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Good day, ladies and gentlemen, and welcome to Peyto's Year-End 2018 Financial Results Conference Call. [Operator Instructions] As a reminder, today's conference may be recorded.I would now like to turn the call over to Darren Gee, President and CEO of Peyto. Sir, please begin.
Thanks, Mark, and good morning, ladies and gentlemen. Thanks for tuning in to Peyto's Fourth Quarter and Year-End 2018 Results Conference Call. Before we get started today, I would like to remind everybody that all statements made by the company during this call are subject to the forward-looking disclaimer and advisory that we set forth in our news release issued yesterday.In the room with me this morning, we've got Kathy Turgeon, our Chief Financial Officer; JP Lachance our VP of Engineering and Chief Operating Officer; we've got Dave Thomas, our VP of Exploration; Lee Curran, our VP of Drilling and Completions is here; and we've got Todd Burdick, our VP of Production. Unfortunately, Tim Louie, our VP of Land couldn't make it this morning, but we're here to answer your questions.So before I get started with just a few introductory comments today and our results, I did want to recognize the efforts of the entire Peyto team, including all of our field personnel. It was a busy fourth quarter and year-end, with a lot of drilling and completion activity in the field and a lot of new wells coming onstream. And of course, we had some on-again, off-again winter weather in the fourth quarter to deal with. But as usual, our team did a great job. So on behalf of all Peyto shareholders, I would like to say thank you to the entire Peyto team for that effort.So just a couple of quick comments this morning before we get started with questions, from those listening in, I think we'll try and keep this brief and we'll try and keep the e-mailed questions that we received overnight to the end.As mentioned in the release, this was our 20th year of operations, which is a major accomplishment, in and of itself, even more impressive I think that it was our 19th year in a row of earnings, which really speaks to the success of our strategy of focusing on returns and delivering real profits to shareholders. This is a particularly tough industry to post that kind of track record of profitability, especially considering the ever increasing volatility that we've seen over the past 19 years. So a big congratulations to the entire Peyto team for that major accomplishment.2018, of course, was another challenging year, especially with the low natural gas prices that we experienced. It wasn't just gas, actually in the fourth quarter, Western Canadian Select oil prices came under significant pressure. And while we're not a heavy oil producer, it did put pressure on condensate demand and reduced prices as well, and we did feel that.For some perspective, the average AECO daily price of $1.42 per gigajoule in 2018 was the lowest price we've seen since 1996. So that means it was the lowest price we have ever seen in Peyto, since we started in 1998.But despite the low price, we had put in place significant price protection for 2018. I think we ended up pre-selling around 90% of our gas for the year, at an average price that was more than 55% greater than the average AECO price. So we were well protected.We did, of course, shut in some spot volumes in the summer when prices were negative and obviously, it didn't make sense to keep producing. But overall, our exposure was quite minimal.And we're sitting in about the same position this year, with the majority of the 2019 gas price already predetermined for us. Beyond this year, we, as well, have significant portion of our gas volumes tied to the NYMEX price, not at AECO, in fact. So I think more than 50% of our 2020 volumes are not exposed to AECO prices.So all in all, I think our market diversification strategy that we brought in place, early in 2018, is paying dividends and significantly reducing the risk of continued volatility at AECO and particularly weak summer prices.Personally, I think the most exciting thing that happened in 2018 was with our Cardium plays. As many know we've been a Cardium producer for 20 years now. But we haven't been focusing on the Cardium over the last few years much because higher gas prices have led us to develop the leaner, tighter Spirit River formations. But we tried a new completion design in late 2017, early 2018, on the Cardium and that was yielding much better results. And so we spent a lot of 2018 testing this new completion out in various areas across our land base. We tried wells in Kakwa, down in Brazeau and all across our greater Sundance complex. And we also tinkered with the design a bit to see if we could optimize it further. I think we'd say today that we're close to having the right recipe.One thing we did at the end of 2018 was to start integrating all of our geological, geophysical, reservoir, drilling, completion and production data that we have on the Cardium, as well as all the penetrations through the Cardium that were done when we were drilling deeper Spirit River formations for all those years.And now we have what we believe is a very, very sophisticated, predictive tool to high-grade future locations. We've only used it on the last handful of locations, but we back tested it and it appears to give very consistent results. So that said, we believe that we should be able to improve upon our Cardium results even more, with our 2019 drilling program, which should result in increasing the production tight curves and even better economic results. So we're very excited about that going forward with the Cardium.Overall capital and cost efficiencies continued to improve with F&D costs and the cost of new production getting less each year. We expect to do that again in 2019. We are always focused on cost here at Peyto. So we're going to keep pushing them down. And we've got a much lower base decline this year at 25% versus 35% in 2018. So it's going to be easier and take far less capital to hold production at this level in 2019. And that combined with the reduced dividend level means we'll have plenty of free cash flow in 2019 to pay down debt. As a default, I suppose or perhaps look at some interesting opportunities that this current environment might create.And we also have our Montney play, that is moving along. We're not in a big rush but we do want to get that completion done, but done as cheap as possible. So we're looking to do it in the summer. We'll grab the frac crew that's driving I think by or one that's nearby doing a Cardium completion for us in Wildhay and take advantage of that. But that could really be a very exciting result, so we're looking forward to that here just after breakup.As far as land goes, Tim is not here today, but we continue to add a lot of drilling inventory for very little cost at land sales. In 2018, we acquired a lot of new land, both Montney lands and Cardium lands, all for less than $100 an acre.And all this land we believe has drilling locations on it, so we've added to our inventory of locations. And then in Q1 of this year, we've already been really busy with the land activity. We bought another 49 sections of Cardium rights for half the cost really that we paid in 2018, around $50 an acre. And with our new prospecting tool, we think we have another 80-plus locations on these new lands. So we're adding inventory at a much greater rate than we're drilling it right now, but it's a great time to do so. And of course this is all liquids rich drilling inventory that will continue to increase our corporate liquids ratio as we drill it up.With respect to liquids, we mentioned in the release that propane and butane prices right now are particularly weak. And this is really because all the gas producers are chasing liquids rich gas and because of the low gas prices, right? And so as an industry, we flooded the propane and butane markets a little bit. We've got very high inventory of butane right now. And so on the screen, the price is trading at a very low level and it's likely going to take until later in the year to clear that storage glut that we have in Edmonton before we see price recovery. Propane will likely recover a little sooner as Ridley Island comes on I think in April here takes 40,000 barrels a day of supply away from the Edmonton market. But in the meantime, we warmed up our plants, changed the operating conditions. We've turned off the deep cut plants at Oldman and we're rejecting as much of the propane and butane as we can into the gas stream because we get better price for it there, especially with gas prices as strong as they are today. And again that just speaks to the advantage that we have at Peyto, owning and operating all of our plants that gives us that flexibility. If we were going through midstream processors, we wouldn't get that kind of flexibility. But that's something we've always done here at Peyto. So all in all, I think a very successful year in 2018, and we're looking to improve upon that in 2019. So we're excited about moving forward here. That just about sums up my comments. Mark, maybe we can throw it open to listeners, and see if there's any questions from those listening in.
[Operator Instructions] Our first question comes from the line of Michael Harvey of RBC Capital Markets.
So kind of a 2-part question, as we get to the completion of your Montney well. Can you give us a sense of what you consider to be a success there in terms of early results. So what kind of test rate or liquids content you would get more excited about drilling additional wells there. And then the second part, how do you plan to process the product there from Wildhay, just particularly if you find it to be significantly sour?
Thanks for that question. The Montney sits in an area where we've seen a little bit to the southwest of us, evidence of sweet gas or very low concentration of H2S. And then further to the northwest of us, sorry northeast of us we see, obviously, higher H2S concentrations moving up from 1,000 parts per million all the way up to probably 7,000 or 8,000 parts per million as we move further away. So we're somewhere in the middle there, not quite sure what we're going to get with respect to H2S content. We can handle about 500 parts per million through our sweet infrastructure. We have to do so some chemical sweetening at the wellsite. But beyond that, we can take that kind of gas stream into our sweet gathering system and into our sweet gas plant at Wildhay. So we're hoping that we get something at that level or lower that we can then deal with, which would be quite easy. That well is drilled from an existing Cardium wellsite that's tied in today. So it's a really quick and easy tie-in. If it's much more sour than that obviously then we've got to look at sour processing options that we have. There are some in the area, obviously, there's an operator just to the north of us that's drilled wells that are more sour than that. They go into, I think, it's Repsol sour system, for third party processing. So we can test drive either through a third party system or we can just test the well and leave it capped while we design and build our own sour processing capability, which is something that we have as an option to us for sure. As far as the test rate and the liquids content that we are expecting, we've looked at the well. It looks like it's got some very interesting geologic attributes to it. Some permeability streaks in it that look like it could really be quite productive. So we are kind of excited about that. I do want to get to that test and see exactly what this thing is capable of. We've seen tests in the area. I don't know, JP can you comment on the type of variability that we've seen from a test rate perspective?
Yes, certainly we've seen, I think, the most important part of it is the liquid content. We've seen liquid rates at 40 to 60 barrels a million. So I think that's the target, that's the desire or the outcome for us. Gas rates, it's hard to tell. We're keeping a close eye on some of the offset production in the area. So it's our understanding that those wells might be restricted. So it's hard to know for sure what we're going to get based on the offsets. But certainly you don't want to -- if we do get a sour outcome, we're prepared and we're looking at the design of expansion of our Wildhay facility to accommodate a sour train. So we got the engineering work going on as a backstop in that situation. So ideally, sweet.
Mike, I don't think we're going to half-half the completion at all. We're going to try and give this a full shake, even though this is the very first well into the land base, and it's a bit exploratory and the tendency would be to sort of cheap out and maybe not. Do a full-blown completion, I think we really do want to do a completion that will be an indication of what 2 developments going to look like. So we do want to give it the full shake, which means also that we're pumping a lot of water and, obviously, the cost to eat that water is significant in the wintertime, which is one of the reasons we want to push it off after breakup into the summer.
Got it. That's helpful. And that 40 to 60 barrels per million is that just condensate or is that kind of a whole bucket?
I think that's the whole bucket from the gas analysis we've looked at. It looks kind of similar actually to a Cardium well. So we would expect to get what about, 10 barrels a million of propane, 10 barrels a million of butane, and then the balance, 20 to 30 barrels of C5+ condensate equivalent.
And our next question comes from the line of Brian Kristjansen of Macquarie.
What should we be using for transportation cost in 2019? I know you've got $52 million of commitments, but in 2018, you actually came in about 11% less than what was originally committed then. I'm not sure if that's selling down some firm service or not or what do you expect?
You're right, Brian. We do have some excess firm service because we, obviously, had firm for a higher production volume than we have today. We're at I think at one point, about 115,000 BOEs a day, so we had firm coverage for that. So today, down under 90, we've got some excess, which may prove to be beneficial to us if there is some curtailments in the upstream James River area. We have seen some just recently in the early part of 2019, so we've taken advantage of some of that service. But the majority of our marketing arrangements are actually basis deals. All of our NYMEX exposure is through AECO NYMEX basis. So our physical commitment is really just to deliver gas to net, and so we only need to hold transportation for that piece, which is effectively just the Nova transportation, the $0.17 or $0.15 from the Greater Sundance Area. So our transportation costs, we are forecasting are going to stay in line with what we've seen in the past. They're not going to jump a lot. We don't have a lot of big long hole pipe commitments today that we're going to have to pay for in 2019. So it should be very low transportation costs. But again our realized prices, of course, are going to be net of those basis deals that get us to those other markets outside of AECO.
All right, okay. And can you provide us what's the delta in the recoveries you're expecting by turning down the deep cut facilities. I know you projected 27 barrels a million in 2019. Is that with those propane and butane volumes getting rejected? Or would that be 22 or something?
Yes, the 27 would definitely be with the deep cut running. We've got, I think, we were about 25 barrels a million just coming into the start of the year. By shutting off the Oldman deep cut, warming up the Oldman plant, the Oldman North plant, and a few of our other plants, the refrigeration process has warmed up a bit. I think we dropped about 3 barrels a million. That's what we've lost on the liquid yield. Of course, we make that up in heat content in the gas and because gas is trading at $3 a gigajoule or more these days. We more than make it up in terms of cash flow. So it makes good sense financially to do that, but as soon as gas prices drop off again, relative to where the propane and butane prices are, then it all makes sense to start to extract those products again. So there's a pretty steep cliff really between the current AECO price and the forward curve. Summer prices are still projected at about $1.22, which is, obviously, a pretty big drop from the $3 we're seeing today. I think somewhere around $1.50 to $2 range when we pass through that price, depending on what propane and butane prices are, is sort of the cut-off for going back to the liquids -- maximum liquids extraction mode of operation. So we'd expect probably April-ish timeline. We will be looking at kicking the deep cut back on again and cooling the plants down again. Of course, this is all very volatile, as you have to be very dynamic and you have to watch costs and prices daily, really. But the reality is and Todd, maybe you can chime in here, the cost for us to turn the deep cut off and turn the deep cut on, to warm up the plants and cool them down is immaterial. How long does it take?
It's literally in the case of the deep cut, the plant has to be down for 1 to 2 hours. And so it's really just a migrating crew $3,000 to get some guys out and swing some pancakes, really some speck lines that sort of stuff. So it's done very quickly. And at the plant themselves, it's just a matter of just increasing or decreasing the heat. How much we're cooling the gas going into the LPS's and that sort of stuff, so it's done very quickly, very easily.
Brian, there is an optimization, of course, because we want to maximize the C5+ recovery. So any pentanes that are in the gas stream if we warm up too much, of course, then we don't strip those out. And of course those are worth a lot in liquid form way more than the gas price. So we want to make sure you maximize the C5+ recovery. But in the current situation obviously with C4 butane prices so weak and propane prices not that great either, then it makes sense to leave those ones in the gas stream. So it's a delicate balance no question but, of course, we operate all our plants. We understand exactly the process that the gas goes through and exactly how to tune our plants to maximize that cash flow.
Any marketing arrangements in the works for propane? I know some of your peers have entered into some longer-term deals?
Yes, for sure. And we are one of those operators that we get the fractionation of the product, we take it and we can market it on the back end. And we've done a lot of that. Obviously, we entertain and engage and enter into these longer-term contracts, not just spot contracts for our liquids because we have quite a bit. We're 2,200 to 2,500 barrels a day of propane and it's about the same of butane. We've got 5,600 barrels a day or so of C5+. So we've got a lot of concentrated product. We're pipe connected with a lot of our clients in the greater Sundance area, so it's efficient. And we can do a lot of those marketing arrangements. And we've looked at a lot of those. We're not disclosing those contracts, the terms of those contracts are kept pretty confidential and so we're not bragging about them necessarily. But we're definitely entering them for sure.
Okay, cool. And just on the move to integration, what do you expect costs to be -- to get Big Sunny operational in 2019 and 2020. And then you referenced in your presentation -- your corporate presentation how you potentially participate in capital ownership in electrical generation. When does that decision get made?
Yes, so the Big Sunny storage scheme, we've just closed that acquisition. Obviously, we're looking at the scheme itself doing a bunch of the planning and engineering work that's required there. There is an existing vertical well that we are going to go and obviously put some pressure recorders in, watch over break up here. Then when we get to the summer, we'll look at potentially connecting that well and using it initially to inject gas into if we get some really weak summer prices. The base gas, when you want to use the cheapest gas you can. So if there's the opportunity there, where gas prices are zero or negative we'll then -- and we're going to be exposed to that or else shut in. We'll just put that shut-in gas into the storage reservoir instead. We've got to get the pressure up a little bit before we can drill new wells into the pool. We would want to drill new horizontal wells into the pool, open-hole horizontal, they don't need to be fractured or anything of course because it's really high permeability rock and those wells are relatively cheap. I think a $1.5 million to $2 million was kind of the number that was tossed around.We need to get the base gas in there pressure up at a little bit so that we can safely drill even under balance because the pressure in the reservoir is very low. And then once we've drilled the few wells, which we wouldn't likely do until I would say at the very earliest it would be like the fall of 2019 or the winter drilling season of 2019, '20. I think at the very earliest. Once we get those in, then we can look to do some testing. So say we drill 3 or 4 of those wells, we have very -- the expectation is they will have very high injectivity productivity something in the order of $50 million to $75 million a day each. So we could give ourselves about $150 million to $200 million a day of injectivity productivity. And then that over, say 150 days of either withdrawal season in the winter or 200-and-some days of injection season in the summer gives us a working range of somewhere in the order of 15 to 20 Bcf, that we could either put in or take out. So once we tested the wells and established a sort of working range that we're looking at, then we will order the equipment. It's mostly just compression and dehydration. And that's where the bulk of the capital dollars are. So for 2019, really we're not looking at spending very much at all, maybe a well or 2 this year. And then we would order the gear in 2020 depending on the time line of that equipment, get it in place in order to start injecting, obviously during the summer period.
And then could you address. I don't know if that is a legitimate decision that's going to happen in the short term with respect to taking capital ownership of some power generation?
Oh yes. And so we're looking, obviously, at opportunity to sort of extend that value chain, even become an owner in some of this power generation. Companies like Tidewater, for instance, they are building pipelines to power gen plants. That's something we could easily do, like probably do it a lot cheaper. So we're looking at that kind of opportunities. And if there is an opportunity to be an owner to put capital into a new power generation facility, I think we would look seriously at that. That's just part of that entire integration effort. If we're going to be selling our gas in the form of electrons anyway, through power deals that we have already done, maybe we want to even be an owner there. So those are opportunities that are coming down the pipe. There's going to be a lot of gas-fired power generation conversion and new build, I think, in Alberta over the next several years. So we're really staying dialed into that market as much as we can to perhaps be a more significant participant there.
And I'm sorry to continue. But would that be sort of a '20, '22 style time horizon? Or would that potentially come sooner?
Yes. I don't think the cap -- any capital investment there would be prior -- it would be 2021 to 2022 at the earliest.
And our next question comes from the line of [indiscernible].
I was just wondering, what is your short-term and long-term goal?
Me personally or for Peyto?
For Peyto. For Peyto.
I'm just joking with you. Peyto has been in business for 20 years now, and I think we've proven when we focus on maximizing the return on every dollar of capital that we invest here, that is the strategy that has paid dividends and rewards obviously to shareholders over the long term. And that will continue to be our goal. We are believers in natural gas as the cleanest burning fuel -- hydrocarbon fuel that we have out there. And after this winter, I'm a very strong believer in natural gas considering the cold weather we've just had for last month. And if I didn't have it heating my home, it would be very uncomfortable. We've long been believers in natural gas. Obviously, we've been a 20-year natural gas company. Oil still seems to be that magic fuel though when it comes to pricing. I think Canada can do a lot more with respect to its natural gas resources to help the world with respect to climate change. There's a lot of coal still being burned around the globe that we can displace with natural gas and Canada has a lot of it and if we would get after it and start exporting it to other countries who need it, I think that would do a world a good. And so we'd love to be a participant in that. Here locally obviously we are an Alberta-based company. All of our assets that we've developed today, all the wells we've drilled, all the lands that we bought are here in Alberta. We're helping develop those Alberta resources. We pay a significant amount of royalties to the Alberta residents via the Alberta government every year and have for the last 20 years. And so here we are investing in our home turf, which is something we're proud of and that's something we want to continue. So our goals are very similar to what they were when we started Peyto. It was investing capital to generate profit through the most efficient development of the resources that we can find and discover here in Alberta.
Our next question comes from the line of Fai Lee of Odlum Brown.
In terms of the -- your commentary in the press release today the free cash flow that you have, you're expecting this year, you mentioned possibly paying down debt. But you also referenced something about unique opportunity. Just to be clearer, we like we're talking about taking advantage of land expiry that you talked about back in January or is it something different?
Well, we're always open to new opportunities, Fai. I think anything that has a real big potential to generate return for shareholders is something we have to be looking at and, of course, want to be looking at. We think based on the current commodity prices and our forecast that we're going to have more free cash flow, if you will, in 2019 than we even had in 2018. And the default is, of course, to put that on the debt, to lower the debt, but we are still looking at lots of opportunities. To your point, I think the land sales that we participated in to-date are good example of that. They don't cost a lot. We're picking up a ton of drilling inventory, really good quality drilling inventory. We think we've got hundreds of locations effectively on the lands that we just bought in the last year in a bid. So we don't want to miss out on that either. Just putting money on the debts, accretive for shareholders in the short term but long term if there's some opportunities for us, we definitely want to be looking at those. As you know, we don't spend a lot at Peyto for those opportunities. I think our historic land spend has been maybe 1% to 2% of the total capital that we have spent in over 20 years. So we've managed to secure all of the opportunities that we've harvested to-date for very low cost. But we watch them and we only participate at certain times in the cycle too. And this is one of those times where cash flow is tight for everybody and companies seem to be wanting to put that excess cash or free cash flow that they have, either on debt or buy back stock. There's not too many guys that are really looking at the inventory and opportunities. I think most guys think that they're kind of fat with the inventory, but if we're getting brand-new lands today, they have a 5- to potentially 10-year time horizon on them. And when we're looking out 2 or 3 years to when the egress starts to expand and the market starts to free up a little bit and the expectation is obviously that we get little better gas prices linked to other markets a little better. That's when we're going to really want a lot of this inventory. So fresh land is important, land that we either buy from somebody else or that have a shorter time line on them. Don't really do us a lot of good 3 years, 4 years from now. So brand-new land actually that comes with a brand-new time horizon on it and expiry clock on it is more valuable to us for sure. Now we don't have a lot of expiry situation because we've got the layered stacked formation. So a lot of our lands have been continued with drilling either through the formations or with old vertical wells. But there are a lot of producers out there today who have a lot of their undeveloped land that only has 2 or 3 years left on it. And that means that they're really not going to be able to harvest that opportunity on those lands within the horizon while we're waiting for just the market to expand. And so here's an opportunity for us that I think we need to jump at it to load up with as much potential inventory so that when we do get 2 or 3 years out and we can really start to grow aggressively again, we've got just a ton of opportunities to chase.
Okay. And back in January, you talked about pursuing marketing of your midstream processing given I guess the current NGL prices I'm just wondering how that initiative is going right now.
Yes, JP you want to comment on that?
Sure. Yes, we've met with several operators already. Just to bring gas into one of our plants, we'd estimate we got about 300 million of processing capacity available across the entire infrastructure that we own. So we've talked to a lots of different folks, and one of the advantages we have of course is that our low operating cost allows us to be very competitive when it comes to other options for those operators. So we've had some encouraging conversations. Nothing firm yet, but certainly some real interest.
Okay. And just a question, a technical question I guess. In terms of, if you have a situation of higher propane but depressed butane, I don't believe you can just isolate the propane, you have to take the butane, is that correct, as well?
Yes, you're right, Fai. The propane comes first because it's the lightest. So as we start to cool down, it's the one that condenses first. So it's a bit tricky to recover propane but reject butane. That gets really challenging because it's the heavier hydrocarbon. So you got to cool down to get the propane out. But you warm up the rejected butane back in, it's not part of the process or the way in which we can really run our process. So you're absolutely right. When we are running the economic opportunity and what's the maximum cash flow that we can achieve from the production stream, one of the considerations is what is propane prices doing and if propane prices get strong enough, then we would be condensing butane out to get all the propane and having to expose that butane to a low price. So the way the timing is going to work here though, it looks like to us, that come April-ish that's when Ridley Island, I think comes onstream. That's probably the first real positive pressure on propane prices we're going to see. It's also about when gas prices are forecast to drop quite a bit. So we would likely be kicking our deep cuts in and cooling down our plants anyway right around that time. And so we're probably going to be changing our operation mode back to what we have before to get the maximum amount of propane out because propane prices are going to be quite a bit stronger. And it's not going to be as big a deal because gas prices will be lower anyway.
Sorry, just to clarify, to get propane you have to cool it more, right, because it's the lightest, isn't it? Or...
No, propane comes out first.
[Operator Instructions] Our next question comes from the line of Adam Gill of Eight Capital.
Just with regards to the positive results that you've initially seen on the kind of big data initiative on the Cardium. Where do you think the high end of the liquids yield could be corporately at the end of the year into 2020. Should you continue to see the success that you have?
That's a great question, Adam. Because we've really seen a lot of variability in the Cardium that we've been drilling. I mean as a base sort of liquid yield from the Cardium, we are running the average Cardium that we produce from today is probably around the 45 barrel a million mark, 10 barrels a million of propane, 10 of butane and the rest is C5+ condensate and pentanes. But we've seen liquid yields from some of the early flush production from some of these new wells as high as 150 barrels a million and maybe even more. And of course all the extra is condensate. So we're hitting pockets of more liquids-rich Cardium whether it's natural fractures that are spitting out that condensate or whether it's just -- there's been some concentration of heavier hydrocarbons in that particular area. We're obviously targeting that because those economics are even superior to the average Cardium well. And that's factoring into this algorithm that we've been running to target which Cardium wells we drill first. We want the highest productivity, best reservoir quality, but also the highest liquid yields. So we do expect that if anything we're going to err on the side of higher liquid recovery, higher liquid yields, then the average Cardium well that we are modeling. But it's just a kind of thing where we are just going to wait and see. And yes, we expect that we're probably going to get better. We've seen that indication. We just don't know how much though. It's kind of a tricky thing to try and forecast.
I'm not showing any further questions at this time. I would now like to turn the call back to Darren Gee for closing remarks.
Okay, well, thanks, Mark. We did get a question overnight from 1 investor that was e-mailed in asking about the dividend and asking about our earnings projection for 2019, and were we looking to match dividends to earnings.The answer to that is really that our projection for earnings for 2019 is far greater than what we're going to be paying out in dividends. So we have taken a very conservative approach with respect to the dividend this year as far as matching it to actual earnings, keeping more of those earnings in the organization, if you will. Using them to pay down debt and perhaps using them for some unique opportunities that we do see coming down the pipe. So we do expect earnings are going to be far greater than what we are dividending out to shareholders. And then one of the other questions that came in was one on liabilities. Obviously the Redwater ruling that came out in the news shocked the industry a little bit. Definitely it gave the bankers a bit of a pause with respect to the industry, knowing that they were potentially on the book for more liabilities than what they thought before. And so of course to provide some clarity to our bankers, we've gone through, as we always do and updated our liabilities. We report them in our annual information form every year and in our sustainability report every year. But Peyto is a very unique situation and that we have this asset base that's been entirely developed organically by Peyto. And so we are, by far, one of the cleanest companies in the industry with respect to environmental liability. We have very few abandonment liabilities. At the end of December 2018, for example, we owned 1,475 net wells, 91% of those wells were on production, 1,344 producing wells. There's about 130 nonproducing wells. And out of those 130 wells, the majority are still capable of production, but are either shut in because of low gas prices or they are a little too far away from a tie-in right now. We only have 23 wells that are scheduled for an abandonment of some kind, whether it's zonal suspension or full abandonment and reclamation over the next few years. So very few, really, true abandonment liabilities that we have to deal with and we're dealing with them on our schedule, but we are not worried about them and they don't represent a large capital cost to us. So we have a very, very clean asset base. Of all those producing wells, of course, in our reserve report, we capture the value or the cost to abandon those wells at the end of their life. So that's captured in our valuation when we do our reserves. On top of the wells, of course, we have facilities, wellsite facilities, we've got pipelines and we've got gas plants that we're going to have to look after at the end of their life. And in each of those cases or maybe not pipelines, but for sure wellsite equipment and that facilities, there's some reclamation of the existing equipment that's on those sites. And our estimates are today that the reclamation value of that equipment far exceeds the abandonment liability and cleanup of those leases. And so we are in the black with respect to any liability there. So all in all, obviously Peyto is incredibly clean when it comes to abandonment liability and that's reflected in our LMR rating, it's very high and I think it's over 8 times. So we've got a very clean asset base here. It's all organically built by Peyto. It doesn't have any spills or any problems that we have to clean up. And so we've obviously been able to provide our bankers with a lot of comfort that we don't have a liability issue that they need to worry about at all. So that's just a little bit of color on that question that came in overnight. So there doesn't seem to be any more questions, maybe we will wrap it up there. We're, obviously, looking forward to the first quarter results here. We've got some Cardium drilling done already and we'll do some more here before we start to get to breakup. And we're excited about the results that we've been seeing from the last few completions and we're hopefully going to see over the next few completions here with this new technique, this targeting technique that we are using. We are looking for some really big wells here. We will tell you all about them when we get to Q1. So thanks for listening in. Just a quick reminder of the Annual General Meeting that's coming up. We have our Annual General Meeting scheduled on Thursday, May 9, at 3:00 p.m. here in our office building down on the plus 15 level. So I invite all our shareholders to come and participate in the AGM if they'd like. Anyway, thanks again for listening in this morning.
Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Everyone, have a great day.