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Good day, ladies and gentlemen, and welcome to the Peyto Exploration Year-end Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to introduce your host for today's conference, Darren Gee, President and Chief Executive Officer. You may begin.
All right. Well, thank you, Gigi. And good morning, ladies and gentlemen. Thanks for tuning in to Peyto's fourth quarter and fiscal 2017 year-end results conference call. Before we get started, I do want to remind everybody that all statements made by the company during this call are subject to the same forward-looking disclaimer and advisory that we set forth in the company's news release issued yesterday. In the room with me today, we've got almost all of Peyto's management team. We've got Scott Robinson, our newly appointed Executive VP of New Ventures; we've got Kathy Turgeon, our Chief Financial Officer; JP Lachance, our newly appointed Chief Operating Officer; Dave Thomas, our VP, Exploration; Lee Curran, VP, Drilling and Completions; and Todd Burdick, our VP of Production. And the only one missing today is our VP of Land, Tim Louie, who is out. Before I get started with some comments on the quarter this morning, I want to recognize the efforts of the entire Peyto team, including all our field personnel. We not only had a lot of activity this past quarter, but again, had to deal with some unprecedented volatile natural gas prices. And I think all of our team did a great job. We managed to achieve record production for Peyto despite having to shut in about 800 boes a day on average for the quarter due to some low prices in October and again, in December. And we posted one of the largest quarterly earnings numbers that we've seen over the last few years. So on behalf of all of the Peyto shareholders, I just want to say thank you to the entire Peyto team for that effort. So just to start off this morning with some general comments about the quarter, and then get into a few specifics and maybe take some questions from those listening in. On the drilling front, we drilled some exciting wells in Q4. Our Notikewin play in West Brazeau continues to deliver some of the most productive wells we've drilled as a company. They're very high rate and very high pressure. And while they're a little bit challenging because they're our channel play, they're very exciting. And of course, our new Whitehorse area was giving us some nice Wilrich results, too, especially considering that we have a lot more liquids coming out of that Wilrich than our traditional Wilrich. So that's encouraging, especially with these gas prices that we're currently experiencing. And then we tested a couple of new wells in our South Brazeau land block that we just bought this year, and we're excited about those. So those should provide a lot of drilling inventory in the future within a number of different prospective horizons. On the production front, we did react to a couple of dips in the AECO daily gas price, which kind of surprised us in the [Audio Gap] fourth quarter. We had to curtail production for a few days when the day price was low. But other than that, as I mentioned, we posted record production for Peyto, even touching 150 barrels a day before we exited the year. And included in that fourth quarter production, we also hit record liquids production for us at over 10,000 barrels a day of NGLs. And obviously, with liquids being worth so much more than gas, optimizing that NGL extraction is becoming even more important today. And we're busy working on ways to do that [Audio Gap] even better. And I think Scott can probably provide some more color on how we're doing that going forward. There's a lot of things happening during the fourth quarter that were affecting natural gas prices in Alberta and Western Canada, the surprise change in Q3 by TCPL to treat interruptible delivery service off their Nova system differently than they did before. It meant storage had a very small role to play this fall. And unfortunately, that sent gas prices swinging quite widely, especially in October. For instance, on September 30, AECO daily was actually negative $0.12. And by October 30th, with the weather starting to get colder, it rallied to $2.22, so quite a swing. And then thankfully, we continued to see early cold weather and the price stayed stronger for November and then got a little soft in early December, but then rallied again to the end of the year to be very strong. And that's even with a big surge of new production that we saw in Western Canada in November, close to a Bcf a day hit the system from -- through -- 3 branded plants that were started up in the North Montney. Thankfully, we [ hold there ] the normal weather or that extra supply would really be pressuring gas prices. Regardless though, we had already presold about 85% of our gas at around $2.60 a gigajoule and then dedicated over 90% of the total to the monthly price. So we had very little exposure to gas through the daily prices anyway. Monthly averaged, I think, about $1.86 in the quarter and then the daily average to only $1.55. So when we combine our [ multi-hedge ] gas price with a very strong liquids price that we saw in the fourth quarter, I think the best liquids price we've seen, in fact, in several years. We realized around 350 Mcfe a year, $21 a BOE in revenue, which is actually our highest combined realized price that we've seen in over [ 2 ]. So when you combine that with our total cash costs of around $5 a BOE, we ended up with very strong net backs even for a gas producer. And that's what drove the big increase in earnings for the quarter. Earnings for the quarter were $51.5 million, which is the best quarterly earnings we posted since 2014, in fact. And all of us can remember that in 2014, we had a $4 gas and a $100 oil price. So a very successful quarter, I think, despite the natural gas prices were doing.So maybe before we open up the call to questions from those listening in, I wanted to engage some of the Peyto management team with some discussion about our future outlook and hope that provides some additional color. So maybe I can start on the drilling side with our VP of Drilling, Lee Curran. Lee trimmed our capital budget obviously for the year. We started off this year pretty slow from a drilling perspective. I think we've only got 1 or 2 rigs running now. So we're hoping I think that we can continue to make some significant cost savings on the drilling and completion front to help bolster returns while we have to endure some very weak near-term gas prices. And as we noted in our release, we recently shaved 30% off the cost of a couple of Whitehorse wells, which is quite the accomplishment. And then we're going to drill some more Cardium wells this year. So I guess the question is, what's the plan for cost reductions in 2018 going forward? And how do you see us continuing to innovate to bring those costs down?
Sure, Darren. And as we saw, coming into the first quarter of 2018, activity ramped up quite substantially. And with that, came some associated costs that [Audio Gap ] cost pressures, unfortunately. We didn't experience a few minor price increases in a few select areas where services were running at full capacity. However, for the most part, service costs remained flat. And actually, in a few select instances, we were able to realize some small cost reductions from our service providers. Now despite the continued winter drilling conditions, we're starting to see some of that activity fall off with support -- with reports that a significant amount of that activity is going to further reduce over the next couple of weeks. And with that, we should see a retreat in those typical first quarter cost pressures. At our Whitehorse Wilrich play, we realized some significant drill cost reductions due to well design improvements. In many of our Greater Sundance Wilrich areas, we're required to case off the intermediate section to alleviate borehole instability that's associated with thick troublesome [ cores ]. And down in Whitehorse, through our experiences with the initial wells that we drilled, we were able to gain sufficient confidence to evolve these designs into a modified monobore design. And thus, eliminate that full protective string of intermediate casing. The 5 Whitehorse wells drilled in 2017 averaged just over 11 days as compared to just under 9.5 days for the 2 wells that we drilled in the first quarter of this year. Being a little quicker saved some of that cost. However, the bulk majority of that cost reduction just simply comes from eliminating that intermediate casing string and the associated cost reductions of drilling a smaller diameter hole for a greater portion of the wells depth. We've a number of multi-well pad drilling opportunities down there as well. So that's going to help us further reduce those costs once this play hits full stride. Our typical Cardium wellbore design is consistent with the prior mentioned Whitehorse design. We've continued to experiment with fluids to enhance drill rates. And some of these Cardium laterals can be extremely abrasive, so we've got a few design improvements that -- now that we have a consistent program, we're going to be able to feather in and utilize the model of continuous improvement. With that, we've recently started installing significantly increased stage counts in our Cardium wells. So that's spells a bit of a cost increase, but we intend to erase that elsewhere. We have a few ideas to combat that. The big carrot in this play will be the ability to confidently execute with multi-well pad operations, eliminating all those burdens associated with physically picking up rigs, moving well to well along with significant efficiency improvements associated with batched out completions. And for that matter, batched out tie-in operations has the potential to more than offset the incremental costs associated with this increased stage count. I'll defer some of the finer details on our current efforts to improve our Cardium well results with this increased stage count design for JP's contribution to the call.
Okay. Great. Thanks, Lee. Maybe sticking with our cost theme, I wanted to ask a question that I get a lot. Todd, who is our VP of Production -- we're attacking costs on all sides. We're going to try and drive cash costs down even further. And what are we going to do? What's the plan, I guess, to attack these operating costs and maybe transportation costs? How we're going to get some of those cash costs down even further from Peyto's industry-leading cost levels?
Yes. Well, Darren, it -- really for, for several years, we've had an intensive effort to use technology that we already have in place to make key changes to process and reduce the costs in a number of different aspects of production operations. Water handling has been a focus for a couple of years now. By optimizing the logistics of moving water in the field, we've seen a reduction in the cost per meter cubed. And we're going to continue to streamline this process and drive those costs even lower. Chemicals, specifically methanol, which is key to our ongoing operations, over the past few years, we've had -- we secured some price protection that has allowed us to buffer seasonal price swings. We'll continue to do that in 2018 and beyond. This is an area where we've been able to use our SCADA technology to optimize the amount of methanol that's being injected into each well. And as a result, we're seeing average injection rates per well drop every year. We're continuing to reduce maintenance costs by moving away from using third parties to perform maintenance on key pieces of our facility infrastructure. Several years ago, we began with compression, and we've seen a significant decrease in the labor costs to maintain that equipment. And this year, we intend to continue in that same vein with other components of our facility infrastructure, and we expect to see similar cost reductions. Pad drilling is going to help us to reduce costs as well. As well production declines, we're able to consolidate the equipment on a well pad, and then redeploy that surplus equipment on new wells. So we were able to realize savings on the manpower costs, chemical costs, maintenance costs and also on the property taxes charged by the MD. We expect yearly road maintenance charges to be reduced as we've been able to take significant vehicle traffic off the roads with the installation of our liquid pipeline infrastructure in Greater Sundance and the use of helicopter operations in our northern areas. And then with respect to transportation costs, our marketing team are actively taking steps to keep our transportation costs flat on a per unit of production basis as we go forward through this year and next.
Okay. Great. Maybe one last question on the cost front. G&A and interest are the last cash cost there. Kathy, maybe you can give us some color on how we're going to keep grinding away on the interest and G&A costs and keep those low on a per unit basis? And maybe push those down?
Well, our G&A is already, of course, very low. For a company that has $760 million in revenue, our G&A is just over [ $70 ] million, which is before overhead recoveries; after overhead recoveries, $8.5 million. As we have a reduced capital budget, we will see perhaps a per Mcfe net G&A increase, but our gross G&A is only $0.07 per Mcfe now. We only have just about 50 staff, and we don't see any reason to increase it. We'll just continue doing what we've always done, which is focusing on necessary costs and not extra costs and question ourselves on every expenditure to say: is this something that will benefit the company or is it just nice to have? And we've always done that and we'll continue to do it. On interest. I think there's going to be a reduction there. We have had -- now have a smaller capital program going forward. We've reduced the dividend, so we'll see repayment of debt, which will drive our interest costs down. In addition, we did some notes at the beginning of January. So more of our debt will be fixed in a period where we're looking at rising interest rates in the next couple of years. That's an important feature in managing our interest costs as well.
Okay. Good. Thank you. So maybe just switching gears just to talk a little bit about the resource opportunities. Dave, we talked in the release and I talked earlier that we're going to focus on some more liquids-rich drilling in our portfolio that includes obviously some Spirit River in Whitehorse that looks a little rich and then, of course, the Cardium. And it's been several years since we really attacked the Cardium in earnest. We've been focusing on the Spirit River over the last few years. Maybe you can refresh everybody on what the real Cardium potential is and what kind of inventory we have and where that exists?
Darren, Peyto has a long history in the Cardium. We've drilled quite a large number of verticals and just over 70 Cardium horizontal wells. Our independent reserves evaluators have booked an additional 174 undrilled Cardium horizontal offset locations. And of those 174 undrilled locations, about 140 are in the Greater Sundance [ antwip ] area. Including our [ Wild J ]in northern [ capital ] lands, we hold quite a lot of prospective acreage in the play. Geological net pay mapping supports an additional 375 unbooked horizontal locations. So the potential is over 500 undrilled Cardium horizontal locations. And if you look at [ psi H ] volumetrics, that supports actually a significantly higher number than 500. For 2018, we plan to focus our Cardium drilling in Greater Sundance, which is our most proven area. Later in the year, and assuming continued success, we'll likely push out and test our new approach to the play in some of our northern lands at Smoky/Kakwa. The Cardium is shallow, sweet and liquids-rich, and we have abundant opportunity, much of which is directly under our existing infrastructure. It's taken a few years, but now it finally appears that improvements to Drilling and Completions technology will allow us to realize much more of the potential we've recognized in this play for a long time.
Okay. Thanks. So keeping on that same discussion, JP, maybe you can provide some color on this Cardium completion. You know we've changed the design a little bit. And obviously, we don't want to give too much away, but what's this new design giving us? And why we're so excited about it?
Sure, Darren. As you mentioned, we've -- we haven't focused a lot on the Cardium in Sundance during the last few years. And that's not because we didn't recognize the tremendous resource potential still remaining, but more related to the fact that our Spirit River plays carry better returns with higher prices then. So naturally, were a bigger part of our portfolio. But last year, we drilled 2 horizontal wells in the Cardium with a different approach to the completion design, whereby, we applied smaller size slick water fracs across more stages. The outcome of these 2 wells, which should be on-stream for several months now, have yielded superior performance as compared to the 48 wells drilled in this area prior. So in fact, one of these wells appears to be trending towards being our best well in the Sundance area, while the other is solidly in that top 10. Now these 2 wells are expected to generate returns of over 30% on today's strip, with funding and development costs about $1 an Mcfe. So following up on last year's success, we put together a 3-well program in the first quarter of 2018, targeting a broader area in Greater Sundance to further test our new design. I'm being more specific without giving too much away. On the completion design changes, we've moved from an average of 8 stages and 150-meter spacing on the wells prior to 2017 up to 29 stages and less than 50-meter spacing most recently. At present, we have 1 well drilled and completed, which has recently been put on-stream, and it's showing a similar positive attributes to last year's program. The second well is waiting on completion and the third is currently drilling. Internally, we estimate about 2.4 Tcfe of gas in place in the Sundance area alone, which is only -- which today, we've only recovered about 14% of that. The Cardium gas comes with liquids ratios between 40 and 60 barrels a million with a large portion of that in the valuable condensate and pentanes-plus form. So we're proceeding cautiously, but with continued positive results, we plan to load up the back half of 2018 with 30 to 40 more Cardium wells where we'll continue to evolve that well design by drilling some longer horizontals and perhaps, increasing stage counts up to 50 or more. So on top of -- I guess, Darren, on top of all that, those encouraging elements of this play, and as Dave mentioned, the fact that this opportunity sits amongst our vast network of leases, roads and pipe and plants, makes the Cardium that much more exciting again.
So how -- could we ramps up quicker than that if we wanted to do more? How easy would it be to add even more Cardium locations to the back half of the year?
Well, we certainly have -- I -- well, part of this is we want to see how these wells perform. So we want to give it some time. And that was one of the reasons why we wanted to spread some of these tests out amongst our larger area. So we certainly have more locations we can put together for the back half. So if we get those encouraging results -- and since we have some at our existing -- these locations exist on our -- off of existing leases that we have in the area, we could ramp up quicker if we wanted to. But we kind of want to see how this play out. We're going cautiously. We're looking -- we're testing different areas to make sure it works, and then we'll go from there.
Okay. Good. Maybe lastly, Scott, some comments on the new ventures. You wanted to retire, and we said you couldn't go fishing full time just yet, but -- and you've been so busy looking at all these new opportunities to extract the value out of our resources and our infrastructure assets without having to put our gas on expensive pipelines and ship it to far away markets. What kind of things are we looking at? And what do you envision all this might look like, even a year from now or maybe 3 years from now?
Yes. I'm -- been busy digging through the tackle box looking for the right lure to find the opportunities. But there are a lot of opportunities out there and it's -- we just kind of neat to change venue and look at the business a little bit differently. The guys have been talking about all the resources that we're bringing forward. We've got 1.7 Tcf of proved reserve and 4 Tcf of proved plus probable. So there's a long horizon ahead to turn that reserve into value. And we're looking at a few different things. But first and most immediate, as we indicated in our release, we've got a multiyear project involving the next big step in our Deep Cut liquid recovery series of installations. Primarily, in the Sundance area, 4 of our -- 4 or 5 of our gas plants there -- some of the listeners may be aware that we have an existing Deep Cut facility, only 80 million a day. It's a partial deep cut on our Oldman facility, and we're getting recovery levels on propane there, upwards of 60% to 70% as compared to most of our other -- normal [ refrig ] facilities, which are in the 10% to 50% levels. So we've got a lot of volume that we can get more propane out of -- and butane and that's what we're targeting with this next phase of sequential installments of deep cuts. Just a further comment, the engineering firm that we're dealing with has undertaken some innovative steps to improve this technology to make it cheaper and to process more gas and get better recoveries than we've seen on our first installation. So we're really excited about that. Overall, I think we cited that our current corporate recoveries for propane are only 15% to 20% and for butane, only 55%. So there's a lot of room to increase those recoveries in a liquid form. And I think most people are aware that propane and butane are worth about 4 to 6x as much in a liquid form as they are in a gas form. So there's a lot of value creation opportunity there. And we anticipate embarking on that with installations in 2019 and continuing into 2020. So that's exciting, and that's right at the forefront. Changing gears. And some of the listeners are maybe aware that the Alberta Energy Diversity Advisory Committee came up with a report a couple of days ago on ways to make more money on Alberta's gas in Alberta. It was something that the government initiated a couple of years ago to look at domestic processing, upgrading of oil or processing of gas, and we're involved in that. We've got -- we're currently engaged with a number of parties, talking about direct sales to petrochemical and power generation opportunities, multiple opportunities. We obviously won't be able to address all of them, but some of them make a lot of sense. And one of the features of our assets is that we sit immediately west of Edmonton on a major highway and on a major rail line that can provide ease of access and transportation of any products to the markets that they need to head to. So some of these markets being Asian markets, for instance, for petrochemical products. So we can't say a lot about the details at this point in time, but we're looking forward to further progressing our discussions. We feel confident that we'll get there on these things. And in the next couple of months, we'll have some more details on these initiatives that we have underway.
Great. Okay. Well, that's probably enough color from our guys. Maybe we can answer some questions from listeners that have called in. Gigi?
[Operator Instructions] Our first question is from Mike Harvey from RBC.
Just a little bit more on the new ventures and how you are going to expand your land position. I'm guessing there will be largely crown land sales like you've done in the past. But would you also look at things like asset deals or things more corporate in nature? So any sense for timing on this and if this would be an ongoing initiative or if you have any kind of milestones there. And then the second one would be just on the well design front. You talked about fracs quite a bit here, but a number of your competitors are going to the longer laterals, so the extended reach. Just wondering if your thinking has changed there. Over the past several years, you were doing kind of mostly one milers now, but is this technology kind of at a stage where you could look at drilling longer wells?
Okay. Maybe we'll engage a few people to answer some of that, Mike. But on the land front, we're looking obviously within the deep basin traditional horizons that we've been working on. We're also looking outside of that at some of the other plays that are still proceeding in this price environment. Obviously, the Montney is still active. So we're looking at land opportunities there. You know, we've never really been a very successful company when it comes to paying up for other people's assets that they've built, much more successful just building our own. But we are very encouraged by what we see in terms of land turnover in some of the new evolving plays like the Montney or even the [ Duvermay ] for that matter. It was several years ago that the big land grabs happened and billions of dollars were spent at very high prices to secure a lot of land within Alberta. But the continuation of that land requires drilling and a lot of it hasn't happened over the last several years. As we got lower gas prices and subsequently lower oil prices, activity levels peeled off. And there's a lot of that land that's coming up for expiry. I think when we counted, didn't we count something like close to 500 sections, I think, of Montney land that could potentially be expiring over the next few years. So I think there is a -- sort of a renewed opportunity here for us to look at some of these new plays. And now they've got a lot more information available, a lot more proven economics that we can look at, too. So I think we can start to look beyond the Deep Basin. And maybe let's be greedy when everyone's fearful here and look for some times and places where we can enter some of these new plays and build the -- a war chest that we can use in the next chapter of Peyto. So we can't talk too much more about some of these inter -- intra-Alberta industrial-demand-type projects that we're involved in just because we're behind confidentiality agreements with a lot of the parties, so we can't disclose too much of the negotiations there. For -- on the well bore design front, Lee, maybe you can comment a little bit about the 2-mile horizontals or JP just to -- the -- with drilling with the Cardium for sure. I would suggest maybe there are some well bore collision considerations for 2-mile wells. But what do you think about the longer lateral?
Yes. Already -- I mean, I mentioned that in my comments earlier that we're considering that. I think it depends on where they are geographically. Obviously, as Darren mentioned, we have lots of vertical control, which helps us with the steering, it helps us with the -- our ability to keep the lateral in the formation. So that's an asset, in some respects. But obviously, we have to be mindful of drainage and not over capitalizing with --[ where ] put horizontals and weave them through existing vertical control. So that's part of the reasons why we may have a less -- we tend to keep these wells to shorter length than -- we pushed up the lengths as it is. Lee can maybe elaborate a little bit more on some of the risks involved with going to longer laterals. But it's certainly not something we're shying away from, which is -- it depends on where they are, right? Where we are -- where our lands are and where we want to pursue it.
Yes. Sure. It's the lateral -- our decision to restrict large number of our laterals to a 1-mile single-section type of design, is typically not a technical consideration. It's more of a -- by virtue of drainage, contiguous land base, the various features that restrict us in other ways. It does afford us the opportunity to keep our per well cost down not as expressed in terms of lateral meterage necessarily or total stage counts, but our actual per well cost because we derisk those individual well bores with those shorter lengths. However, that's not our primary driver.
I would say, too, that the -- Mike, the -- some of the plays like the Montney, for instance, that are up in very remote areas or in undeveloped areas, there's not a lot of surface infrastructure there. So the value of an existing site to be used for a longer lateral is probably greater. Where we are, though, in sort of the central part of the Deep Basin. There's just so much well control, there's a lot of surface sites already that we can use. And so that vertical section of the well isn't very expensive. And if you've already got a well site at surface that you can reuse, you're not saving as much by trying to drill longer lateral from the same point on surface as opposed to having to go a mile away and build a brand new lease that's expensive. Obviously, you want to stay on the existing lease. But if we can go a mile away and use an existing lease then that's quite a bit cheaper. So we don't have to take on some of the risks of the longer lateral a lot of times because we already have a way to save a lot of that surface cost.
Got you. It just looked like you were tweaking your frac program a little bit, so I thought you might be -- looking to adjust your laterals as well. But that's helpful.
Yes. And it really depends on the play. We have drilled longer laterals down in Brazeau, in the [ flair ], for instance. And maybe in Whitehorse, we can look at doing some longer laterals in that play. The Cardium is a little trickier to do the longer lateral in, though, with all the other considerations.
Our next question is from Thomas Matthews from AltaCorp Capital.
Just wondering if you could comment on those cheap cut costs on the construction of those. And what you kind of see as the paybacks, given the current pricing of the liquids?
We're still in a process of determining the costs for the installations. So I can't really comment on that. I think next conference call, we'll probably be able to provide more detail on that. But from the range of costs that we expect, we're looking at a couple of year payout, maybe a little bit longer then, two, based on current propane, butane and condensate prices. So it's a good project, particularly when you know it's going to address an extremely long reserve life. It's really going to enhance an existing -- our existing infrastructure, we've got about $1 billion of plant infrastructure in that Sundance area. And by installing these plant additions, we'll really enhance that infrastructure for many years to come for our resource, potentially for other people's resource if they -- we choose to bring in some third-party resource because of a -- our low costs and our ability to recover high liquids. So back to your original, a couple of years is what we're looking at on a payout, simple payout basis.
I think Thomas -- Scott, what was the original Deep Cut cost versus what we...
About $30 million?
$30 million.
$30 million to cover about [ $80 ] million a day of -- inlet volume. So we're looking for something cheaper than that. The new design, we hope, is going to be less intense capital cost for the volume. But again, we're in the design phase there looking at recoveries, and then we'll translate that into what the capital components will be. Hopefully, the timing of some of that construction will come at a time when industry is still pretty quiet. And so we're not competing with a lot of other developments or if I suppose oil went rushing up to $100 then, we'd be back in the oil sands and we'd be trying to build these things at a time when the oil sands are taking all our labor away. But I don't see that happening here over the next year or 2.
A lot of the fab shops are quite empty right now, so it is a good time. And one of the other features that we're looking at, if we do 4 of these back-to-back, we see some real cost advantages in doing them sequentially and building the gear, which will be somewhat standardized and then installing it, having the crews install it, jumping from one project to the next, to the next. So the continuity of that will lend itself -- we're optimistic it'll cut multiples of tens of percentages off the total scope of the project.
Yes. Not unlike a multi-well program cuts costs from a single-well program. It would be a multi-facility program that would have, hopefully, the same kind of cost savings associated with it.
I think too -- we've had 4 years to refine this kind of innovative design, that original cheap cut. So we've worked the bugs out of the systems. So now we're confident that we can go ahead with a larger capital spend on 4 or 5 plants and not have to go through those growing pains again. We've done that so...
And how much volume would you cover then once all 4 projects are complete?
$400 million.
$400 million.
Round number, $400 million of our $600 million of raw gas production.
Okay. And then on ...
5,000 barrels of liquid roughly, maybe a little more than that based on the recovery factors that we anticipate.
Yes. And that 5,000 barrels would be incremental on your current gas volumes? I mean, that -- that's not new drilling, that would be just extraction from current volumes?
Yes. Exactly. And as you know, as we note that if we're focused obviously this year on a lot of Cardium and liquids-rich Wilrich, we're going to see our liquid yields still climb over where they are today. You know, we're close to [ eighteen ] barrels a million currently. And we would expect that a year's worth of drilling, backfilling dry gas declines with the liquids-rich declines, we'll see corporate yields rise higher, north of 20 barrels a million, I think, by the end of the year. And that's before we start to strip anymore liquids out.
Our next question is from Brian Kristjansen from Macquarie.
Apologies if this got mentioned at the onset of the call. But the savings on Whitehorse on the drill costs, can you -- is that applicable? And can it be permeated across all the Spirit River activity?
That's a tough one to address. As a whole, no. We were actually discussing that earlier this week in some discreet instances where we may be able to shave that intermediate string out of our design. But for the most part, the Greater Sundance Area, our -- a combination of our -- a [ hole ] loss issues, borehole design, borehole stability with the coals, and the inherent pressure associated with those zones predicate that we -- the bulk majority of those wells needs to receive that intermediate string of casing. So unfortunately, it's not that we can't apply it across-the-board. Even a little bit further south in [ Pico ], we're struggling with adequate confidence in implementing that design there as well.
Yes. So by the way, it's a combination, I think, of -- what would be wellbore pressure, depth, some of the borehole design and experience within the area, right? So Whitehorse was a newer area for us. We hadn't seen a lot of drilling -- we hadn't done a lot of drilling. So when we got in there and started to evaluate it, we knew there was potential for cost savings. You know, we looked at something like the high-pressure Notikewin play in West Brazeau, obviously. We can't do it there because we've got more risks associated with the reservoir pressures and the depths. And so we've got to take more precautions but, you know, the Deep Basin's like that. We've been up and down the Deep Basin over 20 years now, and so we've gained all kinds of experience from all the drilling that we've done. We've been one of the most active drillers in the Deep Basin and gaining all that experience over all those years helps us get to a lot of these costs savings a lot faster when we get into these new areas. So Whitehorse is just a -- is a good example of that.
I mean, relative to your planned budget in 2018, could you estimate what sort of impact -- I mean, what percent of the program could use the -- would need -- would not need intermediate casing? I'm just trying to quantify what your potential capital efficiency gains would be corporately.
Yes. So our capital program for the year, it's still a little flexible. Obviously, it depends on some of the outcomes of the some of these Cardium wells. But there's no question that we're rerunning our Whitehorse economics with heavier liquid rich -- Wilrich, which -- experiencing down there. And these new drill curve, drill times and drill costs, those economics are going to improve. So we're always responsive to the most recent information that we have, Brian. And I think we're always looking at maximizing the returns on all the capital dollars that we're putting to work. So the program for the year is going to remain flexible. We're going to continue to follow up on those results that give us the best returns. And if, for instance, Whitehorse has better returns than even the Cardium within Sundance because of these new drill costs, then we're going to push to get more inventory drilled there than even the Cardium gives us. It really just depends on those combination of costs and cash flows and what kind of return we're getting in total. So Whitehorse has some other challenges, though, from a process standpoint. Right now, we're going through a third party, while we're going to get our plant built over time. So we've got to look at the timing of those capacities and our ability to bring on new volume there, too. So there's a bunch of considerations, obviously. I think our original plan was how many wells in Whitehorse versus the Cardium and Sundance. JP?
Well, we would have had maybe 5 more to drill depending on the timing of the new plant and the capacity of the existing system of our current third-party processor. So...
So 10% of the program was going to be sort of Whitehorse and 90% Cardium. But like I say, that's going to change and evolve as the year goes by.
Our next question is from Fai Lee from Odlum Brown.
It's Fai here. Darren, I'm just wondering about your -- how to think about your hedging strategy. I get that you're trying to mitigate risk over time and be methodical about it. But looking at some of these prices, particularly in the summer months in 2020, in 2019, they seem well below your supply costs. And I'm just trying to understand how you think about the balance between risk management and, I guess, trying to maximize your return.
Well, it's a good question, Fai. I mean, I don't think there -- the -- our full cycle supply costs potentially, yes. So all new capital investment is obviously being measured against the strip. And so we have to feel confident that the forward curve is going to give us good enough return on the capital to justify investing that. The hedges are really for past capital. It's the protection of cash flows on those past capital investments and those past assets. And so we're looking at what is that future curve look like. I think we've seen evidence in the last couple of years that the AECO price can be particularly weak in the summer, especially relative to, say, the NYMEX price or some sort of other benchmark North American natural gas price. A lot of that is, in some ways, almost artificial because it has to do with how the pipeline system is being operated, local access to storage, whether certain service is being given priority over other service. And we've only just come to appreciate some of these in the last year or so with the way TransCanada has changed the operating of their system. So we're looking forward at summer prices for the next couple of years without any change to the current egress situation and thinking that there needs to be good protection there. The couple of basis deals that we did to get ourselves started, to get ourselves exposed to the NYMEX price are for summer periods again to try and protect some of those summer prices. I agree with you that the summer prices even at the strip right now look really unsustainable and they look like prices that we shouldn't ever have to experience. But we've just come out of a year where we've had negative prices in the summer and fall months where there's no access to storage. So we're a bit in uncharted territory. There's no question. We should never have to see these kind of prices and industry shouldn't be -- experience these prices. And hopefully, going forward here, these hedges are going to be underwater. That would be a good thing, in fact, that we're -- we've locked a little bit of gas away at a price that's so low, it's unsustainable. And the rest of the gas we've got is going to get a much better price. But -- and -- but that's going to mean that the industry has become very responsive to the price. And that when the price starts to get soft, when the demands are low, industry throttles back its production. And that's just a behavior we didn't see last year. We were looking for it. We did it when gas prices got weak, we shut in our day gas, and we expected the industry to respond the same, and they didn't. They kept pounding gas down through the pipelines and driving the price down to negative levels. So going forward, what are we going to see? Are we going to see more response from the industry? I sure hope so. But it's hard to predict as well what the behavior of the shippers are going to be like. Are they going to change the way that they're operating their system this year, more in response to soft gas prices or not, have pressures from places like the Alberta government come to bear on them to say, "Look, you can't be fooling around with your system and driving AECO prices negative because our royalties go 0. And we can't handle that so you need to change the way you're operating your system." I don't know. Again, we're in somewhat uncharted territory, unfortunately.
Yes. And regarding [ like a ], you mentioned that you are evaluating new projects relative to the strip. Is the strip like -- it looks pretty close to the supply cost and, correct me if I'm wrong, even your lowest supply costs. And so it seems kind of hard to justify being only generate return based on the current strip. Am I missing anything in that statement?
I think with historical costs, that you're right. The current strip is giving us just enough that we cover our supply costs, maybe a little bit of profit, but definitely not the profit that we're used to and that we want. And so that's why we're grinding away on costs in every place of our business. All of our cash costs are under scrutiny. How do we get those down by another 15% or 20%? Todd talked about some of the operating cost initiatives that we've got underway. Kathy talked about the fact that we're going to pay down debt, reduce our interest costs, keep our G&A costs really low. And then on the capital side going forward, we're going to look at the -- where we're going to invest capital. It's got to be more liquids-rich wells, the Cardium has more robust economics obviously, the Whitehorse area is looking like it has some robust economics not only with the liquids rich, but also the new drilling costs that we're seeing. So we're only going to put capital towards things that make us that return hurdle at the strip. And obviously, that -- some of the stuff that we've been traditionally drilling isn't going to get us to that return hurdle that we're looking for. A lot of the drier gas just doesn't work. And that's not just us. I mean, that's pervasive across the basin now. You're not going to see anybody touching anything that's probably sub-40 or 50 barrels a million. And the question's going to become, how much of that do we have as an industry? And does the basin really offer? And is it enough to even backfill the decline?
And given what you've experienced over the last year, how does the infrastructure problems that you've faced influence what you do going forward?
Well, obviously it's a big consideration, right? Because it's setting the price, the lack of egress to where the supply is coming from, lack of ability to get to export markets to a better price. That's what's driving us to look at a lot of these new ventures to, say, what are -- what kind of price can we get if we keep the gas right off the pipe altogether? And is that a competitive price? Do we get to a supply cost then that brings a lot of these plays back into the realm of economic interest? And I think that we will be successful doing that and that there will be opportunities to do that. So we don't have to rely on getting the gas out to a market that really has become a lot more competitive. The U.S. market obviously is self-sufficient now and so busting into that market with a high toll to get there just doesn't work. And so we're looking domestically, we're looking locally, how can we convert our resource into a greater value and keep it off of that risk of all of that export system?
[Operator Instructions] At this time, I'm showing no further questions. I would like to turn the call back over to Darren Gee, President and Chief Executive Officer, for closing remarks.
Okay. Thanks, Gigi. And thanks to everybody for listening in and participating in our conference call. Like I said, we had a very successful 2017. But really the focus is turned on to 2018 and the future and, obviously, some very challenging-looking future natural gas prices for an entire industry. We've got, I think, a very strong plan in place to deal with those prices and to ensure that this business continues to move forward successfully in that environment. And we're going to have some very neat things to talk about in coming quarters, some of these new ventures and -- as well as some of the results from some of our drilling opportunities and drilling initiatives here as we move throughout the year. So it's going to be another challenging but exciting year at Peyto. And we're all up for the challenge. So we'll be talking to you in subsequent quarters. Thanks for calling -- or for listening in.
Ladies and gentlemen, thank you for your participation in today's conference. This concludes the program. You may now disconnect.