Pipestone Energy Corp

TSX:PIPE

Earnings Call Transcript 2019-Q3

[Operator]

Good morning, and welcome to the Pipestone Energy Corp. Third Quarter 2019 Results 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, Corporate Development. You may begin.

[Dan van Kessel, Vice President of Corporate Development]

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 a summary of our recent operational developments, including an update on our 2019 development program and initial production results. Craig will follow with an overview of our Q3 2019 financial results, Dustin will provide an overview of our current operations, and I will provide an update on our risk management program. 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.

[Craig Frederick Nieboer, Chief Financial Officer]

Thanks, Dan. Listeners should be advised that some of our remarks today will contain forward-looking statements within the meaning of applicable securities laws. I refer you to our advisories regarding forward-looking statements, non-GAAP financial measures and capital management measures and risk factors in today's press release and in our Q3 2019 MD&A that's been filed on SEDAR. All dollar amounts referenced in our remarks today are Canadian dollars unless otherwise specified. With that, I would like to pass it over to Paul Wanklyn, President and Chief Executive Officer, who'll provide a summary of our recent operational developments.

[Paul Wanklyn, President, CEO & Director]

Thanks, Craig. Good morning, everyone. I'm very pleased to provide an update on Pipestone Energy's development activities. Earlier this morning, we press released our Q3 2019 financial results and provided a status update on our 2019 capital program and operations, including initial production results. I'm extremely pleased to report that Pipestone Energy started production operations north of the Wapiti River into the new Keyera compression facility and Tidewater plants in September, earlier than originally forecast. We remain on track with our ambitious development program to deliver a tenfold production increase in 2019, and I'm reaffirming our exit guidance of 14,000 to 16,000 BOEs per day. During the month of October, we estimate our sales production averaged approximately 11,400 BOEs per day, about half of which came from condensate and NGLs. This was produced despite normal third-party start-up challenges, causing intermittent run-times at both facilities and restricted production. While only 14 wells out of the total 21 tied in have produced for more than 30 days since commissioning, the producing wells are performing at our type-curve expectations. On the operations front, our team's done an exceptional job in stewarding capital throughout the year. Completion operations at our recent 9-14 pad achieved pacesetter performance at an average cost of $4 million per well. On the infrastructure front, Pipestone infrastructure projects were completed at lower-than-budgeted cost, which, with the realized DCET cost efficiencies, has afforded Pipestone the opportunity to accelerate the completion of 6 wells on the 6-24 pad for approximately $20 million in total 2019 spend from Q1 2020 accelerated into Q4 2019, while remaining within our capital guidance ceiling of $155 million. Pipestone Energy is currently drilling 6 wells in the 6-24 pad with the final well expected to finish drilling in late November. Drilling operations are going extremely well, and following the 6-24 pad, the rig will move to the 6-30 pad to commence drilling 6 new wells, 2 of which should be rig released prior to year-end. Craig's going to provide now an overview of our Q3 financials.

[Craig Frederick Nieboer, Chief Financial Officer]

Thanks, Paul, and I believe as listeners are aware, Pipestone Energy is in initial stages of executing a multiyear development strategy. And as such, our Q3 financial results reflect extensive capital spend ahead of our production that we are wrapping into this fall. As a reminder to listeners, to fund the 2019 capital program, Pipestone Energy secured $198.5 million first lien credit facility with the syndicate of lenders comprised of a $10 million revolving operating line, a $20 million letter of credit facility and a $168.5 million delayed draw term loan. Highlights of the Q3 capital spend, which much Paul has touched on already. Pipestone Energy successfully completed 3 wells at our 9-14 pad site for an average estimated final cost of $4 million per well. 2 wells were drilled and rig released on our 6-24 pad in September, and the above spend was all incurred at or below budget. And including other miscellaneous capital items, our Q3 total capital spend was $29.4 million, which was in line with our expectations. As noted above, initial production began north of the Wapiti River in mid-September as tie-ins at both the Tidewater Pipestone plant and the Keyera Wapiti plant were completed. This allowed Pipestone to initiate production from wells located at the 15-14 and the 0 -- and the 3-1 pad sites. The start-up time was approximately 1 month ahead of the originally planned schedule. However, as noted above, production was impacted by normal third-party start-up challenges, causing intermittent run-times in both facilities. The resulting sales revenue net of royalties in Q3 2019 was $7.39 million, which is in no way reflective of our future expected revenue profile as we ramp production in the fourth quarter. Expenses for the quarter were $11.64 million, including G&A of $2.19 million. As noted by Paul, the 2019 capital program is tracking ahead of schedule and below budget for 2019, and our balance sheet is strong with $47.9 million of cash at September 30, 2019, and a net draw on our $198.5 million first lien facilities of only $160.7 million, leaving Pipestone plenty of liquidity to complete the remaining spend of our 2019 capital program guidance of up to $155 million. I'll now hand it over to Dustin to review the quarter's operations.

[Dustin Hoffman, Chief Operating Officer]

Thanks, Craig. As Paul mentioned, we're nearing the end of a 6-well drilling campaign on the 6-24 pad where continued refinement of our manufacturing approach to drilling has continued to improve drilling times and costs. We recently achieved a new corporate pacesetter result on this pad with a spud to rig release time of approximately 13 days and a cost of $1.85 million. Once the final well is finished drilling on this pad, the rig will be moved to our 6-30 pad to drill another 6 wells. We expect fracking operations to begin in the first week of December on the 6-24 pad, utilizing a similar limited entry frac design to the recently completed 9-14 pad. From a reservoir management perspective, we believe that a limited-entry approach to completions can reduce well costs, which we've already demonstrated, and potentially mitigate future parent-child issues through better frac containment. These 6 wells will be equipped and tied in during Q1 2020 and are expected to be on stream in Q2. Pipeline construction is underway to tie-in the recently completed 9-14 pad, with the 3 wells scheduled for in-line testing in Q1 2020. Dan will now go through an update on our risk management program.

[Dan van Kessel, Vice President of Corporate Development]

Thanks, Dustin. During and subsequent to the third quarter, the company took advantage of recent increases in future Canadian natural gas pricing at AECO to layer on a meaningful hedge position for Q4 2019 and for the full calendar year 2020, weighted towards the typically volatile summer months. Pipestone Energy has 35,000 gigajoules per day hedged at a weighted average swap price of $1.60 per GJ for next summer, which compares favorably to April -- compares favorably to the period of April to September 2019, where AECO only averaged $1.14 per GJ. These gas hedges, coupled with approximately 3,300 barrels per day of oil hedge for 2020 at about CAD 79 per barrel, are expected to reduce cash flow volatility and support the company's development objectives for 2020. I'll pass it back over to Paul for closing remarks before we begin the question and answers.

[Paul Wanklyn, President, CEO & Director]

To sum up, I think we're on track to either meet or exceed all the expectations laid out to investors since the formation of Pipestone Energy Corp. as we approach the end of 2019. We've continued to add key members to our team this last -- over the course of the fall, and our team has done an excellent job in achieving our key development milestones in 2019. Our initial production comes from 3 pad sites approximately 10 kilometers apart, giving us high confidence in the quality of the resource base across our core area. All aspects of the business plan remain on track to meet or exceed expectations, including the generation of full cycle returns on capital in the next 12 months. And that's all we had on our end and over to the operator for questions.

[Operator]

[Operator Instructions] And our first question comes from Luke Davis with RBC.

[Luke Davis, Analyst]

Just wondering if you can provide some detail on initial well results relative to type curve. Just looking at offset industry data, it looks like you can generally get to an IP30 of about 4 million a day declining naturally fairly quickly versus your presentation, which suggests your wells are [ shelfing ] about 4 million a day for the better part of the year. Can you just reconcile that difference and provide some detail on what you've seen to date? And then as a follow-up to that, can you just walk through the differences in initial CGRs that you've seen on each pad kind of drivers behind that? And then where do you see them going?

[Dustin Hoffman, Chief Operating Officer]

Sure. It's Dustin. I'll take that one. So I think we published our type-curve results in our corporate deck. We typically do constrain our wells early time to that 4.5 million/day mark. And that's just to optimize facility design and not overcapitalize on facilities. The -- definitely early time days for us, but our wells are tracking our type-curve expectations. And you're correct, we do anchor our type curves off a lot of offset data, which also supports our type curve. The variability in CGRs, I think, which was in our press release where we talked as 152 barrel a million average from the 3-1 pad, the 82 barrels a million from the 15-14 pad and the 237 barrel per million CGR from the 6-24 pad, it fits our mapping very well and is well within the expectations that we had prior to start-up.

[Dan van Kessel, Vice President of Corporate Development]

Yes, that's perfect. And what I'd allude to you as well, Luke, is I'd point you to Page 11 on the new presentation we just uploaded to our website. I think if you take a look at the updated offsets relative to just one of our example type curves that represents the most of the acreage that we've got here at Pipestone, you can see how well fitted our type curve is to what the offset results have.

[Operator]

And our next question comes from Tyler Maguire with Peters & Co.

[Tyler James Maguire, Principal and Oil & Gas Analyst]

I just had a follow-up to the previous question. I was wondering if you could comment on what you're seeing in initial rates between zones. If there's anything above expectations, below expectations or anything that you're seeing amongst the zones that you've been drilling.

[Dustin Hoffman, Chief Operating Officer]

Sure, I can take that one again. It is early days, for sure, and some of the early run-time challenges. We're still trying to differentiate some of our early pilots and kind of the bench performance. But what I can say is the early days on the 3-1 pad. We're seeing pretty comparable performance between the 2 primary benches that we've got under development today.

[Paul Wanklyn, President, CEO & Director]

Maybe I'll just add one little comment to that, Tyler. It's Paul here. On the 15-14 pad, I think it's fair to say both zones are equally robust in terms of flow characteristics. However, the lower zone, the C zone in that pad are typically dryer, and we got a hint of that when we first tested those wells in the last year, but they've proven to be slightly dryer, just in the C.

[Tyler James Maguire, Principal and Oil & Gas Analyst]

Okay. Okay, perfect. And then I was wondering if you can just talk a little bit more about -- into 2020 and where you're at in terms of productive capacity and where you think the first quarter might shake out in terms of production.

[Paul Wanklyn, President, CEO & Director]

Yes. We're not prepared actually to release any real 2020 guidance, Tyler, until January. Our goal is to get a full quarter behind us. And then in January, sometime, leave a pretty full -- release a pretty fulsome view of what 2020 looks like. In terms of productive capacity. Again, I don't think we're prepared after just really just over a month of production to talk about that. I think we're very pleased with the performance of the wells. I think we're all on track, and the comment a minute ago about -- on type curve and having excess capacity behind pipe is a theme we're going to continue on with.

[Dan van Kessel, Vice President of Corporate Development]

I think what I -- just follow-up, what I'd highlight is that just from an infrastructure capacity perspective, right now with the 2 processing facilities in south of the River, we've got about 24,000 BOEs a day of access. And I think we pretty clearly lay out in the presentation as well as in the press release, we'll have about 9 new wells that we'll bring on production between Q1 and Q2. We'll happily provide more update on that in January.

[Operator]

And our next question comes from Mitch Mastel with National Bank.

[Mitch Mastel, Associate]

Things are shaping up nicely for Pipestone. Just kind of a couple of quick questions building on what the other guys have said. With the first 20 wells having corporate liquids at about 50%. I just want to know if you could provide any insight on how you think these wells will perform in terms of liquids yields kind of into Q4 and Q -- and into 2020 and the impact of the development north of 3-1 pad, where liquids are more prominent on corporate liquids and going forward, I guess.

[Dustin Hoffman, Chief Operating Officer]

Yes, again, I think we just probably reiterate that we're -- our expectations right now in these first 20 wells is they're tracking type curve. The CGR profile on our type curve does kind of fall off with kind of that average CGR around 100 barrels a million and a terminal CGR rate. So I think we're still expecting that type of performance from these wells. There's no doubt that the northern part of the land base does appear to be a little bit richer from a CGR perspective out of the gate, and really that's meaningful, why our maybe short-term development is focused in that area.

[Mitch Mastel, Associate]

All right. And just another question regarding -- I want to know if you could provide any insight as to the sustainability of the cost structure kind of going forward, how we can think about just operating and transport costs in the near and over the next coming years?

[Dan van Kessel, Vice President of Corporate Development]

Yes, sure. So in terms of transport cost, I would say that Q3 is not representative of what that's going to look like going forward. We have fixed pipe transportation costs for all of our C5 and NGLs that we're utilizing on a go-forward basis. As we become more and more weighted to north of the river, where everything is pipe-connected versus the trucking that we incur south of the river, you're going to see those overall all costs come down -- transportation costs come down quite a bit. Additionally, all of the -- south of the river volumes are for gas or transported on a line. So we realize better revenue per Mcf, but also incur higher transportation costs. And so that's where you see the overall per BOE transportation costs higher than what we would expect to be in the $3.50 to $3.75 per BOE range going forward here.

[Dustin Hoffman, Chief Operating Officer]

Sorry, so from a direct operating cost perspective, as we ramp up volumes, obviously, a lot of the operating costs are fixed. So you're going to see on a unit basis, those come down quite a bit from where we're at currently. The other thing that we have, we do operate Keyera compressor station and all our in-field facilities. So again, as we ramp up production, those fixed costs will get blended out and we'll be in a much better shape go forward.

[Operator]

[Operator Instructions] And our next question comes from Amir Arif with Cormark.

[Amir Arif, Analyst of Institutional Equity Research]

I understand you're not giving guidance until January 2020. I just wanted to confirm though that do you still estimate that you only need about 9 wells to hold production flat? And I think you'd previously provided that in a previous presentation.

[Dan van Kessel, Vice President of Corporate Development]

Yes, at the midpoint of guidance of 15,000 BOEs a day that would continue to be our estimate. So roughly $65 million of sustaining DC&T cost at that level.

[Amir Arif, Analyst of Institutional Equity Research]

Okay. And that, again, compares to the 12 wells you have drilled and completed by year-end behind pipe?

[Paul Wanklyn, President, CEO & Director]

Yes. 9 of those wells are expected to be on production in sort of Q1, early Q2.

[Dan van Kessel, Vice President of Corporate Development]

Yes. There's a handful of wells in that number that aren't clearly on track to be brought on production immediately, mostly from the perspective of, we'd like to drill additional wells out and track them so that we're not leaving single wells producing on their own and creating parent-child issues.

[Amir Arif, Analyst of Institutional Equity Research]

Okay, makes sense. And just a question on the completion approach you used at the 9-14. Is that a change from the way you were completing the previous wells? I know you were using plug and perf, but just to the limited entry design?

[Dustin Hoffman, Chief Operating Officer]

Yes. We've continued with the plug and perf design on 9-14 with the extreme limited entry processes in place, which is really kind of our base design. So very similar tool. We've done on 3-1, the 2.5 tonne per meter.

[Dan van Kessel, Vice President of Corporate Development]

I would say, there is -- there are some -- we brought on some fantastic new guys on the D&C and the reservoir engineering side. And while we're utilizing kind of being played same completion methodology in terms of tonnage and using plug and perf, there are a number of somewhat proprietary tweaks that we're making along the way here, which we think will result in more effective fracs and continuously driving down the cost structure here on the completion side.

[Paul Wanklyn, President, CEO & Director]

Yes. And one last note, Amir, too. We're still piloting some of these designs in terms of stage lengths, cluster spacing, et cetera. And one of the other variables we're still looking at is larger tonnage, and we've gone as high as 3.75 tonnes per meter. And we expect the next pad, that 6-24, will be piloting at least 2 of the wells at that higher tonnage rate as well. And so as we continue on, we're really honing in the ultimate design that we think we're going to be sticking with. So that's another nuance to your question, I think.

[Operator]

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.