Good day, ladies and gentlemen. Welcome to Peyto's Q1 2018 Financial Results Conference Call. At this time, all participants are on listen-only mode. Later, we will conduct a Q&A answer session. Instruction will follow at that time. If anyone should require assistance during the conference at any time, please press star then zero on your touch-tone telephone. As a reminder, this conference call is being recorded. I will now like to turn the conference over to Mr. Darren Gee, President and CEO. Sir, the podium is yours.
Thanks, Brian. Good morning, ladies and gentlemen. Thanks for tuning in to Peyto's first quarter 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 same forward-looking disclaimer and advisory that we set forth in the news release issued yesterday. In the room with me today is all of Peyto's management team. We've got Scott Robinson, our Executive VP of New Ventures, Kathy Turgeon, our Chief Financial Officer. We've got JP Lachance, our VP Engineering and Chief Operating Officer. We've got Dave Thomas, our VP Exploration here, Lee Curran, our VP of Drilling and Completions, Todd Burdick, our VP of Production, and Tim Louie, our VP of Land. We've got the whole team here if you'd like to ask questions later.
Before we get started with my comments, I did want to recognize the effort of the entire Peyto team over this past quarter, especially our field personnel. It was a long, cold, and lots of snow winter. While we weren't as active as we have been in the past, we still had a significant production base to optimize and lots of other opportunities to look at as well. Thanks to the entire team. As usual, they did a great job, and on behalf of all Peyto shareholders, just want to send a big shout-out to the team. I just want to start off this morning with some general comments before we get into some specifics about the quarter and take some questions from those listening in.
I'm going to try and be particularly brief this morning just because this is a very busy week of reporting, and there's a lot of calls going on this morning. Hopefully we can get through investor questions quite quickly and get everybody moving on this morning. As far as the quarter goes, on the drilling front, it was a pretty quiet quarter. As many have read, just eight wells drilled in the quarter, basically just finishing up the winter program that we started before the end of the year. We did complete a couple more Cardium wells in the quarter, and JP can talk a little more later about what we're seeing there and how we're excited to get back in the field drilling into that play after breakup.
It looks like we were correct to curtail any development we did have planned because any new production we would've built, we would've just been shutting in right now since AECO gas prices have collapsed just recently here in the last week or so. Our previous production base is very well protected with hedges, but of course, any new production from a Q1 capital program would've been unhedged, so we would've been exposing that new production to very low gas price. We think it makes a lot more sense not to be investing through the wintertime and then bringing production in onto very low prices. Better to just wait and develop those resources and those reserves later in the year. I think that yields us a much better financial result long term.
That means our production becomes a bit more seasonal, of course, and then rises and shrinks with the gas price for the next year or two while we work through some of this constraint with egress. We've got a lot of plans, obviously, to build new production, we've got to time that production to line up with the gas price so that we're not throwing away those reserves or producing to zero or negative prices. Financially, the quarter was still very strong. Our operating profits and operating margins were still very good and should be industry leading. With the reduced capital investments and reduced dividends, of course, we reduced our net debt by CAD 84 million, which meant our debt to funds from operations stayed just over two times, relatively flat to the fourth quarter, which is good.
We expect we will see probably a similar level of debt reduction into Q2. We made some good initial progress on our longer-term marketing strategy in the quarter. We put in place some NYMEX basis deals that will see us selling around 70 million a day at NYMEX prices over the next four summers starting in 2019. We've picked up some transportation starting in 2021 that should allow us to get much closer to that target of 40% of our gas exposed to U.S. markets within about three years' time. Shortly here on the horizon. All in all, I think a very successful quarter, despite what natural gas prices were and now are doing.
Maybe before we open it up to questions from those listening in, I wanted to just engage a few of the Peyto management team in some discussion about the future outlook, and hopefully that can give us some additional color on what we have going forward. I wanted to start with Todd Burdick, our Vice President of Production this morning, and just ask a question of Todd. Operating costs, Todd, were the same as Q1 2017, but a little bit higher than what we're targeting for the year. Obviously, that means we expect costs are going to be coming down in future quarters for 2018. I was wondering if you could maybe give us a little bit of color on the quarterly op cost expectations.
Sure, Darren. Well, Q1 was a particularly challenging quarter this year from a cost perspective due to several factors. You mentioned one, which is a really cold winter where
All of our areas saw a prolonged period of below-normal temperatures really for most of the quarter. We saw heavy snow in February and March. In fact, February and March saw nearly twice as much snow this year as in the same two months last year in 2017. As a result, we saw higher-than-normal chemical usage, which was compounded by higher pricing due to increased local demand because of that weather, and a weaker Canadian dollar. Of course, we needed to move that snow off of our road network as it wasn't melting. Those costs were up considerably over 2017. Add to that yearly increases to government and regulatory costs and power prices that now reflect the carbon tax, we continue to see cost pressure on the operating side.
That said, the initiatives that we've implemented over the past couple of years are helping to offset those costs, which are more or less out of our control. For the remainder of the year, we expect that we'll see lower operating costs on a per-unit of production basis as we continue to make strides with respect to facility operating costs, liquid handling, and even some fixed costs relating to infrastructure. This continued focus should help us as we work toward our goals through the year of op costs in that CAD 0.25 per Mcf range.
Good. Okay. Thanks, Todd. Maybe keeping with the cost theme, turn to Kathy Turgeon. Kathy, G&A and interest were also up a little bit this quarter. How are those looking going forward? How are we going to control those components and try and get those down towards our targets?
Well, G&A on a gross basis was actually relatively flat. It's up on a per Mcfe basis. That was due to a 70% decrease in our capital overhead recoveries, which was related to our capital program being extremely small for the first quarter. When our capital program starts up again in the latter half of the year, we expect capital overhead recoveries will bring our net G&A expenses back in line with normal levels at about CAD 0.04 per Mcfe. Interest expense is up as both the underlying interest rate and the level of our debt had increased. We reduced net debt by CAD 84 million in Q1, of which CAD 15 million was a repayment of long-term debt and CAD 69 million was payment of payables, which related to the Q4 capital and performance compensation.
We expect to repay in the range of CAD 150 million-CAD 200 million of debt, which will decrease our interest costs over the year.
Okay, good. Maybe switching gears, talk a little bit about the resource opportunities. JP, we're obviously very excited about the potential of the Cardium again. How have the last few wells looked? How did the economics look at current strip for those wells? What's the drilling program going to look like coming out of breakup and into the summer?
Thanks, Darren. Yep. We drilled three Cardium wells in Q1 to continue to test our latest Cardium completion design. These wells have been on now for one or two months, the average of these three wells validates our new type curve for the Sundance area. One well, in particular, was very strong. Now it looks like to be our best horizontal Cardium in the Sundance area. One well. Recall we've changed the completion design to slick-water fracs, and we've run up to 30 stages now at about 50-meter spacing. We estimate this new type curve with our latest cost structure will yield us around a 40% rate of return on the current strip. This makes sense when you factor in the liquid yields of over 40 barrels a million and starting rates close to three million a day of gas.
The fact that this place sits amongst our Peyto owned and operated infrastructure really helps to keep the cost down, both from the initial outlay and our ongoing operations as well. The plan, post-breakup and for the rest of the year, is to drill a lot more of the Cardium, about 40 locations, and continue to test our new design to exploit the areas where we've had success and to test other areas. We will start with three rigs as soon as road bans are lifted, and we will ramp up from there as summer goes on. We plan to push the stage count up a little higher and see if it adds incremental value, and we will likely test some other Cardium lands we have in areas outside of Sundance before year-end. As always, we will react to the feedback, and we will adjust the program accordingly.
Okay, thanks. What did that biggest well IP at?
It was close to 1,000 barrels a day.
Very strong. Excellent. All right. Maybe we can ask Scott Robinson about some of the new ventures we are working on. Scott, can you give us an update on where we are at on maybe the deep cut and some of the other new ventures?
Sure. With respect to the deep cuts, as a reminder, this project, if you recall, that we recognized a significant long-term value proposition by amending many of the processes that are at our wholly owned gas plants, both in the greater Sundance area and possibly in Brazeau, with process expansions that will allow us to achieve lower gas processing temperatures from the current refrigeration levels, which are about -35 degrees Celsius, down to very cold cryogenic temperatures, -80 to -90 degrees Celsius. In doing this, what we would do is we would achieve liquid recovery efficiencies that are much higher, in particular, increasing propane from levels that are sub 20% at the current processing configuration up towards 90% recovery of propane in a liquid form. That's the proposition.
The impact for our four or so plants, when we do implement these projects, would be to add about 6,000 to 7,000 barrels a day of added liquid from the existing raw gas stream production and production rates that would feed those plants with right now. Where are we at? The preliminary engineering design work is done. I think we've mentioned that before, and we've recently finished some cost estimating at a very high level. We're presently reviewing the project economics and considering timing strategies that best fit with the liquids market, in particular, the propane market. I think it would be worth providing a little bit of background color on the propane market.
To start off, we recognize that at the current natural gas price levels of CAD 1 to CAD 2 per GJ, we already get the equivalent of about CAD 5 to CAD 10 a barrel of propane by selling it in the gas phase. That's the equivalent value of the gas phase on a per liquid barrel equivalent basis. CAD 5 to CAD 10. And that's with the existing processing conditions, the -35 plant recovery levels of sub 20% on propane. If we consider the liquid propane market, that's the gas propane market. The liquid propane market was very strong over the fourth quarter of 2017 with plant gates after transportation and fractionation of about CAD 36 a barrel as compared to the CAD 5 to CAD 10 a barrel of what it's worth in the gas phase.
A very attractive margin of over CAD 25 a barrel by recovering and selling propane in the liquid phase. However, the propane prices have come off a bit since the fourth quarter of 2017 as the winter demand begins to subside. If I can step back a little bit on some more fundamentals on propane price, I think that's important to this project consideration. Just on a fundamental basis, propane contains about three-quarters of the energy of gasoline, so one might expect propane to be worth about CAD 50 a barrel if oil's worth CAD 70 a barrel. In fact, before one of the major pipelines to the U.S., the Cochin Pipeline, was reversed and converted to condensate in 2014, Western Canada did enjoy a very robust propane market.
With the loss of that egress, like similar other products in Western Canada, we're now seeing an inferior price, about CAD 10 discount to U.S. prices. There are some strong fundamentals on the horizon here. If you consider Western Canada produces about 200,000 to 250,000 barrels of propane, you can measure some of these upcoming changes against that 200,000 to 250,000 barrels. For starters, AltaGas is projecting the in-service date of its West Coast Ridley Island export terminal in the first quarter of 2019, that'll take 40,000 to 50,000 barrels of [audio distortion]. Behind that project on the drawing board, there are three other similar Far East export projects. Not all that may occur, but in aggregate, they add up to another 80,000 barrels a day.
You can add to that two recently government-supported petrochemical projects both with the potential to uptake another 45,000 to 50,000 barrels a day of propane. Those two projects have qualified for CAD 1 billion of government aid. One has broken ground, and the other's looking at making investment decisions in the first quarter of 2019. Long story long, the ingredients are all there for a very strong and reliable propane market. Just what we'd like to see to backstop our long-term infrastructure investment plans. Coming back to where we're at, we're presently contemplating the best timing to play our increased recovery levels into this market transformation that looks to be happening over the next couple of years here.
Okay, great. Thanks, Scott. Good color there, too. I think maybe we'll stop the questions there and, Brian, maybe we could open it up to questions from listeners and investors.
Of course. Ladies and gentlemen, if you have a question right now, at this time, just press star followed by the one key on your touchtone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. Once again, if you have a question, that's star and one. Our first question comes from the line of Bryan Christensen from Macquarie. Your line's now open.
Good morning, guys. Darren, you guys have been pretty nimble in the past, shutting in on negative AECO price days. I know you've still got some minor exposure to daily still. Did you shut anything in this past weekend, or do you plan to if we dip back down in Q2?
Yeah. Hi, Bryan, thanks for the question. It's a good one. Obviously, that's very relevant these days and was relevant last fall, too, when we saw some negative pricing. We did shut some production in over the weekend for sure as we're, as you point out, extremely nimble. Todd, could you walk us through maybe just the process of When we see negative prices, what happens? What do we do?
We already had a little bit of gas shut in as it dropped below CAD 0.50 the previous day. When we start seeing negative prices, we start talking with our marketing group. As a group together, we start deciding whether or not we want to essentially buy some of that negative gas, so get someone to give it to us for a price. That decision's made. They start getting away at that. We'll end up with some volume, maybe 10,000, 20,000, 30,000, 40,000 GJs or more. The marketing group will let us know what they were able to get. We turn around and convey that to the field. Essentially guys jump on the computer and guys in the plant start shutting compressors in at the various plants.
We typically shut in the driest gas that we've got. We've got a kind of pre-canned list of wells. It usually takes us maybe one or two hours. We'll have large volumes of gas shut in. That's essentially how it works. It's pretty smooth. It happens pretty quickly.
What about turning it back on when the price starts to bounce?
Same thing. The marketing group lets us know what the price is. We talk, we say what volume we'd like to get back on. Again, the marketing group starts selling our gas, and we go to the field again, and they start bringing the gas back on, and again, usually it's no more than a couple of hours, and we've got it back on.
Bryan, to answer your question, we are being very nimble. We have that capability, which I think is quite rare, actually, in the industry. We operate all of our production, we operate all the wells, we operate all the gas plants. We're in control, and we're in tune, in any given minute, what gas prices are doing. We're able to respond very quickly, take advantage of when the price quickly goes negative because weather isn't constructive or because TransCanada changes, interruptible, or there's maintenance that all of a sudden happens on the system. We see the prices move, and we react. We preserve our cash flow, we keep our reserves in the ground, and not have to incur any cash costs at all when prices go negative, and effectively still get all of the revenue.
We can even shut volumes down, not just our day gas that's exposed to that daily price, but obviously if the prices are low enough, then we still have our hedge protection. We can shut in our hedged gas too, and just go collect basically that financial gain without incurring any costs or pulling any of our reserves out of the ground. We'll just use other people's gas to actually do that. They're paying us back to do that. That kind of nimbleness, it served us well in the third and fourth quarters last year. We didn't get to benefit from negative prices very much, but not that's really a benefit, but we do get to take advantage of that opportunity or take advantage of others during that opportunity anyway. We're going to keep doing that as we go forward here.
That's great. Thanks. Should we be using that sort of CAD 0.50 threshold to judge what's getting shut in and what isn't going forward? I know we're above that now, for future reference.
We've got a tiny little bit of gas that's third party processed. Our Whitehorse gas, for instance, we've got a couple of wells down there that we're waiting, obviously, on our Whitehorse plant to get built at some point, that'll pull that gas back out of that third party. Those third-party wells obviously are seeing higher fees, we've got a little higher break-even gas price on those wells. Those ones, as Todd was talking about, are the first ones that we look at when gas price gets to that CAD 0.01 level and down.
Got you.
Our cash costs obviously are a lot lower than that, if there's any liquids at all in those wells, that drags the cash cost or the gas price break even down even further. It's really when gas goes zero or negative that we're jumping on it and taking advantage of it. Basically saying, if someone's going to pay us to basically use our space in the pipe and our hedges, we'll take that. Really, it's more when gas gets to that sort of zero or negative level that we have material volumes that are getting shut in.
Okay. Got it. Thanks, Darren. Appreciate it.
Yeah, you bet. Thanks for the question.
Once again, ladies and gentlemen, if you have a question at this time, please press star followed by the one key on your touchtone telephone. Our next question comes from the line of Travis Wood from National Bank. Your line is now open.
Good morning, everybody. Kind of building off Bryan's question around marketing. With the volatility in the pricing aggregate production in the basin being infrastructure constrained, do you guys have the opportunity to basically just start to process more third-party gas and play a bit of a midstreamer role where you have facilities that are not at full capacity?
Thanks, Travis. Great question. Yeah, we do. Obviously, in and around our existing facilities, there are other operators, and we do have that option. We don't have any true, I don't think, third-party volumes where we don't have an ownership in the volumes going through any of our plants today. It's not something we've traditionally pursued because we've been growing our own volumes and filling up our plant capacity as we've gone over the last several years here with our own gas. We haven't really pursued other people's gas to help fill those capacities. If we have available capacity that can be used, there's no question that we can start to offer it to others in the industry. J.P., are we actively working that, or what?
We've reached out to a few in a few situations where the folks don't have their own infrastructure, or they're exceeding what they have. A lot of the operators around us have their own infrastructure, so it's not as simple as what it sounds to just attract that volume over. In some instances, we've had some opportunities, and we've reached out. It's like you say, the true third-party volumes aren't a big part of our business, really.
Our operating costs, though, are obviously quite a bit lower than a lot of our competitors, even in the basin and at surrounding plants. If we have capacity that we want to offer, we can definitely offer it at very competitive pricing and I think probably attractive pricing to some of those people. If they're already being third-party processed by a midstreamer or something, we can compete with the very best midstreamers out there, no question, because our cost structure is so much lower than most of their competitors. I think, as Scott mentioned, too, we start to get installation of deep cut and liquids extraction that a lot of plants in the area don't have. That, too, is going to be attractive to others around us.
If we do have available capacity, where we can deep cut the gas, obviously, other producers are going to look at that option as a more attractive one than just doing a shallow cut and only getting a small portion of liquids out.
Okay. Thank you.
Great. Thanks, Travis.
Once again, if you have a question this time, please press star followed by the one key on your touch-tone telephone. One moment for questions. I'm currently showing no further questions. I would now like to turn the call back to Darren Gee for any further remarks.
Okay. Thanks, Brian. Thanks for everybody for listening in this morning. We're trying to keep things quick and brief here this morning just because it is such a busy week. We've got a bunch of opportunities that we're keen to get looking at here. We're obviously chomping at the bit to get back out in the field and start drilling a lot of these Cardium opportunities we have. They've got very robust economics, even at the current depressed gas prices. We want to get started building that, and we're quite optimistic about what AECO pricing is going to look like in the fall and going into next winter.
The lack of access to storage that we're seeing just in the last couple of weeks here, if that persists throughout summer, we're going to enter next fall with very little usable gas in storage in Alberta, and that's got to have a really positive price impact going into next winter. Our timing, it looks like, could be perfect in terms of building a lot of new production volume this summer and then bringing it on into next fall's much stronger AECO prices with all that flush. While we're not enjoying these really low gas prices on the daily basis much, we are definitely strategically set up to take advantage of this volatility that we're seeing going forward. We're not just throwing away our reserves this summer.
We're going to be prudent about keeping them in the ground and bringing them out at a time when the pricing is much better. We'll get back to you in Q2 and update you on how we've come out of breakup and got the rigs back working and what the gas price forecast looks at the time and how that's going to play into the remainder of the year. Thanks for listening in, and we'll be back to you in August.
Ladies and gentlemen, thank you for your participation in today's conference call. This does conclude the program, and you may disconnect. Everyone have a great day.