questions will be pulled in the order that they are received. Should you wish to decline from the pulling process, please press the star, followed by the 2. If you have a speakerphone, please lift the handset before pressing any keys.

Your first question comes from

Faye Lee from Oldham Brown.

Hi, it's Faye here. Mike, I'm just wondering about this Gulf Coast LNG pathway. I just want to confirm, are the volumes moving on the TC pipeline Alberta Express AXP project? Is that how the volumes are going to the Gulf Coast?

Well, yes, but there's really four pipeline segments to get it there, all trans-Canada operated, if you go all the way back to the NGTL system.

And the total tolls are 86 cents US.

Right. And is there potential room for expanding those volumes that you've in the future or the kind of what you kind of the agreement you've reached is kind of sort of the maximum?

I think we've taken up all the available space in that pipeline system.

Okay, yeah, that's what I wanted to get. That's what it looked like. Okay, great. And in terms of returning cash to shareholder with the free cash flow, in terms of share buybacks, I'm just wondering, I know you're going to provide more detail there, but do you have any initial thoughts on how you're going to handle a share buyback? Do you have some criteria in mind or how that's going to be handled relative to preference versus, say, special dividends?

Well, it'll be in the mix of, you know, return to shareholder opportunities. We just renewed our NCIB, as you probably saw when we announced the closing of the Black Swan transaction.

Right.

But do you have, like, there's some criteria, say, okay, we'll do a share buyback under these conditions, or are you just going to try and come up with some sort of mix between the two?

Well, we're finalizing what the mix between all the various return opportunities are. I mean, obviously, and our actions have demonstrated that we like sustainable base dividend increases. And in times and periods of significantly more free cash flows and models, we like the special dividend as well.

Okay. All right. Thank you. Your next question comes from Sean McPherson from Industrial Alliance.

Good morning, guys. Quick question. Yeah, we can't hear you very well. Oh, sorry about that. How about now? That's a little better. Okay. Earlier this month, you guys announced a focus on cutting costs with each dollar supposed to add like $190 million in free cash flow. Any idea how many dollars in costs you might be able to cut?

Well, I mean, our goal internally is to initially try and shave a dollar off over the next – or a dollar of improved margin over the next 12 to 18 months.

So we're working away on it, and we've actually made good headway already. Awesome. Thank you.

Your next question comes from Joseph Schlatter from Schlatter Energy Research.

Good morning, Mike. It's Joseph Schachter. Two questions for me. First one on the technology side. We're seeing more comments in the States about intelligent fracking systems. Are you using that in Canada, and are you finding that the well productivity using these new fracking and the DGB technology are capable of doing that, the new unit that's coming on, as you mentioned, in the next short while?

That technology specifically is not something we're trialing right now, but we're always evolving and improving our frac technology and performance and simultaneously trying to deliver better well performance for less dollars. So it's never complete. It's always improving.

Okay, so real-time fracturing is not really something that's really shown up that much yet in terms of showing improvement in well performance.

Yeah, that specific technology we're not using, but, I mean, we are certainly using real-time technology, you know, as we stimulate these wells.

Okay, super. Second question for me on the M&A side. is there much more available in your two core areas that you're looking at, or do you have really the footprint you want? And the additional part then is, are you looking to build a third core area, and would that be, again, in natural gas and MGLs, or would you be looking at a core area in, let's say, conventional, the oil business?

We've largely, you know, acquired the targets that we wanted in the Alberta Deep Basin and the B.C. Montney, which are our two large gas complexes. You know, it doesn't preclude us from doing small, and I mean small, bolt-on ab-deck transactions within either of those areas, but we have nothing close on that front anyway. We have a third core area, and that's our Peace River High, Chardy Lake, Montney, and it's about 60% oil. 40% gas, and it generates this year about $100 million of free cash flow on a $70 million capital investment. So we really like that area, even though it's significantly smaller than our two large gas complexes. And as far as establishing a fourth core area, we have so much inventory, so many projects, and so much production in the three complexes we have already that You know, we have decades of drilling and EP development to put in place. And so, I think we're very happy with what we have under Kerberlink supervision right now.

Super. Congratulations again on a great quarter. Thank you. Yeah. Thanks, Joseph.

Your next question comes from Dan Lloyd from Forge First. Morning, guys. Hi.

Just curious if you can give some color or maybe determining perspective on the BC government Blueberry River First Nation judgment and then kind of a follow-up, I guess, if you could maybe speak to ideally the strength of your relationship with the Blueberry River First Nation.

We've been, you know, working in that North Montney area in and around the BRFN. for over five years and I think we've established a good working relationship and we continue at our full operational pace in that sub-area within our overall B.C. Montney complex. And then all I would say on the government was that I believe they chose not to appeal the B.C. Supreme Court decision and I think that

ruling came out yesterday. Right. Saw that.

Okay.

As a reminder, should you have a question, please press star followed by one. There are no further questions at this time. Please proceed. Thanks, everyone, for dialing in. We'll talk to you next quarter.

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