Tourmaline Oil Corp

TSX:TOU

Earnings Call Transcript 2020-Q2

[Operator]

Ladies and gentlemen, thank you for standing by, and welcome to the Tourmaline Q2 2020 Results Conference Call. [Operator Instructions] I would like to hand the conference over to your speaker today, Jamie Heard. You may begin.

[Jamie Heard;Senior Capital Markets Analyst]

Thank you, operator, and welcome, everyone, to our discussion of Tourmaline's results for the 3 months ended June 30, 2020. My name is Jamie Heard, and I'm Tourmaline's Senior Capital Markets Analyst. Before we get started, I refer you to the advisories on forward-looking statements contained in the news release as well as the advisories in the Tourmaline Annual Information Form and our MD&A available on SEDAR and 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 of 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 his remarks, we'll be open for questions. Mike, please go ahead.

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

Thanks, Jamie, and thanks, everybody, who's on the line. So we are pleased to announce a very strong Q2 2020 with significant free cash flow generation. A few of the highlights. Q2 cash flow was $225 million on EP capital spending of $95.6 million. So we delivered strong free cash flow of $121.3 million or $0.45 per diluted share. Q2 production averaged 299,400 BOEs a day, which was pretty much at the top end of the guidance range of between 295,000 and 300,000 BOEs per day, and up 7% over Q2 2019 production. We had strong Q2 2020 cash cost performance, and that was highlighted by our OpEx of $3.06 a BOE, which is down a full 12% from the corresponding quarter in 2019. Starting with the production update. Second quarter volumes of 299,400 BOEs a day do include the impact of the company's natural gas storage injections during the quarter, which reduced quarterly production by approximately 4,000 BOEs a day. And these volumes are planned to be sold during the fourth quarter of this year into a higher gas price environment. A similar Q3 2020 production range of 295,000 to 300,000 BOEs a day is currently anticipated. And these estimates do include the impact of significant scheduled maintenance on both TransCanada and Enbridge systems and our corresponding plant turnarounds that we time to those outages. We'll also continue in July with storage injections in California. And like everyone else, we had a bit of a late start to Q3 field operations as it was extremely wet in BC and Northern Alberta during the first half of July. We expect fourth quarter production to be very strong at between 320,000 and 325,000 BOEs per day as the full quarter production impact of the approximately 42 wells we'll bring on stream during this quarter, Q3, will be realized as well as a further 57 wells, which will be tied in during Q4. And again, those fourth quarter results will also be positively impacted by our storage withdrawals from California and Dawn. So we're now expecting an increased 2020 production exit of between 322,500 BOEs a day and 327,500 BOEs per day. Current '21 production estimates, as outlined in our 5-year plan of approximately 320,000 BOEs per day will be revised in conjunction with the release of our 2021 capital program, and we'll do that with our Q3 results in early November. So our ongoing 2020 M&A business and our ongoing robust second half '20 EP program are currently expected to increase 2021 production and cash flow from the previous outlook. A few financial highlights. As mentioned, second quarter cash flow was $225.2 million, which was essentially flat to Q2 2019 of $226 million, despite, obviously, very challenging oil and liquid prices that we all endured during the second quarter of this year. First half 2020 cash flow, approximately $509 million or $1.88 per diluted share. We're now expecting on strip pricing full year cash flow of $1.05 billion, and we're maintaining our $800 million maintenance capital budget. Q2 earnings were $20.1 million, and that does underscore the low-cost profitable nature of our EP businesses across all 3 complexes. And as mentioned, Q2 OpEx was a highlight, down 12% year-over-year at $3.06 of BOE. Briefly on our capital programs. First half EP capital spending this year was basically right on the full year maintenance capital budget of $800 million. So we spent $401.8 million. So as mentioned, exactly half. Q2 EP spending was $95.6 million, and that was significantly lower than our cash flow of $225 million, yielding a very strong free cash flow generation. And that free cash flow was utilized to fully fund the dividend, to acquire Chinook Energy, to fund Deep Basin acquisitions and to also reduce debt, all during one of the most difficult quarters in the history of our industry. Net debt at June 30, $1.69 billion. That's down $148 million from March 31, 2020, after accounting for the funds received with the Topaz Energy financing, which was completed during the quarter. In the current 5-year plan, net debt to cash flow trends down to less than 1x by exit '21. And we plan to maintain our leverage in that range, 1 to 1.5x. And the excess free cash flow will be allocated towards dividend increases, share buybacks and debt reduction. On the acquisition front, during the second quarter, we did complete the acquisition of Chinook Energy for $24.5 million, including the assumption of their net debt. That added production of 3,500 BOEs per day. And we also acquired 2P booked reserves of 35.6 million BOES. We have subsequently reduced Chinook's processing costs by approximately 45% since that acquisition. And we've fully incorporated Chinook's assets into our long-term BC Montney growth plans. We also completed several small transactions in the Alberta Deep Basin during the first 7 months of 2020 for a total cash consideration of $38.3 million. These acquisitions added an aggregate 3,200 BOEs per day of production, 32 million BOEs of booked 2P reserves, 67 sections of land, a gas plant interest and a very extensive Tier 1 drilling inventory. These high netback assets are all in close proximity to our existing infrastructure, and they will be accretive on a consolidated free cash flow basis in '21 based on current strip pricing. And we plan to continue our Deep Basin consolidation efforts as well as our BC Montney efforts, and we expect further opportunities for Topaz as a result of these in 2021, which will further improve already strong operating and financial metrics for these acquisitions. And of note, our interconnected Deep Basin asset, where we're the largest producer, it is currently Alberta's largest gas field. And our goal is to make it a lot larger. Looking at a couple of marketing updates. We are Canada's largest natural gas producer with forecast total average '20 gas production of 1.5 Bcf per day. And we have 530 million per day transported and sold at 6 NYMEX-priced hubs on firm long-term transportation contracts. Currently, Tourmaline has an average of 351 million per day hedged for the second half of this year at a weighted average fixed price of CAD 2.37 per Mcf. We also have an average of 156 million per day of NYMEX basis done. And we move approximately 400 million per day of incremental volume that's exposed to the export markets. And those include Dawn, Chicago, Ventura, Sumas, Malin and PG&E. Natural gas fundamentals for 2021 are steadily improving. And of note, approximately 75% of Tourmaline's natural gas volumes are sold on the western half of the continent, where the gas supply diminishment is anticipated to be the greatest. And that includes the hubs at PG&E, Malin, Sumas, Station 2, AECO. A bit of a brief EP update. The company remains on track to deliver the best capital efficiencies in our corporate history, and at or near the top on a North American large-cap basis. As mentioned, with the full rig fleet of 10 rigs going now, that's still within our 2020 maintenance capital budget of $800 million. The second half EP program will drill approximately 79 new wells and complete approximately 99 wells, and that includes 24 DUCs that were not completed with the first half 2020 program. And as mentioned, we expect 42 new wells will be brought on stream in Q3 and a further 57 wells during the fourth quarter. And of course, that's going to yield very strong Q4 production, and as mentioned, the increased 2020 production exit. We continue to seek opportunities to improve all aspects of our execution and to continue to reduce costs in all aspects of our business. Ongoing company optimized technology developments have reduced our aggregate drill/complete costs by between 5% and 10% over the past 12 months, and those highlights include continuously improving frac designs, our water management initiatives and business, our monobore drilling efforts and a broader application of rotary steerable technology in all 3 core complexes. We are pleased to report that the company received $3.2 million in funding from ERA, which is Emissions Reduction in Alberta, in support of our expanding diesel replacement initiatives through our new technology development. And again, that's across all 3 core operated complexes. We, as a company, continue to make significant measurable reductions in our emissions. Tourmaline has the lowest net emissions in the Canadian senior category, and we have defined hard reduction targets for net emissions going forward, including methane and also reducing our emission intensity over the next 5 years. The Canadian energy sector invests over half of the funds invested by all sectors of the Canadian economy in environmental performance improvement on an annual basis, and that total is going up. And we believe that Canada produces the net cleanest methane molecule in the world, and the Canadian natural gas sector is only going to get better going forward. And so that's the end of the formal remarks. And Brian and I and Jamie are here to answer any questions that you might have.

[Operator]

[Operator Instructions] And our first question comes from the line of Patrick O'Rourke from ATB Capital.

[Patrick Joseph O'Rourke]

You guys have obviously done a very excellent job on both the capital and operating cost side here. I'm just wondering where we sit sort of in that cycle? And if there is any low-hanging fruit or potential for further improvements? And then maybe conversely -- and I know it feels like we're a long way off from inflation in the sector and specifically oil services. But just wondering if there is to be kind of cost vulnerabilities that emerge, where would the first place that we should be looking for those be?

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

Sure. Thanks, Patrick, for the questions. I mean we continue, as I mentioned, to look at reducing costs throughout the business. I know you're aware that over the last 6.5 years, we brought our drill complete costs down by a full 50%. They're not going down another 50%, but we always have between 8 and 10 new technology avenues that we're pursuing on the capital cost side to further reduce costs. And we've seen it even in the last 12 months, we're down another 10%. I'd say most are small, but then in aggregate, they can turn into something meaningful. So perhaps over the next 2 years, we can find another, say, 10% on a plus or minus $1 billion per annum D&C budget. That's a significant amount of capital reduction that, in part, has translated into free cash flow. I mean operating costs are down. Service costs are down. Those are perhaps more transitory, if you do get into that inflationary environment. But I'd say, fully 80% of the cost reductions we've achieved to date over the last 6.5 years are because of our efforts, and they're not going away. In Brian's 5-year plan, he actually, other than this year, builds in 2.5% inflation into that plan. And so we do acknowledge that inflation may creep back in. And if that's because of higher commodity prices, bring it on.

[Patrick Joseph O'Rourke]

Yes. I think we'd all like that. Just a quick follow-up question. You guys touched on the balance sheet there, the target range between 1 and 1.5x. And I thought that the new 5-year plan slide that's in the deck is excellent, but that would bring you well below that range, talking about potential for dividend increases, share buybacks and then also acquiring resource potentially through acquisition with that free cash flow. Just wondering if -- when you look at those 3, is there one where there's a preference for allocating capital.

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

I'd say debt reduction and finding the time -- the right time to do dividend increases would be the top 2 priorities. The acquisition capital, primarily we've tried to allocate that from our Topaz equity and fund our M&A business that way and then keep the organic growth 5-year plan intact. But clearly, if you get to that position 5 years out where your debt-to-cash flow is 0.5, there is some inherent acquisition capital built into the structure of the company at that point. Brian, anything you want to add to that?

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

No, I think that's good, Mike. The only thing is structurally, commodity prices continue to improve, and we've seen some good tailwinds there. Over time, we might take a bit of that free cash flow and expand our process program and move our growth rate up a little bit as well, just organically. But we have to see strong tenure and sustainable improvement in the gas prices before we consider that.

[Operator]

Our next question comes from the line of Fai Lee from Odlum Brown.

[Fai Lee, Equity Analyst]

It's Fai here. Just regarding the 2020 CapEx budget, the maintenance budget of $800 million, should we consider that as being fairly firm given -- for the remainder of the year?

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

Well, it is at this point. Yes. And I think we've been pretty good at having good cost discipline. We spent, what, $402 million in the first half. So we're in a bit of a, not completely unique, but a lot of our E&P brethren don't have as much capital to spend in the second half of this year. And so we essentially have half of our maintenance capital budget to utilize, which is what is generating the strong production momentum in Q4 through to exit, really sets us up nicely in 2021. So -- and I mean, if gas prices -- there's a remarkable improvement in gas prices, as Brian mentioned, we can look at the '21 and '22 budget and what we should do with that.

[Fai Lee, Equity Analyst]

Okay. So it will be in the upcoming years, rather than this year, as you see that improvement.

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

Yes, we've got the program pretty much all right, right now.

[Fai Lee, Equity Analyst]

Okay. And can you talk a little bit about the market for acquisitions in this current environment? Like how you see it and the willingness of parties to divest in this market?

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

Well, it's more robust than it's been in the past, and it's less expensive than it's been in the past from a generality standpoint. I mean I think you see the transactions that we've closed on. It's 10,000 flowing BOE or less and you're buying 2P reserves for -- well, I mean you're buying PDP reserves for less than their value. So I mean, that's partly why we created Topaz in the first place in the fourth quarter last year, was we saw what we recognized as a generational opportunity to perhaps participate in that business. But I would point out that we transact on well less than 10% of what we evaluate. And so it's not necessarily always easy to get deals done.

[Fai Lee, Equity Analyst]

Okay. And I noticed in the 5-year plan that the AECO price assumption kind of comes off a bit in the out years. I'm just wondering about the thinking around that.

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

Well, sorry, is that what comes off? AECO...

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

The AECO.

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

Oh, the AECO. Brian?

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

2020 and -- in 2021, it continues to contango. And then you're right, in 2022, it backwarded a bit. That's just the strip itself, so Fai. So we're not interpolating our own assessment of what we think as fundamentals are. We're just plucking the strip out and laying it in there. That's all that is. And you'll see a similar pattern in the NYMEX structure as well, I think.

[Fai Lee, Equity Analyst]

Okay. All right. Got it. And just the last question. COVID-19 in terms of the -- it doesn't seem to have much of an impact on your cost structure. Do you see that kind of being the case going forward? Or just how that -- what impact COVID-19 has had on the operating cost structure?

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

Well, I'd say it's had none on the actual cost side. We've got our full staff contingent back in the office. We started bringing them back in a safe and methodical way, started that over 6 weeks ago. Our field operations continued during Q2. And in our drilling completions and facilities work thus far, we've had no positive test of anybody that's working in the field. So, so far, so good on that front.

[Operator]

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

[Jordan McNiven]

I've got a couple of questions for you here, which may actually tie together. The first one, just on the 5-year plan, relatively low growth on a percent basis. But as the largest gas producer, reasonably significant volumes overall. When you look at that, like what are your thoughts on kind of growing the basin as a whole? Like do you see your growth mostly backfilling other declines? Do you see it generating absolute growth? And just kind of what are your thoughts on growth within the basin in a broader macro perspective?

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

Sure. The 5-year plan is really the organic growth piece. And so it's 4% to 5% per annum. And a lot of it's actually on the liquids side. And so we have decreased our growth rate over time, mostly because the commodity price wasn't rewarding it. We're quite constructive on the supply-demand rebalancing that's been occurring in the Western Canadian Sedimentary Basin, and that suggests that it's probably a bit further along than it is south of the border simply because we've had lower prices for longer. And so we do not want to grow basin supply in any significant way right now because we want that supply-demand rebalancing to continue and hopefully translates through to strong impact on pricing and gets rid of that backwardation that Brian was just alluding to. So the first part of your question is really our approach, keep basin supply, plus or minus the same and grow our proportion of that supply through our M&A activities.

[Jordan McNiven]

Got it. Okay. And then maybe this is related, but on the LNG side, that being probably the larger growth market from a longer-term perspective. When you look at potential opportunities there, when you think about the different mechanisms through which you could get involved, I'm just curious what your thoughts would be on something like what EOG and Apache you have done where they take on a long-term liquefaction commitment but have exposure to the global prices or other producers, which have gone more of just a strict supply agreement and, therefore, don't have the liquefaction liability on the balance sheet, but also don't have the global pricing exposure. Just curious as to how you guys think about that. And what might be the ideal structure for you guys balancing the pricing upside versus the liability on a long-term commitment?

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

Well, we're certainly looking at all of those opportunities, and it is a logical extension to our really 7-year gas marketing and transportation diversification plan. I'd say we prefer supply deals over the full exposure to the liquefaction at this point. But we're going to continue to pursue that over the next couple of years and, hopefully, something comes to fruition in that time frame. Brian, anything?

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

I think that's good. I mean we see other ways of just getting -- if it's just that deal indexed to AECO or to NYMEX, we're able to do that already. So we're looking for a method where we can get a little bit of exposure to the Asian market without having to make a full commitment to the equity pieces you mentioned on liquefying the hydrocarbon. So it's kind of a hybrid, I think.

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

More to follow.

[Operator]

Our next question comes from the line of [ Jim Miller ], private investor.

[Unknown Attendee]

I was just going through the 5-year plan, and it doesn't look like there are any facilities in the plan but I know that you have talked about some deep cut, either expanding at Gundy or at the new properties that you acquired. Could you talk some about how the facilities will fit in with this plan?

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

Yes. The facilities dollars are included for every year in the 5-year plan. That is every dollar of capital that a company will spend. So it's drill/complete, facilities, pipeline, everything is in there, including capitalized G&A in that 5-year plan. So it's in there. Over time, the proportion of the annual capital budget that's been dedicated to facilities and pipelines has dropped as we have largely completed the construction of our infrastructure skeleton across all 3 core areas. So we're sort of down. Historically, we'd run north of 30% of the annual CapEx was infrastructure-related. And now we're sort of down in that 10% to 15% range. So it's in there. So every dollar we spend is captured in that point.

[Unknown Attendee]

Okay. Because I thought those were fairly extensive plans, the deep cut, the large deep-cut plans. Are those...

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

Yes, it is. It's $150 million Gundy phase 2, and it's incorporated in the plan, and the dollars are in 2021 and 2022. So $150 million in aggregate, and we'll pay some of it in '21 and the balance in 2022. And it's the only significant facility project in the whole 5-year plan. But we will point out that there are a number of very viable projects that aren't in the plan simply because we're moderating our growth and keeping it in that sort of 4% to 5% per annum range.

[Operator]

We have no further questions in queue. I'll turn back to the presenters for closing remarks.

[Jamie Heard;Senior Capital Markets Analyst]

Thank you very much for joining us on this call today, and have a good rest of your day.

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

Yes. Thanks, everybody.

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

Thank you.

[Operator]

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.