Good day, ladies and gentlemen, and welcome to Peyto's Third Quarter twenty eighteen Financial Results Conference Call. As a reminder, this conference call may be recorded. I would now like to turn the conference over to President and CEO, Darren Gee. Please go ahead.
Thanks, George, and good morning, ladies and gentlemen. Thanks to everybody for turning into our third quarter twenty eighteen results conference call. Before we get started today, I would like to remind everybody that all statements made by the company during this call today are subject to the same forward looking disclaimer and advisory set forth in our company news release issued yesterday. So please have a read of that. In the room this morning, we've got all of the Peyto management team here.
We've got Kathy Terjean, our Chief Financial Officer JP Lachance, who's our VP Engineering and Chief Operating Officer Dave Thomas, who's our VP Exploration Lee Curran is our VP of Drilling and Completion, he's here Todd Burdick, our VP Production Tim Louie, our VP of Land and we've also got Scott Robinson, our Executive VP of New Ventures. So feel free to pepper Scott with some questions later about all our new ventures. Before I get started with my comments today about our quarterly results, I do want to recognize the efforts of the entire Peyto team, including all of our field personnel. We didn't have a lot of completion and drilling activity in the quarter, but they were still very hard at work with production operations and cost control, particularly in light of the wet conditions that we had in the third quarter. And as usual, our team did a great job.
So on behalf of all Peyto shareholders, I'd just like to say thank you for the big team effort out there in the field and here in the office. So just some general comments. I'd start off this morning with just a few comments about the quarter, and then we can take some questions from those listening in. Going to try and keep this relatively brief as this is a very busy week of reporting. And of course, we have our twentieth anniversary party to get ready for tonight.
So we'll get through this quarter quickly. As I mentioned in the release, we are back drilling again. We've ramped up our drilling activity throughout the quarter. We were able to keep drilling even through a lot of the wet weather because we were sitting on many pad sites within Greater Sundance. We weren't quite as lucky on the completion side.
We were shut in and shut out of many of our completion sites due to road bans in the West Edmonton area during September. Frac pumpers are the heaviest equipment that we have to move around in the field. And so of course, we need some relatively firm roads to do that. We still managed to get 25 wells drilled though in the quarter, 15 completed and just a few more brought on production by the end of the quarter. Of course, we'd hope to do more, especially considering the nice rally we had in gas price in the later part of September.
We wanted more production ready for that early winter rally that we saw. But then, of course, I suppose we would have been shutting some of those volumes in because then in later October, we saw gas prices collapse again and now they're taking off again. So we're busy adding those volumes that we drilled throughout the latter part of the third quarter and here into the fourth quarter. As also mentioned in the quarter, we experimented with a couple of different completion designs for our Cardium wells. JP can give us more details on that.
We did several wells with a couple of different technologies. Of course, we keep looking for better ways to complete this big resource that we've got and keep looking at new technologies that are always being developed. And just because we found one way to do it doesn't mean we're going to stop innovating when it comes to our completion design and when it comes to improving our results. I know at Peyto, we don't really like to be on the bleeding edge of technology, but certainly as soon as some of these technologies are proven, we're generally one of the best at putting it into practice and then perfecting it. As we also mentioned in the quarter, we're officially a Montney player.
During the quarter, we picked up 50 secondtions of land and we are currently drilling on our first exploratory well on those lands. So stay tuned on that. Kudos to our team for how quickly they were able to jump on that new opportunity. We picked up the land in the quarter and already we're drilling on it. So that's pretty fast turnaround.
The quarter, as we mentioned, was not very enjoyable from a commodity price perspective. There's some very weak and volatile natural gas prices. And so sadly, our plan of delaying a lot of our capital to the fall and even shutting in some of our summer production was one we had to put into practice. Of course, one of the main reasons for those weak prices is that the traditional storage reservoirs in the province that add demand for gas in the summertime, that market just wasn't really present for us. So we didn't put much gas into storage this summer, which normally translates into much higher winter prices because we won't have that stored gas to rely on this winter.
And I think already, we're starting to see the effect over the last few days with some cold weather showing up in Western Canada and the big rally that we've seen in gas prices on November 3, they were negative. And yesterday, they were $3.1 I think was a closing price. So a big shoot up in AECO gas prices here just in the last few days with the cold weather. On the oil side, oil price was pretty strong and so was our condensate price. So that was nice.
And really, when you look at the combined price along with our hedges, the total price we realized in Q3 twenty eighteen wasn't much different actually than what we realized in Q3 'seventeen. On the cost side, our cash costs were up a little bit. There's continued pressure from government regulation and taxes that are driving up the cost of our business, municipal taxes, carbon taxes, Alberta Energy regulator fees, all these things are going up and that adds cost to our business. I believe we still are doing the best job in the industry to hold cost down, but our industry just keeps getting hit with higher and higher cost to do business. So eventually, something is going to have to give there.
Of course, part of our higher per unit cost had to do with our lower production as we spread the same fixed costs over a lower volume base, it drives per unit costs up a little bit. And so some of the cost increase was us deliberately holding off on our capital investments and production to build out due to low prices. So the combination of those prices and our cash costs gives us a netback in the quarter of around $14 a barrel, which is quite a bit better than a lot of other gas producers that I've seen so far who have even more liquids than we do right now. So I think as we increase our liquids weighting, as we add more Cardium, I expect we'll be making up ground on the industry some more in terms of our netbacks. So it's good to keep those at the top of the industry.
On the marketing front, we continue to make some headway diversifying our sales to The U. S. With some more AECO NYMEX basis deals. We basically hit our target for twenty nineteen summer to have around 40% of our gas tied to NYMEX. We still have some work to do in 2020 and out into 2021.
And then by the end of 2021, we expect the full addition of the Nova system expansion work to be done. And so that should give us a much increased access to the North American market. TransCanada was looking to add, I think, close to 2.5 Bcf a day of market access over the next couple of years with a $7,000,000,000 capital program here in Alberta. So that should close that basis differential between U. S.
And Canadian gas prices for us. As we disclosed in our preliminary 2019 capital budget, we've got capital plans for around $275,000,000 midpoint of our guidance between $250,000,000 and $300,000,000 That's up a bit from 2018. Our 2018 capital program looks to come in at probably around $230,000,000 But both of those numbers are really still very conservative relative to what we're capable of and relative to the capital programs that we've had in the past. All of our capital will be focused almost exclusively on the Cardium as those economics are still relatively robust even with the volatile gas price and even with the big differentials we're seeing right now on condensate prices. So we'll keep banging away on our Cardium because that looks like it's giving us the best returns.
And we're starting to get a little bit bullish on winter gas prices, of course. Not much cold weather has really shown up this fall already. And already, we're seeing a lot of pressure on the ability of the supply to meet demand. Alberta demand is up year over year and supply is sort of capped by the pipe. So we're starting to see some good pressure on prices and we're starting to feel a little more bullish, obviously, as we head into winter here with the potential for AECO to really run.
And if it starts to bring the back end of the curve up, then we start to see some more strength in AECO natural gas prices, obviously, as we go further out into the future, we've got obviously a large inventory of Spirit River locations that we can start to dip into and start to add to our capital program that would result in us increasing our capital budget, just the commodity prices there to support it. So I would say at this point, we remain cautiously optimistic. But considering the volatility that we've had over the last few years, we're really ready for any kind of outcome. Anyway, that's just a few comments on the quarter, quick highlights as we run through them. We've got all the management team here, so I thought maybe we'd hit them up for some more color before we jump into questions from callers.
So maybe we could start with drilling and completions and our VP of Drilling, Lee Curran. Lee, we're trying to catch up from the month of wet weather that we had or I think it was maybe even more than a month. What's that looking like? How are we doing? And how are we set up for next year with rigs and completion spreads?
What's this rig schedule look like for us going forward?
Sure, Darren. We certainly lost some ground relative to our planned schedule due to that excessively wet weather that span most of September and well into October. Although we were able to find a way to keep most of our drilling rigs moving as you mentioned, we were certainly not so fortunate with our completion activity. In fact, we were held to fracking only a single well in the entire month of September and just a pair of wells from a single pad in October, I mean, the October. The silver lining here is that market conditions are really supporting our capacity to ramp up activity The and quickly catch up on that backlog, both in terms of frozen access conditions that we're seeing right now and more importantly, to our services.
We're having great success lining up crews. We fracked nine wells over the last October and a second intense wave of activity starting this week with a schedule that hosts eight fracs in just seven days. So everybody upstairs is going to be busy watching their screens. We expect to see some great cost efficiencies over this period as well, given the majority of this standing inventory is being served from both two and three well pads. And with this current market activity, there's some spare capacity in pressure pumping market and we're receiving a little bit of incremental pricing discount to accommodate this Q4 activity.
In addition to our single Montney drill, we have six core active drilling rigs. Five of those are spread out across the Greater Sundance area and one of those rigs has been bouncing around the Brazeau Complex. It will be diverted up to Kisku just east of Grand Cache at the end of the year to follow-up on a successful well we drilled earlier this fall. And all six of those rigs have been contracted through the 2019. So with those, we continue to see performance improvements that we've always associated that we achieve with the consistent core fleet of people and equipment.
We've populated a solid program of Cardium wells to keep these six rigs active. We presently have four full completion spreads, and that represents the spare capacity that we need right now to catch up on this standing DUC inventory, while keeping up with the newly generated wells that will follow those six rigs. The rig schedule for the 2019 has essentially been fully populated. Of course, with all things, we tweak it daily almost and try and optimize that for both movement and offsetting better results. Got a great lineup of ready to drill locations that represent our capital program.
If weather and market conditions cooperate, a number of those locations are well poised for even accommodating some breakup activity. We'll see how that goes as that time approaches. One element that's kind of key to our flexibility in terms of capital expansion is we are starting to see some material improvement in terms of project approval timelines on the regulatory front. So adding newly generated projects to the schedule is steadily moving in the right direction. We're a very active participant in those discussions with the regulator.
And although there's still some significant room for improvement, great strides are being made to shrink those timelines.
Okay. Thanks, Lee. Maybe let's pop over to JP Lachance and talk about these new Cardium completion designs. JP, what can you tell us about them? How many did we do?
What's the result of them that we've
seen so far?
Sure, Darren. I think last quarter, I shared some specifics about water volumes and spacing. But essentially, we've tested three different liner designs with varying stage counts and intensity, including open hole and cemented ball drop systems and coiled tubing angular frac systems. We did this intentionally in a few areas and in sorry, for a few different wells and in different areas. As we mentioned in the press release, some of these wells with the higher frac density are cleaning up slowly or essentially flat at lower rates.
So we kind of need to see those see some time to determine if the increase in intensity, which translates to higher costs, is in fact creating more value. In the meantime, we've dialed in an open hole ball drop system that appears to provide us the best returns for now. Our average drill and complete cost for Sundance well with this design is about $2,800,000 so it's cheap. And all in costs, full cycle costs of about $3,500,000 Our average production profile for the wells run with this system generally have a short cleanup period to a peak rate of about 500 BOEs a day before declining out to what we estimate will be an ultimate recovery of around 3.7 Bcfe. But most importantly, the liquid yield here we get from our Cardium wells.
And don't forget, we have a lot of historical production here to validate our forecast assumptions. It typically ranges between 40 to 60 barrels a million. It depends on which plant it goes to. But I should also note that some of our better wells recently have exhibited initial yields closer to 100 barrels per million under this new design. So when you factor all this in, our latest type curve yields close to a 40% rate of return on the current strip, which now includes the most recent higher condensate differentials.
If gas prices continue to strengthen, it makes our Cardium returns even that much better. So either way, the Cardium will be a primary focus for us next year. And as Lee and Darren said as you said and Lee said, we're a little slow off the mark here, but I think there's some real positive things to come.
Okay. Thanks, JP. I think you mentioned that it was nine wells that we had tried the new design on. Yes, sorry. We'll watch those closely.
Maybe jumping over to our VP Exploration, Dave Thomas. Looking at the 2019 budget, Dave, what can you tell us about the 75 to 90 locations that we've got teed up? Are they all Cardium? Or do we have a couple of other types of locations in there? Are they all in Sundance?
Or are we moving up north? And are we going to do any more Montney drilling next year?
Darren, the majority of next year's wells will be Cardiums and most will be drilled in our Ansel, Sundance and Wildhay areas. Up in our northern area, as Lee mentioned, at Kakwa Kisku, We've recently completed and tied in our first test well, and we're happy with the results. So we've got three Cardium follow ups lined up there this winter. We'll look to get feedback from those three wells to guide us on how aggressive our northern drilling program will be in the summer and fall. Down south at Brazeau, we're just about to spud two Cardium test wells this November that will help evaluate potential of the play on those lands.
The gas pricing looks strong enough for the 2020. We may also substitute in some Spirit River wells during next year's Q4 so that their flush production takes advantage of the stronger winter prices. As for the Montney, we'll wait on completion results. It's an exploration well, but if it's sweet and if it has good liquids, we'll get it tied into our Wildhay plant and follow it up later in the year.
Okay. Thanks, Dave. Todd Burdick here, our VP Production. Todd, one of the questions that I saw yesterday from an investor regarding our Cardium program and the intensity of it next year was had to do with the liquids. Are our plants set up to handle all this extra LPG and condensate that we're getting from the Cardiums going forward?
Yes, sure, Darren. Maybe I'll start at the wellhead and then move through the gathering system at plants and finally delivery to sales because really we've been working on all those pieces of that value chain through the year here. So starting at the wellhead, where we separate gas, condensate and water We've made changes to piping within the surface facilities to accommodate more volumes of condensate and water. This is an easy and inexpensive change that we implemented after the first beam Cardium wells earlier this year.
The condensate and gas are then recombined and sent down the pipeline gathering system to the plant. Given that this new Cardium development is happening within our existing core areas of operations, we have existing pipeline infrastructure in place. So very little new pipe is needed to get the gas and condensate to the plants for processing. Now that being said, some wells have required new services, but even in those cases, the tie in distances are relatively short as they connect to our trunk lines. Once the gas and condensate arrives at the plant, it's again separated for processing.
For the first ten years of Peyto's development, we were a Cardium focused company. Many of our plants already have the equipment in place to handle larger volumes of liquids. But much of that older Cardium development involves vertical wells with much lower liquid rates as opposed to what we see with multistage horizontals. So we do need to add some equipment depending on the facility to handle the anticipated liquid volumes that are literally coming down the pipe in 2019 and beyond. We've done all the scoping work to determine where the bottleneck may be and engineering is underway for some relatively small expansion plans at a couple of the plants.
We've had all of this equipment in or we have all of this equipment in our inventory. So we aren't at the mercy of long delivery times for manufacturers. It's anticipated some of this work will be undertaken and completed as early as 2019. And then moving to the final sales of liquids. Of course, in 2017, we put two liquid lines in the service that connected four of our gas plants.
Those lines were built to accommodate much higher volumes going forward. I should also add that as of Q3, we are also moving our Brazos gas plant LPG down pipe to market. Of course, keeping all this product out of trucks and off the road infrastructure also means we see better realized pricing and safer conditions in an already congested area. And then beyond our own infrastructure, we've also been in discussions with the shippers we offload to ensure that they're able to accommodate any future volume increase, which also includes the significant volume we would see from the addition of any deep cuts in the greater Sundance area. So really, we're in good shape going forward, and we're always looking ahead to make sure that we're able to move all of this liquid as efficiently and cost effectively as possible.
Okay. Thanks, Todd. That's great. I think that helps guys understand just how many pieces along the way there really is that you've got to debottleneck when you start changing your production blend, and it's not quite as easy as some people think it is. Maybe switching gears, we could talk a little bit about land and future inventory.
Tim Louie, our VP of Land, we bought some Montney land this quarter and already we're drilling on it. But we also are harvesting a lot of Cardium inventory. So what's the outlook for maybe adding more Cardium lands and backfilling that inventory?
For sure, Darren. The third quarter was definitely an active period for Crown Sail acquisitions. In addition to the fifty secondtions you previously mentioned that were acquired for the Monty, we also purchased another 5.5 secondtions during the quarter. Year to date, Peyto has acquired 63 secondtions at Crown sales. Aside from the 50 Montney sections, the balance of the Crown lands were acquired primarily for Cardium.
Given the average price paid at Upper Crown sales this year stands at $110 per acre, we're pleased to state that our average acquisition cost thus far is $79 per acre. Now we haven't been relying solely upon Crown sales for acquisitions. We are working on two asset deals that will also supplement our Cardium inventory. I can't provide any more details, but I can say that both deals are anticipated to close by mid December. And it is worthwhile to note that the new Cardium locations we have identified on the Crown and Acidea lands will more than replace the wells of what we drilled in 2018.
That's good to hear. As usual, I expect we probably will add 1.5 or two wells for every well we drill this year. That seems to be the way Peyto's operated over the last twenty years, growing inventory when everybody thought we didn't have any land to grow it off of. Maybe last question is for Scott Robinson. Scott, we talked about our deep cut plants for Swanson.
We've got a bunch of plants that we could deep cut, but it looks like Swanson is next up on the list. Just curious maybe what kind of propane market do we need to see going into Q1 to pull the trigger on that and call FID?
Yes. If you recall, propane went through quite a roller coaster ride there in 2015 and 'sixteen and created some uncertainty for us where we saw propane prices actually drop to below the gas value of propane. But if you look at our fourth quarter of last year, propane had recovered into the $30 plus per barrel range, and it's nicely finding its way into the $20 to $30 price here if you look at the last several quarters. And those prices are at plant gates. Those prices work.
That $20 to $30 a barrel propane price works with our capital costs, which are quite low relative to industry to build facilities. And I think it's bringing to us that courage to go ahead with this investment, which will be a very long lasting investment. We'd start with Swanson and build out the deep cut there and then as you mentioned move to some other plants as those feed streams continue to justify deep cutting. At Swanson, it's interesting. If you look at the current composition that feeds that plant, it comes from a number of different formations.
Very little of it is Cardium. And in its current state, the liquid yield advantage that we would get would be about 14 barrels per million cubic feet at that plant.
If you
run those numbers with that propane price, it works out quite nicely. On the horizon though, we've got all of this Cardium that's just now starting to come to fruition. And as we direct the southern part of our Cardium production to this plant, to the Swanson plant, the Cardium in and of itself, when you deep cut it, will give you about 20 barrels per million of incremental liquids as compared to the 14 that we're seeing at Swanson. So as we fill Swanson with more Cardium and transition it to a richer feed stream, that will further enhance the economics of this deep cut. So it's all coming together nicely.
We mentioned that out there on the horizon, there's some other enabling factors, AltaGas' Ridley Island project, some intra Alberta propane consumption in the petrochemical side of the business. Those are all going to put new polls on propane, which will further justify what we see as a very attractive economic investment profile from a facility vertical integration standpoint.
Hopefully, stimulates a little more thought and questions about some of our business from those listening in. So maybe, Jorg, we can open the phone lines up and answer any additional questions that investors and analysts have.
Sure. Thank
you.
And I show no questions at this time. I would like to turn the call back over to Darren Gee for closing remarks.
Well, thanks, George. I appreciate that it is a very busy morning with conference calls and other releases going on. And hopefully, we've managed to answer all the questions that everybody had. So we'll get back to drilling. We've got an obviously incredibly busy Q4 lined up right into what hopefully will be some much stronger gas prices as winter hits and as we start to test whether or not we truly have enough supply in Western Canada to satisfy the demand.
And we'll come back to you, I guess, it'll be late in the quarter and give you an update. We'll talk to you then. Thanks for listening in.
Ladies and gentlemen, thank you for participating on today's conference. This does conclude today's program, and you may all disconnect. Everyone, have a great day.