Ladies and gentlemen, thank you for standing by, and welcome to the Tourmaline Q2 2020 Results conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press star one on your telephone. If you require any further assistance, please press star zero. I would now like to hand the conference over to your speakers today. Jamie Heard, you may begin.
Thank you, Operator, and welcome everyone to our discussion of Tourmaline's results with a three-month end date of June 30th, 2020. My name is Jamie Heard, and I am 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.
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 CAD 225 million on EP capital spending of CAD 95.6 million. So we delivered strong free cash flow of CAD 121.3 million, or CAD 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 CAD 3.06 per 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. 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 295,000-300,000 BOEs a day is currently anticipated. These estimates do include the impact of significant scheduled maintenance on both TransCanada and Enbridge systems and our corresponding plant turnarounds that we timed for those outages. We'll also continue in July with storage injections in California. 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 2021 production estimates, as outlined in our five-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.
Our ongoing 2020 M&A business and our ongoing robust second half 2020 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 CAD 225.2 million, which was essentially flat to Q2 2019 of CAD 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 CAD 509 million or CAD 1.88 per diluted share. We're now expecting, on strip pricing, full year cash flow of CAD 1.05 billion, and we're maintaining our CAD 800 million maintenance capital budget. Q2 earnings were CAD 20.1 million, and that does underscore the low-cost, profitable nature of our EP businesses across all three complexes. And as mentioned, Q2 OpEx was a highlight, down 12% year over year at CAD 3.06 a BOE.
Briefly on our capital programs, first half EP capital spending this year was basically right on the full year maintenance capital budget of CAD 800 million, so we spent CAD 401.8 million, so as mentioned, exactly half. Q2 EP spending was CAD 95.6 million, and that was significantly lower than our cash flow of CAD 225 million, yielding a very strong free cash flow generation, and that free cash flow was utilized to fully fund a 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 30th, CAD 1.69 billion, that's down CAD 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 five-year plan, net debt to cash flow trends down to less than 1x by exit 2021. We plan to maintain our leverage in that range one 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 CAD 24.5 million, including the assumption of their net debt. That added production of 3,500 BOEs per day. We also acquired 2P book reserves of 35.6 million BOEs. We have subsequently reduced Chinook's processing cost 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 seven months of 2020 for a total cash consideration of CAD 38.3 million. These acquisitions added an aggregate 3,200 BOEs per day of production, 32 million BOEs of 2P reserves, 67 sections of land, a gas plant interest, and a very extensive Tier 1 drilling inventory. These high net back assets are all in close proximity to our existing infrastructure, and they will be accreted on a consolidated free cash flow basis in 2021 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.
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 2020 gas production of one and a half BCF per day, and we have 530 million per day transported and sold at six NYMEX price 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, and 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 CAD 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.
As mentioned, we expect 42 new wells will be brought on stream in Q3 and a further 57 wells during the fourth quarter. 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 and complete cost by between 5% and 10% over the past 12 months, and those highlights include continuously improving frac designs, our water management initiatives in business, our monobore drilling efforts, and a broader application of rotary steerable technology in all three core complexes.
We are pleased to report that the company received CAD 3.2 million in funding from ERA, which is Emissions Reduction Alberta, in support of our expanding diesel replacement initiatives through our new technology development, and again, that's across all three core operating 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 five 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.
We believe that Canada produces the next cleanest methane molecule in the world, and the Canadian natural gas sector is only going to get better going forward. 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.
As a reminder, to ask a question, you will need to press star one on your telephone. To withdraw your question, press the pound or hash key. Please stand by while we compile a Q and A roster. And our first question comes from the line of Patrick O'Rourke from ATB Capital . Your line is open.
Hey, good morning, guys. 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?
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've brought our drill complete cost down by a full 50%. They're not going down another 50%, but we always have between eight and 10 new technology avenues that we're pursuing on the capital cost side to further reduce costs. And we have 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 if perhaps over the next two years, we can find another, say, 10% on a CAD ±1 billion per annum D&C budget, that's a significant amount of capital reduction that in part is 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 five-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.
I think we'd all like that. Just a quick follow-up question, and you guys touched on the balance sheet there, the target range between 1x and 1.5x . I thought that the new five-year plan slide that's in the deck is excellent, but that would bring it 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 three, is there one where there's a preference for allocating capital?
I'd say debt reduction and finding the right time to do dividend increases would be the top two 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 five-year plan intact. But clearly, if you get to that position five 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?
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 processing program and move our growth rate up a little bit as well, just organically. But we have to see strong tenor and sustainable improvement in the gas prices before we consider that.
Okay. Perfect. Thanks a lot.
Thank you.
Our next question comes from Lorenas Healy from Odlum Brown. Your line is open.
Okay. It's five here. Just regarding the 2020 CapEx budget, the maintenance budget of CAD 800 million, should we consider that being fairly firm for the remainder of the year?
It is at this point, yeah. I think we've been pretty good at having good cost discipline. We spent, what, CAD 402 million in the first half. We're in a bit of a not completely unique, but a lot of our EP brethren don't have as much capital to spend in the second half of this year. 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. It really sets us up nicely in 2021. I mean, if gas prices, if there's a remarkable improvement in gas prices, as Brian mentioned, we can look at the 2021 and 2022 budget and what we should do with that.
Okay. So that'll be in the upcoming years rather than this year if you see that improvement.
Yeah. We've got the program pretty much outlined right now.
Okay. And can you talk a little bit about the market for acquisition in this current environment, how you see it and the willingness of parties to divest in this market?
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 to 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, which 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.
Okay, and I mentioned the five-year plan that the AECO price assumption kind of comes off a bit in the out years. I'm just wondering what the thinking around that.
Oh, sorry. What comes off? Oh, the AECO price.
No, 2020. In 2021, it continues to continue going in. You're right. In 2022, it backwardated a bit. That's just the strip itself goes by, so we're not interpolating our own assessment of what we think gas fundamentals are. We're just plucking the strip out and laying it in there. That's all that is, and you see a similar pattern in the NYMEX structure as well, I think.
Okay. All right. Got it, and just the last question. COVID-19, in terms of the, didn'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 will impact COVID-19 has had on the operating cost structure?
I'd say it's had none on the actual cost side. We've got our full staff contingent back in the office and started bringing them back in a safe and methodical way. Started that over six weeks ago. Our field operations continued during Q2, and then our drilling completions and facilities work. Thus far, we've had no positive test of anybody that's working in the field. So far, so good on that front.
Okay. Sounds good. Great. Thanks.
Great. Bye. Thanks.
Again, if you'd like to ask a question, that's star one on your telephone keypad. Our next question comes from the line of Jordan McNiven from Tudor, Pickering Holdings . Your line is open.
Hey, guys. I've got a couple of questions for you here, which may actually tie together. The first one, just on the five-year plan, relatively low growth on a percentage basis, but as the largest gas producer, reasonably significant volumes overall. When you look at that, what are your thoughts on kind of growing the basin as a whole? 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?
Sure. The five-year plan is really the organic growth piece. And so it's 4%-5% per annum, and a lot of it's actually on the liquid 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.
Got it. Okay. Thanks. And then maybe this is related, but on the LNG side, and that being probably the larger growth market from a longer-term perspective, when you look at potential opportunities there and 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 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.
We're certainly looking at all of those opportunities, and it is a logical extension to our really seven-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?
I think that's good. I mean, we see other ways of just getting if it's just that deal that's 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 piece that you mentioned on liquefying the hydrocarbons. So it's kind of a hybrid, I think.
Yeah. More to follow.
Okay. That's it for me. Thanks, guys.
Yeah. You bet. Thanks, Brian.
Our next question comes from the line of Jim Miller, private investor. Your line is open.
Hello. Thanks for taking this call. I was just going through the five-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?
Yes. The facilities dollars are included for every year in the five-year plan. That is every dollar of capital that a company will expend. So it's drill complete, facilities, pipelines, everything is in there, including capitalized G&A in that five-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 three 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%-15% range. So it's in there. So every dollar we spend is captured in that plan.
Okay. Because I thought those were fairly expensive plans, the deep cut, the large deep cut plans. Are those?
Yeah, it is. It's CAD 150 million Gundy phase II, and it's incorporated in the plan, and the dollars are in 2021 and 2022, so CAD 150 million in aggregate, and we'll pay some of it in 2021 and the balance in 2022, and it's the only significant facility project in the whole five-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%-5% per annum range.
Great. Great. Thank you very much.
Yeah. Thanks, guys.
It clarifies everything. Thank you.
Thank you.
We have no further questions in queue. I'll turn back to the presenters for closing remarks.
Thank you very much for joining us on this call today, and have a good rest of your day.
Yeah. T`hanks, everybody.
Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.