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Good morning, and welcome to the Pipestone Energy Corp. Q2 2021 Financials and Operations Update Conference Call. [Operator Instructions] As a reminder, this call may be recorded. I would now like to introduce your host for today's conference, Dan van Kessel, Vice President of Corporate Development. You may begin.
Thanks. Good morning, everyone, and thank you very much for joining the call. With me, I have Paul Wanklyn, President and Chief Executive Officer; Dustin Hoffman, Chief Operating Officer; and Craig Nieboer, Chief Financial Officer. On today's call, Paul will start by providing an overview of Pipestone's strategic objectives. Craig will follow with an overview of our Q2 2021 financial results, and Dustin will provide an update on our production and development operations. I will provide an update on our risk management activities. I will now hand the call over to Craig Nieboer, Chief Financial Officer for Pipestone Energy to provide the disclaimer and some comments relating to upcoming financial disclosure.
Thanks, Dan. Listeners should be advised that some of our remarks today will contain forward-looking statements within the meaning of applicable security laws. I refer you to our advisories regarding full statements, non-GAAP financial measures and capital management measures in today's press release and in our Q2 2021 MD&A. All dollar amounts referenced in our remarks today are Canadian dollars unless otherwise specified. With that, I would like to hand it over to Paul Wanklyn, President and Chief Executive Officer, who will provide an update on Pipestone's strategic progress.
Thanks, Craig, and good morning, everyone. There are a few critical messages I'm pleased to relate to you to this quarter. Firstly, the organic growth plan remains on track as evidenced by a third consecutive quarterly production record. We are well on track to deliver our ambitious 2021 full year production guidance of 24,000 to 26,000 BOEs per day. With August month-to-date production estimated at approximately 27,000 BOEs per day. Peer-leading capital efficiencies, coupled with strong commodity prices support excellent full-cycle development economics. Our 2021 capital spending guidance has been increased by $10 million to between $170 million and $175 million, primarily as a result of faster or more efficient drilling than forecast. This has allowed us to accelerate a 3-well completion originally planned in early 2022 to Q4 2021. Secondly, Pipestone expects to reach an inflection point during the fourth quarter of this year, where we forecast material free cash flow generation to begin. The company's priority is to utilize free cash flow to deleverage the balance sheet through debt repayment with a target of less than 0.5x trailing debt to cash flow prior to the end of 2022. We also recognize that the current share price is at a significant discount to its intrinsic value. As a result, and concurrent with the debt repayment strategy, exon expects to implement a normal course issuer bid beginning in Q4 2021. In addition, the Board and management will deliver on all methods to deliver future returns to shareholders, including share buybacks, potential future dividends, asset expansion or acquisitions, with a strong balance sheet and asset base, combinations of these strategies are all possible. Lastly, I want to highlight our measured strategy to delineate a substantial unbooked area of Pipestone's Eastern asset base. During Q3 2021, the company brought on 6 wells from its 15-25 pad, including 2 wells that extend Southeastern area, but we expect to be very compensate rich. Additionally, we've recently finished drilling 3 wells into 2 Montney benches in the southeast direction from our 14-4 pad, which will be completed later this quarter and brought on stream by Q4 this year. Further east, we expect to drill another 3 wells southeast of the 9-14 pad during the first half of 2022. This delineating project or program is expected to substantially derisk another 45 sections of land, which would potentially double the acreage that can be booked for proved plus probable reserves. In summary, Pipestone remains focused on delivering a combination of production and cash flow growth, free cash flow generation and net asset value appreciation to drive the most important element, which is total shareholder returns. With that, I'll pass it over to Craig to discuss the financial highlights for the quarter.
Thanks, Paul. During the second quarter, the company generated record quarterly revenue of $82.3 million and record adjusted funds flow from operations of $35.5 million. These impressive revenue and adjusted fund flow results were driven by a record average quarterly production of 23,336 BOE a day, comprised of 32% oil and condensate, 14% other NGLs and 54% natural gas. The record production was achieved despite processing curtailments due to high ambient temperatures experienced in Alberta during late June. This represents an 8% increase over Q1 2021 and a 39% increase over Q2 2020. .Alongside the increase in production, the company achieved a record quarterly operating netback of $19.60 per BOE, an increase of 12% over Q1 2021 and an 88% increase over Q2 2020. The company continues its 2021 capital program with 8 wells drilled and rig-released and 6 wells completed during the second quarter of 2021. Total capital expenditures, including capitalized G&A, were $47.6 million during the 3 months ended June 30. From a returns perspective, the company generated strong returns on invested capital with Q2 2021 annualized ind being 14.1% and 18.9%, respectively as compared to Q2 2020 annualized ROCE and growth numbers of negative 0.5% and 8.6%, respectively. I'll now hand it over to Dustin to provide a production and capital program update.
Thanks, Craig. Our team is continuing to deliver an efficient and safe development program. At the end of June 2021, Pipestone issued its inaugural ESG report highlighting the company as a peer leading producer with respect to emissions intensity and community engagement. We have set a course to be a net 0 producer by 2035 on Scope 1 and 2 emissions, responsible development of our Montney assets and we're expecting the environment in which we operate are top priorities for Pipestone. From a production standpoint, during July 2021, a planned 10-day outage at the third-party Wapiti gas processing facility was successfully completed. And as Paul mentioned, month-to-date August 2021 production has averaged 27,000 BOE per day, including all 6 wells from the 15-25 pad now on stream to keeping us well on track to achieve our 2021 annual production guidance. In addition to the 15-25 pad, the company expects to bring 9 additional wells on production after August 2021, which includes 6 wells from the 6-24 pad and 3 wells from the 14-4 pad. Subsequent to the second quarter, [indiscernible] completed the 6 wells on the 6-24 pad, which are currently being equipped and will be available for production by the end of this quarter. All 3 Southeast wells on the 14-4 pad, which includes 1 lower Montney well have been rig released with completion scheduled for Q3 this year. The drilling rig will be moving back to the 6-13 pad next where 3 additional wells will be drilled. On the infrastructure front, all necessary regulatory permits required for the new 12-inch gathering pipeline from Pipestone 6-30 pad to Veresen Midstream 16 to 28 battery and compressor station are in place and construction commenced in early August. Additionally, installation of the production handling and water disposal facilities on the Pipestone 6-30 pad are nearing completion. Everything remains on track for a Q4 2021 start-up. As previously disclosed, these facilities will add an additional $25 million of firm and 25 million cubic feet per day of interruptible gas and liquids processing capacity for Pipestone. Well performance continues to meet [indiscernible] expectations. The 3 new wells on the condensate rich 6-13 pad, including on Lower Montney well achieved an average per well IP60 of 536 barrels per day wellhead condensate and 2.8 million cubic feet per day of raw gas, which equates to a condensate gas ratio of CGR of 191 barrels per million. The 3 wells on the 8-15 pad has achieved an average IP90 of 662 barrels per day of wellhead condensate and 3.6 million cubic feet logs or CGR 184 barrels per million. The 6 well 3-12 pad has achieved an IP180 of 405 barrels per day of wellhead condensate and 4.3 million cubic feet per day raw gas. Preliminary results from the 15-25 pad are also demonstrating strong deliverability with more details to be provided once longer-term production data is available. With that, I will turn it over to Dan to provide an update on our risk management program.
Thanks, Dustin. To support the company's deleveraging profile, we will target hedging approximately 25% of our net after royalties condensate production for the first half of 2022. With respect to natural gas, given the continued improvement in AECO prices, we are targeting to be approximately 35% hedged on our full year 2022 production forecast. Q1 2020 has strengthened disproportionately. And as a result, post the end of Q2, we have added an incremental 10,000 gigajoules per day at a weighted average price of $4.03 per gigajoule for that time period. I'll now turn it over to Paul to conclude the call.
Thanks, Dan. Well, in summary, our team is extremely pleased with the progress we've made toward generating return for shareholders. And coupled with our strong ESG strategy, Pipestone will continue to be an attractive investment for shareholders. And with that, I think we'll turn it over to the operator for Q&A.
[Operator Instructions] And your first question comes from the line of Josef Schachter with Schachter Energy.
Congratulations on the progress you've made so far this year in 27,000 where you are now. I have 2 questions. One, given the comments from the service industry about manpower shortages, are you seeing any delays in terms of getting frac crews in or activity that you need in the field? And then part of that also would be are you seeing much price increases across the service sector for the services you need?
Thanks for your question. No, we have not seen any delays. We've actually been -- we've been very fortunate to have met all the schedules we've set out so far. In terms of increase in pricing, I think we mentioned before, we've locked in some of our major suppliers in terms of pipe and sand for a good part of the next year or 12 months out. So we feel like we're in pretty good shape there. Maybe I'll hand it over to Dustin to maybe give you some further color on other services that might be affecting our future operation.
Yes. Thanks, Paul. Yes. Paul's bang on some of the key comp next year. So that will limit any inflationary pressure we're seeing. The other thing we've been able to do, Josef, is utilize multiple service companies. We've developed our process at Pipestone with our large pads is pretty well defined. And logistically, we can plug in different service companies as needed and we've demonstrated that over the course of this year already, and we've been able to maintain the efficiencies that we've laid down. So I think it takes some of the risk off the table for us for sure. And I still think we've got efficiencies to be added to the current plan. We've driven our costs down materially, but we still feel that there's more efficiencies that we're going to be able to implement that will offset any service pressures.
Okay. And the second question, Paul, with the comments we're hearing about LNG Canada being delayed, does that impact your long-term growth objectives of 3, 4 years out?
No, not at all. We don't believe that's a factor. The only impact is on potential future pricing at AECO and the impacts that backing up more gas into the basin has, but that's we're still forecasting long term in terms of our plan of about 250 at GJ AECO and of course, we're well above that price today. So doesn't affect our plan at all.
Yes. Yes, this is Craig, CFO. Just to also highlight for investors. The bulk of our economics is driven by our condensate production and condensate is used to blend with heavy oil sands product as a diluent. So really, it's the oil sands market is going to be more of a driver of demand for our key component of our production base. And at this stage, we see oil sands picking up over the next few years and particularly with new egress coming on. So we think the condensate market will continue to be very robust. Condensate trades as a reminder too, to listeners at or right now slightly again above of WTI price. So it's a very, very positive environment for the key component of our production mix.
Your next question comes from the line of Garrett Ursu with Cormark Securities.
Sorry, having some telephone troubles there. I guess I got dropped off earlier when I tried to ask a question. So hopefully, I'm not asking anything that you guys haven't answered. But 2 questions for me. You brought 3 completions forward into Q4. First of all, just curious if it was tough to get a spread to do those completions? And then second, is there a bit of a risk of those completions into more of a tighter market this winter compared to 2022? Or do you see costs going up in 2022? Or was it just kind of the economics are so compelling that it made sense to bring forward like that?
That's a great question there. The way we look at it is pulling these 3 wells, which we're currently originally scheduled for January into Q4 is actually going to improve our ability to to secure services, and we're anticipating Q1 to be fairly tight in the frac services space. So we see this as a win. I think you're going to see a more capital efficient pad be completed in Q4 than it would have been in January. And obviously, we had a benefit having that production on earlier. So as it stands right now, we feel very confident that we're going to be able to get that pad completed and wouldn't have an issue with frac spread or any data services in Q4 right now.
Okay. And that was kind of the same completions company that you would use in Q1? Or did you find another spread? Or do you still have that opening in Q1 as well?
Yes. We've yet to commit to any 1 frac service provider. I think as Paul talked to earlier, from a sand and steel perspective, we have secured product through most of 2020. But on the frac services side, right now, we kind of left ourselves quarter-to-quarter to look for holes in frac schedules, and it's worked over well for us.
Which just to remind guys, our proximity to Grand Prairie makes that a little easier than for other operators to do because that it's -- we're so close to their basis. And it's easy to get in and out to our locations versus other competitors of ours.
Okay. Also a rumor, I guess there might be some cement shortages kind of on the industrial side? Have you guys heard anything like that? Is that something that may affect oil and gas near term here?
Yes. I mean, everything -- there's no that everything's tightened up, for sure, Garrett. I mean we've some minor wait times on cement crews to show up for our drilling rate, but nothing that I would be material. And again, to Craig's point, us being so close to Grand Prairie is a really big win for us, right? So services are minutes away, which really improves our ability to get people out to our leases.
Okay. And then finally for me for Craig. Obviously, the royalties are really low in Q2 with your gas cost allowance and kind of the growth in the volumes. But kind of given where comas are, what some of your competitors are seeing and just kind of payouts on the wells? I know it's tough, but what are you guys kind of guiding or thinking about for royalties in this kind of environment go forward?
Yes. Garett, this is Dan. I'll chime in here. you're right, we got a fairly large DCET credit in Q2. We royalties eat through '21 and would expect at least through the first half of '22 to be in and around that 5% range. I think what's important to remember these wells are getting extremely quick payouts on the actual capital being spent, whereas as on a long lateral with 2.5 tonne per meter completion, we're getting C-star anywhere between -- on our long wells up to $20 million. So while the wells may be paying out quicker on our $5.6 million to $6 million well cost, we're getting an extended 5% royalty holiday beyond that payout period.
Next question is from the line of Luke Davis with RBC.
So base program has ramped up really nicely here. tons of free cash coming at you in 2022. I know you have a lot of inventory in the base asset suite. And you did mention a potential NCIB. But just wondering if that kind of changes your views or positioning on M&A at all? And maybe you can comment on whether or not it would make sense to look at any incremental assets.
Yes. It's Paul. Thanks, Luke, for the question. It doesn't change your thinking on ultimately how we view M&A. We want to get our balance sheet to the point where we're a bulletproof and able to to really compete maybe for some future assets. But I think all in line thinking that any future opportunity has to compete for capital with the massive opportunity we have at Pipestone. And we're just still scratching the surface in terms of what the total inventory of opportunity is at Pipestone. So it's going to have to be pretty compelling to compete with what we're doing in our own backyard.
Got you. Makes sense. So I guess from a hierarchy sort of standpoint of the debt repayment buybacks and then anything else. Is that fair?
That's right. Maybe I'll just add 1 more comment. We think we've alluded to this in the past that we think the asset base could sustain quite a bit higher ultimate production forecast. We're limiting our 3-year plan to what we've committed to from a midstream capability or capacity point of view. And 1 of the elements as we continue to derisk some of the eastern lands will be to balance off, okay, what is an expanded production forecast in the future look like? And how does that fit into the free cash flow. Obviously, we would -- doing anything in terms of expansion within free cash flow. So in the next 3 quarters or so, we'll be able to I think 0 in on a plan that makes -- that could make some sense in terms of expansion.
[Operator Instructions] There are no other questions at this time.
Okay. Awesome. Thanks very much, everyone.
Ladies and gentlemen, thank you for participating in today's conference. This concludes today's program. You may all disconnect. Everyone, have a great day.