Peyto Exploration & Development Corp

TSX:PEY

Earnings Call Transcript 2018-Q1

[Operator]

Good day, ladies and gentlemen, and welcome to Peyto's Q1 2018 Financial Results Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded.I would now like to turn the conference over to Mr. Darren Gee, President and CEO. Sir, the podium is yours.

[Darren Gee, President, CEO & Director]

Thanks, Brian, and good morning, ladies and gentlemen. Thanks for tuning into 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; 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. So 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. And 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. So, 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.So, 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. So, hopefully, we can get through investor questions quite quickly and get everybody moving on this morning.So, as far as the quarter goes on the drilling front, it was a pretty quiet quarter. As many have read just 8 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 of 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 plan, because any new production we would have built, we would have 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 have been unhedged, so we would have been exposing that new production to very low gas price. And so, we think it makes a lot more sense, not to be investing through the winter time and then bringing production in onto a 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. So 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 2, while we work through some of this constraint with egress. We've got a lot of plans, obviously, to build new production, but 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 $84 million, which meant our debt to funds from operations stayed just over 2x, 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 we'll see as selling around [ 70 million ] a day at NYMEX prices over the next 4 summers, starting in 2019, and we 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 3 years’ time, so shortly here on the horizon.So all in all, I think a very successful quarter, despite what natural gas prices were and now are doing. And maybe before we open it up to questions from those listening in, I wanted to just engage a few of the Peyto management team and some discussion about the future outlook, and hopefully, that can give us some additional color on what we have going forward. So I want to start with Todd Burdick, our VP of Production this morning, and just ask question to 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 the future quarters for 2018. I was wondering if you could maybe give us a little bit of color on the quarterly op cost expectations.

[Todd Burdick, Vice President of Production]

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, and then we saw -- saw heavy snow in February and March, in fact, February and March saw nearly twice as much snow this year as in the same 2 months last year of 2017. So 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, then, of course, we needed to move that snow off of our road network as it wasn't melting, so 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 dioxide 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. So those continued focus should help us as we work toward our goals through the year of pp cost in the $0.25 per Mcfe range.

[Darren Gee, President, CEO & Director]

Good. Okay. Thanks, Todd. Maybe keeping with the costs theme, turning to Kathy Turgeon. Kathy, G&A and interest were also up a little bit this quarter. How are those looking going forward, how we're going to control those components, and try and get those down towards our targets?

[Kathy Turgeon, VP of Finance & CFO]

Well, G&A on a gross basis was actually relatively flat, it's up on a per Mcfe basis, however, that was due to a [ 70% ] decrease in our capital overhead recovery, 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 $0.04 per Mcfe.Interest expenses up as both the underlying interest rate and the level of our debt had increased. We reduced net debt by $84 million in Q1, of which $15 million was the repayment of long-term debt, and $69 million was payment of payables, which related to the Q4 capital and performance compensation. We expect to repay in the range of $150 million to $200 million of debt, which will decrease our interest costs over the year.

[Darren Gee, President, CEO & Director]

Okay. Good. Maybe switching gears, talk a little bit about the resource opportunities, JP, we're obviously very excited about the potential of Cardium again, how the last few wells looked, how does the economics look at current strip for those wells, and also what's the drilling program going to look like coming out of breakup and into the summer?

[Jean-Paul H. Lachance]

Thanks, Darren. Yes. We drilled 3 Cardium wells in Q1 to continue to test our latest Cardium completion design, these wells have been on now for 1 month or 2 months, and the average of these 3 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 slickwater fracs and we've run up to 30 stages now at about 50-meter spacing. So 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're factoring the liquid yields of over 40 barrels a million and starting rates close to 3 million a day of gas. And the fact that this play sits amongst our Peyto owned and operated infrastructure really helps to keep the cost down both from initial outlay and on ongoing operations as well.So the plan post-breakup and for the rest of the year is to drill a lot more of the Cardium both for locations and continue to test our new design to exploit the areas where we've had success and to test other areas. We'll start with 3 rigs, as soon as [ real bans ] are lifted, and we'll 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'll likely test some other Cardium lands we have in areas outside of Sundance before year-end. And as always, we'll react to the feedback and we'll adjust the program accordingly.

[Darren Gee, President, CEO & Director]

Okay. Thanks. What is that biggest well IP at?

[Jean-Paul H. Lachance]

It was close to 1,000 barrels a day, so.

[Darren Gee, President, CEO & Director]

Very strong. Excellent. All right. Maybe we can ask Scott Robinson about some of the new ventures we're working on. Scott, can you give us an update on where we're at, and maybe the Deep Cuts and some of the other new ventures.

[Scott Robinson, Executive Vice President of New Ventures]

Sure. With respect to the Deep Cuts, as a reminder, this project we call it -- we recognize a significant long-term value proposition by many of the processes that are -- at our wholly owned gas plants, both on 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 above minus 35 Celsius, down to a very cold cryogenic temperatures minus 80 to minus 90 degree Celsius. So 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. So that's the proposition, the impact for our 4 or so plants, when we do implement these projects would be to add about 6,000 or 7,000 barrels a day of added liquid from the existing raw gas stream production and production rigs that will feed those plants with right now. So 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, that's fit with the liquids market, in particular, the propane market, and I think it would be worth providing a little bit of background color on the propane market.And to start off, we recognize that -- at the level -- at the current natural gas price levels of $1 to $2 per GJ. We already get the equivalent of about $5 to $10 a barrel of propane by selling it in the gas base. So that's the equivalent value of the gas basis, that we would -- on a per liquid barrel equivalent basis, so $5 to $10, and that's at the -- with existing processing condition the minus 35 [indiscernible] recovery levels of sub 20% on propane. Now, if we consider the liquid propane market, that's the gas propane. The liquid propane market was very strong over the fourth quarter of 2017, with plant gates after transportation and fractionation were above $36 a barrel as compared to the $5 to $10 a barrel of what it's worth in the gas basis. So a very attractive margin of over $25 a barrel by recovery and selling propane in the liquid base. However, the propane prices have come off a bit, since the fourth quarter of 2017 as the winter demand begins to subside. But 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 3 quarters of the energy of gasoline, so one might expect propane to be worth about $50 a barrel, if oil is worth $70 a barrel, and in fact before one of the major pipelines to the U.S., the [ Ocean ] pipeline was reversed and converted to condensate in 2014, Western Canada did enjoy a very robust propane market, however, with the loss of that egress like similar other products in Western Canada we’re now seeing an inferior price about $10 discount to U.S. prices, but there is 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 really as an export terminal in first quarter of 2019, and that will take 50,000 barrels, 40,000 to 50,000 barrels of condensate. Behind that project on the drawing board, there are 3 others similar far east export projects, not all of that may occur, but in aggregate they add up to another 80,000 barrels a day. And then you can add to that 2 recently government supported petrochemical projects both with the potential to update another 45,000 barrels to 50,000 barrels a day of propane. So those 2 projects have qualified for $1 billion of government aid, one has broken ground and the other is looking at making investment decision in the first quarter of 2019. So the long story long, the ingredients are all there for a very strong and reliable propane market. Just what we'd like to see the backstop our long-term infrastructure investment plans. So coming back to where we're at, we're presently contemplating the best time into playing our increased recovery levels into this market transformation that looks to be happening on a couple of years here.

[Darren Gee, President, CEO & Director]

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.

[Operator]

[Operator Instructions] And our first question comes from the line of Brian Kristjansen from Macquarie.

[Brian Kristjansen, Research Analyst]

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?

[Darren Gee, President, CEO & Director]

Yes. Hi, Brian, and thanks for the question. It's the good one. Obviously, that's very relevant these days and, well, it’s relevant to last fall too, and 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. Maybe, Todd, could you walk us through, maybe just the process of when we see negative prices, what happens, what do we do.

[Todd Burdick, Vice President of Production]

Sure. So, we already had a little bit of gas shut-in as it dropped below $0.50 previous day, when we start seeing negative prices then we start talking with our marketing group, and 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, so that decision’s made, and then they start hitting away at that, and then we'll end up with some volume, maybe 10,000, 20,000, 30,000, 40,000 GJs or more. And the marketing group will let us know what they were able to get. And then we turn around and convey that to the field, and essentially guys jump on the computer and guys in the plants start shutting compressors in at the various plants, we typically shut-in the driest gas that we've got. And so, we've got a kind of pre-canned list of wells and that usually takes us maybe 1 or 2 hours, and we will have a large volumes of gas shut-in, so that's essentially how it works, it's pretty smooth, it happens pretty quickly.

[Darren Gee, President, CEO & Director]

And then what about turning it back on when the price starts to bounce?

[Todd Burdick, Vice President of Production]

So, the same thing, the marketing group lets us know what prices, we talked, we say kind of what volume we'd like to get back on. So 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.

[Darren Gee, President, CEO & Director]

So, Brian, I mean, 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. So we're able to respond very quickly to take advantage of when the prices 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, and we preserve our cash flow, we keep our reserves in the ground and not have to incur any cash cost at all when prices go negative, and effectively still get all of the revenue. We can even shut volumes down, not just to our day gas that's exposed to that daily price, but obviously, if the prices are low enough and 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. And they're paying us in fact to do that, so that kind of nimbleness 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, that's really a benefit. But we do get to take advantage of that opportunity or take advantage of others during that opportunity anyway, and we're going to keep doing that as we go forward here.

[Brian Kristjansen, Research Analyst]

That’s great. Should we be using that sort of $0.50 threshold sort of to judge what's getting shut-in and what isn't go forward, I know we're above that now, but for future reference?

[Darren Gee, President, CEO & Director]

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, and that will pull that gas back out of that third-party. But those third-party wells, obviously, are seeing higher fees, and so we've got a little higher breakeven gas price on those wells -- those ones as Todd was talking about kind of -- are the first ones that we look at when gas price gets to that $0.50 level and down. Our cash costs obviously are a lot lower than that, and if there is any liquids at all in those wells, then that drags the cash costs or the gas price breakeven 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 is going to pay us to basically use our space in the pipe and our hedges, then we'll take that. So really it's more when gas to gets to that sort of zero or negative level that we have material volumes that are going to shut-in.

[Operator]

[Operator Instructions] Our next question comes from the line of Travis Wood from National Bank.

[Travis Wood, Analyst]

Kind of building off Brian's question around marketing, with the volatility in the pricing aggregate production in the basin being infrastructure constrained. You guys have the opportunity to basically just start the process more of third-party gas and play a bit of the midstream role where you have facilities that are not at full capacity?

[Darren Gee, President, CEO & Director]

Thanks, Travis. Good question. Yes, 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. So we haven't really pursued other people’s gas to help fill those capacities. But if we have available capacity that can be used, there's no question that we can start to offer to others in the industry. JP, are we actively working that or what?

[Jean-Paul H. Lachance]

So, we have 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, they have their own infrastructure. So it's not as simple as what it sounds, it's just to attract that volume over, but in some instances, we've had some opportunities and we've reached out, so like you said the true third-party volumes aren't a big part of our business really.

[Darren Gee, President, CEO & Director]

Our operating costs though are obviously, quite a bit lower than a lot of our competitors, even in the basin and surrounding plants. So 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 process by a midstream 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 our competitors. I think as Scott mentioned too with the -- 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 and around us. So 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, and just doing the shallow cut and only getting a small portion of liquids out.

[Operator]

[Operator Instructions] And I'm currently showing no further questions. I would now like to turn the call back to Darren Gee for any final remarks.

[Darren Gee, President, CEO & Director]

Okay. Thanks, Brian, and thanks to 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. And we've got a bunch of opportunities that we're keen to get looking at here. We're obviously jumping at a bit to get back out of the field and start drilling a lot of these Cardium opportunities we have. We've got very robust economics even at the current depressed gas prices. So 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, then we're going to enter next fall with very little gas -- usable gas in storage in Alberta and that's going to have a really positive price impact going into next winter. So 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. So, 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. And we're not just throwing away our reserves this summer, we're going to take -- be prudent about keeping them in the ground and bringing them out at a time when the pricing is much better. So we will 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. So thanks for listening in, and we will be back to you in August.

[Operator]

Ladies and gentlemen, thank you for your participation in today's conference call. This does conclude the program, and you may all disconnect. Everyone, have a great day.