Peyto Exploration & Development Corp

TSX:PEY

Earnings Call Transcript 2020-Q1

[Operator]

Ladies and gentlemen, thank you for standing by, and welcome to Peyto's First Quarter 2020 Financial Results Conference Call. [Operator Instructions]I would now like to hand the conference to your speaker today, Darren Gee, President and Chief Executive Officer. Please go ahead, sir.

[Darren Gee, President, CEO & Director]

Okay. Well, thanks, Joel, and good morning, ladies and gentlemen. Thanks for tuning in to Peyto's First Quarter 2020 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 we set forth in the company's news release yesterday.In the room with me today and honoring our 2-meter spacing rules, we've got a full management team. We've got JP Lachance, our VP of Engineering and Chief Operating Officer; Kathy Turgeon is here with our Chief Operating Officer; Dave Thomas, our VP of Exploration is here; Todd Burdick, our VP of Production; Lee Curran, our VP of Drilling and Completions; Tim Louie, our VP of Land; and we've got Scott Robinson, our VP of Business Development here. So the whole team is here for your questions.Before I get started, though, with my comments today about our results, I would like to recognize the extraordinary efforts and perhaps even the bravery shown by the entire Peyto team, including our field personnel over the first quarter. Our team set aside their peers with respect to the pandemic and continued to provide Albertans with the critical energy that's required to keep our households warm and safe and to power our ever so important hospitals and critical care facilities during this global pandemic. It was a scary time for everyone, but we were all extremely careful and successfully got the job done.Because what we produce at Peyto, obviously is very essential and critical in our society, and we are very much reminded of that fact these days. It's very important that we keep all our employees and key service providers, healthy and safe, especially during this time. So a congratulations to the whole team and a job well done. I'd also like to take this opportunity to thank all of our frontline health care workers in the province who are also putting their lives at risk every day to ensure that we have the full capacity of the health care system available to all those Albertans that are in need.So on to our first quarter results. Obviously, the first quarter proved to be a very challenging period for Peyto with a very sudden and dramatic drop in oil prices during the quarter, and we had a pretty consistent erosion even in natural gas prices throughout that quarter. So not only did we have to deal with the pandemic and all of the things that, that brought, we had to deal with some rather terrible commodity prices, too. This was quite the reversal from the fourth quarter sentiment, where we were very optimistic on where gas prices were going. And the fact that we expected 2020 to be a bigger and better year than 2019. But I suppose so far, that's not been the case. However, our team here at Peyto remain very nimble, and we responded to these new challenges, as we always have with straight head on. As we saw the winter heating season failed to materialize, and the gas prices, particularly the NYMEX price in the U.S., which we're now much more exposed to, we saw that NYMEX price basically erode away in the quarter. We decided we needed to slow down our winter program a little bit and defer some of the capital that we had planned in the earlier part of the year to later in the year when we could see prices tighten up a little bit. We did that, I think, in February by dropping some drilling rigs.Then in March, of course, the oil price crashed on the demand impact due to COVID-19. And we had the price war between Russia and Saudi Arabia, where they were threatening to flood the market with a whole bunch of production. So a lot of changes. We had to completely reassess our drilling plans for the year in light of the impact to our economics that those commodity prices brought. So we quickly shifted our focus away from the more liquids-rich Cardium opportunities we've been chasing all of 2019 to now the more leaner dryer gas Spirit River opportunities that we have within our portfolio. I think it's a real testament to Peyto and its nimbleness to be able to do that so quickly and so efficiently.By the end of the quarter, we revised our capital plans for the year. We rebuilt our entire drilling schedule with more of a focus on leaner gas opportunities. Also by the end of March, we saw a new commodity strip evolving with some real interesting developments on oil supply side, as now we had potential shut-ins being promoted, storage was filling rapidly. The OPEC++ group was talking about taking a lot of volumes offline as opposed to flooding the market, and there was an interesting sort of follow-on effect with respect to associated gas being shut-in and, therefore, causing gas prices to rise. And that last effect really was the silver lining for us as a gas producer, and we started to focus on that one. However, we had to be a little bit careful because we also produce condensate, and we had to think about what would happen to that condensate as heavy oil in Alberta was shut-in. So there were a lot of sort of exterior market considerations to think about in the first quarter that kept us on our toes.Those are all the things going on outside of Peyto that we don't really control. Inside of Peyto though, I think the things that we do control, we're going quite well. We drilled some very nice wells in the first quarter, finished up a large 3D seismic program over a big block in the southern area of greater Sundance. We built a large diameter pipeline that opens up a brand-new area in South Brazeau called Chambers. We continue to see improvements in our capital costs. And Lee is here this morning. Hopefully, he can talk a little bit more about how those might continue to evolve this year. Operating in the cost -- operating costs in the quarter were a little higher than normal, mostly due to our preparations really for COVID-19 supply chain disruptions and a few other things, but we've got some great initiatives for the rest of the year, which we should see those coming down. Todd can talk about those a little more.From a production perspective, things ran pretty smoothly. As both propane and gas prices changing throughout the quarter, we were inclined to toggle our deep cut on and off depending on whether propane prices were too weak and gas prices were strong or then gas prices weakened and propane prices got stronger. We seem to be getting better and better at this, though. So it's nice that we have that flexibility to target the best price possible and put the production in the right form to attract that best price. As I mentioned, we were concerned with how our condensate would be priced and handled. If a lot of that heavy oil demand disappeared, then so too with the demand for condensate. So we collected all of our tanks. We rented a bunch more tanks, and we built a couple of key tank farms on a couple of plant sites to store about 80,000 barrels of condensate, which is 2 to 3 weeks' worth of production, just in case there was a major disruption to the condensate markets. This is likely more of an insurance policy than anything, so we don't have to shut-in all of our production, gas, condensate and NGLs, if there's a problem with getting our condensate to market. It's fairly inexpensive to build this capacity and this insurance, so I think it's the right move. And we don't know yet whether we're going to use the full capacity or not. We're definitely not through the oil storage problem yet. It is still continuing to mount up there. So it's a good bit of insurance to have in our pocket.Financially, for the quarter, commodity prices were some of the lowest we've ever seen at Peyto, unfortunately, and delivered the lowest per unit revenue in our entire 21-year history. So even with our low costs, that translated into the lowest netback in our history as well. These low prices caused the independent reservoir engineering firms to drop their price deck substantially and that caused a significant impact to the perceived value of our reserve assets. When we compare that to what we spent on those reserves, we ended up having to record a small noncash impairment of around $80 million, and that in turn results in a loss for the quarter. This was the first impairment we've ever taken as a company. And it's the first quarterly loss we've posted in the last 15 years. It wasn't really a record I wanted to break, unfortunately, but it is a sign of the times. We'd expect that as oil and gas prices rise and the reservoir engineering firms increase their price forecast back up, that this impairment will reverse.So unfortunately, the extreme volatility in commodity prices translated into fairly extreme volatility in our earnings. So that was basically it for the quarter. It was a bit of a tough quarter, but we managed to make it through intact, and I think we're looking forward to some improvement for the rest of the year. Joel, perhaps we could throw the line open and just take some questions from those listening in.

[Operator]

[Operator Instructions] Our first question comes from Fai Lee with Odlum Brown.

[Fai Lee, Equity Analyst]

Fai, here. Darren, I just want to talk a little about the impairment test that was performed. And does it reflect the hedgings -- your hedges in place and the diversification arrangements?

[Darren Gee, President, CEO & Director]

Yes, it does. Those arrangements were included in the reserve evaluation. So depending on what the commodity prices at those various hubs are -- that are forecast by their independent reservoir engineers, then that translates into what our realized prices would be. Obviously, our reserve report is somewhat tailored a little bit to the commodity prices that we perceive at the time when we did it at the year-end, we had a lot of Cardium drilling at the front end because gas prices were weaker and oil prices were stronger. And so naturally, that's the way that we built our drilling forecast going out, picking from the inventory that we have. We don't populate the entire reserve report with all the inventory that we have in the future, obviously. We have couple thousand or more locations, obviously, to choose from and independent reservoir engineering firm will pick from those for the next 5 or so years to populate a forecast of development. It only takes a fraction of our undeveloped locations then and puts it in the reserve report.But we try to direct them a little bit as to what's the most profitable looking species that we're drilling from. And so for the last year or 2, it's been the Cardium with its high liquid yields. And so we brought those to the forefront and put those first up. I think realistically though, if we were to rebuild the complete reserve report today, reflective of the change -- the dramatic change in the commodity price, we would bring a lot more of our dryer gas opportunities forward earlier in the forecast for development. So there's little sort of changes within the way the reserve reports are constructed. They don't adapt to such a dramatic change in commodity prices, obviously. But yes, the reserve report is relatively fulsome, in that, it reflects all the parts of our business.

[Fai Lee, Equity Analyst]

Okay. So that's kind of where my follow-up was going to go. It's like -- it looks like one of the criticism that the reserve engineers is that the price assumptions or evaluation companies -- the price assumptions that you had have always seemed to be quite aggressive relative to where the forward or strips are, where current prices are. And certainly, the deck looks -- what you've outlined in the MD&A looks a lot more realistic. So in terms of valuing your book value, which is close to, I guess, $10 per share, is that kind of -- it seems like -- am I interpreting correctly when it looks like it gets more representative of the MPV based on this current price deck that's outlined in your MD&A.? Is that the way to think about it? Plus obviously, there's some stuff that you mentioned that are not included in that report.

[Darren Gee, President, CEO & Director]

Yes, although still it's very difficult, obviously, for the independent reservoir engineering firms to come up with a forecast as well right now. There's been so much change going on that -- you're right, we criticize them maybe a little bit that their forecasts are optimistic relative to strips sometimes when we look at it. But you have to remember that these are the same guys that do look at everybody's F&D costs, they do look at everyone's supply cost. So when they're looking forward and forecasting what commodities they think commodity prices are going to be. Yes, of course, they, I'm sure, incorporate what the strip is going to look like, but they also know what the industry supply cost is. And so they -- in some ways, they know what the commodity price has to be in order for people to have economic drilling prospects and in order for the industry to move forward, replacing its depletion. And so in a way, we have to kind of believe what they believe in somewhat because they do know what the industry's cost structure is like. You know what I mean.So in some ways, we can criticize them for their belief in the commodity price being different than the strip. But the reality is the strip sometimes isn't all that right either. And maybe the strip isn't as knowledgeable as the independent engineering firms are of what people's actual costs have been to convert new reserves into production. You know what I mean. So we like to beat on them -- those guys because yes, they make a forecast of commodity prices, and everybody who makes the forecast of commodity prices is generally wrong. Nobody really knows what the forecast is going to be. But these guys go out on a limb and they do -- in their defense, they do see what everybody's conversion costs are. And from that, I'm sure they determine what the commodity price needs to be. And so maybe when we look at the independent engineering firms, and we see a forecast that's higher than the strip today, what that -- what we really should conclude from that is that the supply cost is actually higher than the strip today. And so one would expect that activity levels would probably drop off if those strip prices continue to persist, and they have to get above what the company supply costs really are to be manageable. So -- sorry, that doesn't really answer your question. I mean, it's a little bit more background, perhaps, information on those independent engineering firms. But -- it's changing quite rapidly. And next quarter, we're probably going to see a significantly different forecast from those guys, and that's going to flow through to a significantly different impact on our reserve values. And one would expect, and I think most people do expect in the industry that as commodity prices turn around that a lot of the impairments, obviously, that the industry has had to take this quarter are going to be reversed.

[Fai Lee, Equity Analyst]

Okay. But the book value of your assets now, it seems like with impairment and the changes that seems to match the -- you're marking to market almost a bit too to the assumptions laid out by the reserve evaluator. Is that kind of the way to think about it?

[Darren Gee, President, CEO & Director]

I don't know. Is that how you would look at it, Kath? I don't think from a book value perspective...

[Kathy Turgeon, VP of Finance, CFO & Director]

I'm not really clear on...

[Darren Gee, President, CEO & Director]

Sorry, Fai, I'm not sure what you're getting at, but...

[Fai Lee, Equity Analyst]

All right. Maybe I'll follow-up off-line with you.

[Todd Burdick, Vice President of Production]

One thing to -- just to add, Darren, which you covered that well. The reserve companies have begun to calibrate the near-term prices a lot closer to the strip. But the strip that at the end of the year is just what would be erroneous to just plug in at current momentary strips incur at the end of the year, and it can vary quite a bit over the course of this year depending on the season. So I think these -- the reserve engineers that you stated are trying to look at the big picture and the true supply demand on the out-year as well calibrating the in years or the near years closer to that strip.

[Operator]

Our next question comes from Doug Younghusband with CIBC World Markets.

[Doug Younghusband;CIBC World Markets;Analyst]

A lots of moving parts, not always fun, but it's never boring, right?

[Darren Gee, President, CEO & Director]

You say so, Doug.

[Doug Younghusband;CIBC World Markets;Analyst]

You mentioned higher costs in the quarter due to COVID preparation. So I'm presuming those are expense costs, but over time, they'll average out in future quarters, I'm hoping? Or were they sort of one-off additional costs?

[Darren Gee, President, CEO & Director]

No, that's right. I would say, winter season operating costs generally tend to be higher. We have to obviously use more methanol to keep wells from freezing off. We've got a lot of snow removal that we're looking at. Road maintenance tends to be higher than in the summer. Todd, do you want to jump in there? What else do we have?

[Todd Burdick, Vice President of Production]

Yes, I had those points down for sure. Yes, typically, in the winter as well methanol prices typically go up because supply -- or demand goes up in Alberta. So Q1 is typically higher. And then this year, we had we weren't too sure what the supply chain might do. So we did purchase a few things, the lubricating oils, that sort of stuff, just in the off chance that there was a disruption, and we would be able to make it through a couple of months. So it accounted for some, but not a lot, and it will average out into Q2. That's -- we didn't use any more. It's just kind of sitting in inventory, so...

[Darren Gee, President, CEO & Director]

We had -- if we had been able to foresee that the oil price was going to drop so dramatically, we could have waited and bought our lube oil when it was way cheaper, but I don't think too many people saw that one coming.

[Doug Younghusband;CIBC World Markets;Analyst]

Yes, I don't think so.

[Todd Burdick, Vice President of Production]

We are anticipating lubricating oils to go down, but they -- it's not a 1:1 correlation with oil price. Obviously, it's tied to the U.S. producer price index, which did go down -- it actually went up in January, and then it's come down, but as well, it's tied to the Canadian dollar. So...

[Doug Younghusband;CIBC World Markets;Analyst]

So sure. I appreciate that guys. I just was wondering if it was more of a pulling forward some expenses that you will regain sort of in future quarters or give back in future quarters. Something that's more curious to me is what's going on with world LNG natural gas prices? And will that ultimately translate backwards into North American prices. I mean, the sort of simple view is, Qatar can't sell its gas at a reasonable price. So they've got a surplus. And so maybe some of the export capacity out of Continental USA is going to get backed up or is backing up, which then affects Canadian prices, which move south for volumes moving south. Is that a potential scenario to Canadian prices or North American prices?

[Darren Gee, President, CEO & Director]

Yes, you bet, it is, Doug. It's the sort of counterargument to the positive, more bullish thesis that we're short supply with all the associated gas offline in North America. And so therefore, with the demand looks like it's pretty robust still even with COVID, gas prices moving upwards because of this thesis that we're short supply. And then the counterargument, of course, is but the world is long gas, and there's a lot of cheap LNG on the water, and does that mean that LNG backs up into North America and helps sort of counter the short supply in North America. So that's the rarest case for gas in North America is the return of the LNG that's supposed to be going out. Now that being said, there was also some reports of Asian countries that have been switching over to more and more LNG to replace their coal. I think one of the things that they've experienced with all of the isolation and shutdown of the economies is that they've got cleaner skies over there, and they've got cleaner air to breathe. And now all of a sudden, the direct linkage between that dirty air they were breathing and the coal they're burning becomes more evident. And does that change public sentiment and government behavior in a way that they push harder to convert more coal to LNG and burn more gas and now start to draw some of that excess gas that's on the water, if you will, over into those countries in a more significant way.

[Doug Younghusband;CIBC World Markets;Analyst]

Good point. I think it's a silver lining there.

[Darren Gee, President, CEO & Director]

Yes, for sure. In the very short term, of course, maybe that stuff doesn't happen that fast because you've got to convert coal-to-gas power generation, and how quickly can that happen? I mean, we saw in the U.S. that that happened over a period of years. But in the short term, it's really probably more about the contracts and whether or not there is the takeaway contracts to ensure that, that gas keeps flowing out of the Gulf of Mexico and out of those contracted LNG facilities. Is that -- over the next 6 months, for instance, is that enough to keep the pull on the LNG there and to prevent it from really backing up too much into the Gulf Coast and back into North America.

[Doug Younghusband;CIBC World Markets;Analyst]

Just one more moving part. Last question. So other than condensate, are your natural gas prices or your natural gas liquids prices being negatively affected by the volatility in oil prices? I know there's some linkage there, but to what extent are they being affected? I know you're moving away, you're constantly doing this balancing act between lean gas and liquids-rich gas. So I presume there's some effect there other than just to the condensate portion of your liquids.

[Darren Gee, President, CEO & Director]

No, you're right. We sell our butane typically as a percentage of oil price. We try to link it to WTI so that, that way, we can actually hedge the oil price, and we get a direct butane hedge. That's the easiest way for us to do that. Butane, though, is typically used in the refineries to produce transportation fuels and the other products that the refineries use. So we sell it locally here to a lot of the refineries in Alberta. And if obviously, demand for gasoline is way down and jet fuels way down and the products that they produce are way down, then they're not going to be needing the same amount of feedstock. And so demand for butane could fall a little bit.Propane is somewhat -- the pricing and the demand supply situation for propane is somewhat driven by the U.S., although we are seeing a little more opportunity for Canadian propane to get exported to the Far East. AltaGas' project, for instance, of Ridley Island, gets us some volume out to that Far East pricing. I think generally, just overall, global demand is soft because of the COVID. And so prices generally have fallen a little bit. But we look at propane and butane storage levels in Western Canada, they're very low. And so we don't have a lot of that product in storage, which is good. In the U.S., propane stocks, for instance, are still, I think, at the high end of their normal storage levels, but they're falling quite quickly. And again, if you take a bunch of U.S. gas offline, then you're taking a bunch of the products that come from U.S. gas offline. So a lot less propane gets produced and perhaps those storage levels for propane rebalance quite quickly. We'll see how demand comes back for propane. Arguably, the demand for plastic products seems to be up. So maybe a lot of the things that we make out of those natural gas liquids, demands for that -- for those products are going to continue to rise and be strong. And so therefore, we'll keep needing a lot of those NGL products.

[Todd Burdick, Vice President of Production]

The Pembina export project too, I believe, is on the near horizon here with respect to exporting propane off of the West Coast. So that will add to really the AltaGas Ridley Island export. I think Pembina's boats will be going to South America with a bunch of that propane. That will add another pull from Western Canadian propane here come -- I think, 2021 is when that's going to start to happen.

[Doug Younghusband;CIBC World Markets;Analyst]

Did -- InterPipe, they announced something on their PDH plant too?

[Todd Burdick, Vice President of Production]

Well, they're still proceeding, but that is...

[Doug Younghusband;CIBC World Markets;Analyst]

Lower and higher costs, is that what they announced? Something like that...

[Todd Burdick, Vice President of Production]

Yes, the cost is still -- they're looking for another partner to try to help absorb some of that cost, but I can't remember the startup, 2022? Yes. And that's another 20,000-some barrels of propane there, so a lot of good positive constructive things on the near-term horizon with regard to the propane market in Western Canada.

[Operator]

Our next question comes from Aaron Bilkoski with TD Securities.

[Aaron Bilkoski, Equity Analyst]

I was just curious, you were one of the few companies to proactively build some internal condensate storage. As sands producers have announced shut-in, have you guys actually seen volumes being shut-in? Are you producing into those storage facilities? Just any color on that would be helpful.

[Darren Gee, President, CEO & Director]

Thanks, Aaron. We haven't yet -- we haven't started to fill any of the condensate storage yet. We saw last month some apportionments on the pipelines that take our condensate away. We did manage to get all of our volumes put to market. And I think for the most part, we've been watching that very closely, and there still seems to be a good opportunity to get our volumes to market. Of course, prices are going to be perhaps another thing that gets determined, and we may have to live with some very weak prices. But as long as we can sort of get our condensate to market then we can at least make that call on the price. We were more concerned, I think, with this condensate storage tank farm that we built, that we wouldn't actually be able to move our product at all. And that would be really disastrous because then we'd have to shut-in all our production. So really, this was somewhat insurance against the pipelines really getting full.We've seen a fair amount of oil supply shut-in, obviously, on the heavy oil side. I think up to 1 million or so barrels a day is shut-in now in Alberta. There is a knock-on impact for sure on condensate demand. What I've heard from at least 1 heavy oil producer, though, was that they were actually continuing to stockpile condensate a little bit because the price was attractive to them, and they had some tankage and rather than fill up their tankage with their own production, they were using some of that tankage actually to store condensate. So in some ways, that -- maybe that condensate market has been artificially propped up by the heavy oil producers who are continuing to buy even though they're not producing. But all this could still come to ahead at any point, right? We've got a lot of volumes that are shut-in. We've got a lot of storage that's being rapidly filled up. And so we needed to be prepared. We thought this was a pretty cheap bit of insurance that we could put in place where -- that would cover us for a short period of time while we reacted to what was going on.

[Operator]

[Operator Instructions] Our next question comes Travis Wood with National Bank Financial.

[Travis Wood, Analyst]

Darren, in your opening remarks, you mentioned kind of costs, both on the capital and operating cost side. So I thought that you set that up to address that. So could you talk about the controllables that you have here in terms of where and how low capital could go through kind of Q2 to Q4? Where you would be comfortable? How low that could possibly be? And then kind of where we could see savings on the operating cost side and perhaps even on the transportation cost side, as you were talking about? Some of that -- so the pipeline issue is taking place at the moment.

[Darren Gee, President, CEO & Director]

Yes, you bet. Maybe, Lee, I'll hitch you up for just some color on capital cost savings, what we've seen in Q1 and maybe what we might see for the rest of the year.

[Lee Russell Curran, Vice President of Drilling & Completions]

Sure. I guess, to start, our species diversity, we've lost a little bit of ground because of redeploying our fleet efforts directed towards some deeper gassier, Spirit River species. So with that, we start to heighten our frac intensity. And so we've lost a little bit of ground on our per well cost on that front, but we continue to see a lot of performance gains. Offsetting a lot of that is a lot higher pad efficiencies. And as we recalibrate on that with kind of new service cost portfolios, we're starting to realize that our pad efficiencies are perhaps much greater than what we've realized historically. So we've kind of got a recalibrated model on that and our schedule coming up reflects a lot more pad operations in our schedule.On top of that, it's a pretty delicate balance right now with our financial health as we consider the financial health of our service contractor fleet, and we do recognize that a number of these guys are really just extensions of our company, and we need them to survive. And so we have a lot of really open, transparent conversations, and we work together. We've seen a lot of oil-based inputs like diesel fuel and drilling fluid base oil fall in excess of 25%. So that's a pretty easy cost reduction to understand. Drilling rig day rates continue to reduce well testing, casing, those types of major inputs that comprise a lot of our capital cost structure have come down in the high single-digit to low double-digit numbers. This industry is hypercompetitive right now. The fact that there's only less than 25 rigs running. Everybody is really thinning up where they can. There's been a lot of employment loss as a result. But everybody is really working together not only to find the bottom line margins that we can work within, but to really put their minds together and find ways to align with our staff and our engineers on improving efficiencies. And so we look at this performance curve that we go through every quarter or every couple of quarters. And every time we look at it, we just -- we sometimes get a little amazed that we still continue to see these performance gains despite drilling a 1000 of these things. And it's really a function of just everybody kind of putting their best heads together and finding ways to improve those time lines.So that's -- so in general, I think we're conservatively anticipating overall 10% reduction, and that's really surrounding what we're seeing on -- in the near term on just service cost pricing reductions. So with some continued efforts on performance improvement, hopefully, that improves. And between that and pad efficiencies, hopefully, we can offset. So the bulk majority if not more than the cost increase we see from increased frac intensity and some deeper, longer laterals.

[Darren Gee, President, CEO & Director]

Okay. So that's the capital side, Travis. Todd, can you put some color on the op costs and our initiatives to reduce those?

[Todd Burdick, Vice President of Production]

Yes, for sure. Like Lee mentioned, we've been talking with service providers, and they've been willing to reduce costs in some areas. So we're going to see that through the year. Basically, since 2018, we've been negotiating road use cost with road owners, and we've seen some pretty good gains on that. We -- at the end of last year, we had 2 significant reductions to a large number of our wells with 2 road owners. And now due to the lag in billing, we won't really see those cost benefits until Q2, but they are -- they will continue in perpetuity. So we'll continue to work on that throughout this year. We're talking to a couple other road owners as well. So hopefully, we can get them to move a little bit on their rates. As I mentioned lubricating oils, we expect those to fall. And again, with methanol, we expect that to fall. We've already seen about a 16% drop in the methanol price from Q1 into Q2 here. So we expect to see that fall throughout the year. And then we usually renegotiate our contract that somewhat floats on the Canadian dollar, but we renegotiate that usually in the summertime at the low price point. So we get a benefit from that.And then as well here early in Q3, we plan to commission our water disposal and -- water disposal well and facility. So that should help us to see a bit of modest reduction in our water handling cost for the rest of the year and going forward. And then I guess a bigger point. Finally, we're starting to see some reduction in government fixed costs. The AER admin fee has been reduced for 2020. We have indications that property taxes will be reduced. We don't know exactly what that number will be yet. We've got -- we're hoping that it's significant. We're -- cap has been asking and working with the government for quite some time, about 1.5 years here. So hopefully, we'll see something meaningful come from that and something beyond 2020. I think with the AER, I think they've agreed that their budget will be reduced going forward, so that will be something that's not just 2020.

[Darren Gee, President, CEO & Director]

Okay. Good. Travis, does that answer your most to that?

[Travis Wood, Analyst]

Yes, that's great.

[Operator]

Our next question comes from [ Derrick Wenger ] with -- a private investor.

[Unknown Attendee]

Yes. 2 questions. I came in late. I apologize. One, when would the balance sheet be published? And two, was there any change to the dividend?

[Darren Gee, President, CEO & Director]

No change to the dividend this quarter. Obviously, we announced prior to coming into the quarter that we were reducing the dividend significantly. That was really on the heels of a lot of the OPEC+ activity and then the further impact of COVID-19 on demand when we finally started to see the evolution of the commodity price tape after all that change. In Q1, we announced that we were taking the dividend down to $0.01 a quarter. We're cutting our capital back by $50 million midpoint of guidance. So we had made those adjustments really coming into the quarter. With respect to balance sheet, are you talking about the banks and our bank liquidity and that kind of thing or...?

[Unknown Attendee]

No, I'm just talking about the balance sheet in general. I didn't see it on the press release, and I don't see it on SEDAR.

[Kathy Turgeon, VP of Finance, CFO & Director]

It's not SEDAR filed. It is on our website. If you go into the press release and click on the link, at the end of the press release, it will take you directly to the financial statements and to the MD&A. Alternatively, you can go directly to our website, www.peyto.com. And you can get to the financial reports. Under financial updates, there's a link on the front page that will take you right to the financial statements.

[Operator]

I'm not showing any further questions at this time. I would now like to turn the call back over to Darren Gee for closing remarks.

[Darren Gee, President, CEO & Director]

Okay. Thanks, Joel. Is there one more question there?

[Operator]

Yes. And the question comes from [ Stephen Young ], a private investor.

[Unknown Attendee]

I think no one expected the AECO prices would do so well relative to the North American prices. But -- so diversification and hedging was a very quick move. I just noticed that the diversifying activity costs about $0.88, which is slightly better than the previous quarter. Could you elaborate more about this whether the trend will keep on going down or what the benefits of the -- future benefits of the diversification?

[Darren Gee, President, CEO & Director]

[ Stephen ], that's a great question. So in the winter months, our basis differential between AECO and NYMEX that we locked in is about $0.10 cheaper than in the summer months. So that's part of the reason that maybe the diversification activities are getting a little bit cheaper. But also, we've diversified to a couple of other hubs. So we've got some diversification not just to NYMEX, but also to Ventura, Emerson. We now actually going forward, added on some Malin diversification as well. All of this is still very expensive relative to the existing basis today. And as you pointed out, the AECO market strengthened a lot more than anybody really expected and that tightened the basis differential between AECO and NYMEX. We put a lot of these bases diversification deals in place a year or 2 ago when AECO was $1.50 and NYMEX was $3. And so at the time, that was the cost to get out of AECO and get to some of these other hubs. And at the time, we didn't know AECO was going to be reconnected or fixed. It was very much a broken market for about 2 years, and we were suffering through that significantly. We couldn't hedge, few forward or add AECO because we were at prices that were too low. A lot of times there, we had even negative prices. So we really had to direct our gas elsewhere and the cost to get elsewhere was very expensive. We took short-term diversification initiatives rather than sign up for 10 years' worth of pipe contracts, for instance, to get our gas physically all the way to a market elsewhere. We took some synthetic short-term financial basis deals that put our gas at NYMEX. But they were very expensive, and we're now paying the price for that and will for probably another year. But the fact that they were short-term and they were financial means we can work with them. When NYMEX has been strong enough, we've definitely been hedging to fix the price at NYMEX, so that, combined with that basis, gives us a fixed equivalent price back in Alberta. And if we can get anything over really CAD 2, we're doing just fine at Peyto. It's the $1.50, that was obviously a bit of a tough slug for us.But yes, going forward, AECO looks very good. Arguably, if we could just direct all our gas to the AECO market today, we'd be doing even a lot better on the gas price realizations and the cash flows. But hindsight, it's always 2020, and nobody really knew that the market at AECO could be fixed this significantly and be this strong. Arguably, you might suggest that the 2 years of $1.5 AECO, were obviously driving a lot of producer behavior. There was a lot less gas being developed in our basin. And so now we find ourselves a bit short in the basin, which is providing strength in the price whereas now, it's only really in the last 6 months or so that the U.S. market has seen these very soft gas prices that are now driving producer behavior. And so they're all starting to slow down and invest less and their supply is starting to turn over. And this was really before the associated gas shut-ins came along. We were starting to see this thesis down in the U.S.So they're going through arguably a transition similar to how we had to in Western Canada. So hopefully, on the back end of both of those transitions, we're going to see much more constructive gas prices in both markets. I think we're still a little bit shy of the AECO market, knowing what we've been through and having experienced it. We're still a bit cautious, directing all of our gas at that market. I think we still believe in the diversification of our gas portfolio, the way we have it, a good portion to the U.S. market, a portion to the Canadian market. And quite frankly, the -- we'd love to even increase the proportion that we have that's directly connected to industry in Alberta that completely avoids the pipe. That way, we can share in the economic rent with the consumer ultimately directly, and I think that's going to benefit us a lot. As an example, this past winter, particularly in January, we had some extremely cold weather that drove power prices up in Alberta. If we had been connected at that time to the Cascade power plant that we are going to be direct connected to in a couple of years' time. Scott, what were you looking at the power prices versus the gas prices?

[Scott Robinson, Vice President of Business Development]

We would have made a fortune. No, power price peaked to the maximum of $1,000 for about a week or just under a week in January, but it's interesting. For January, overall, the average, we would have made $10 a gigajoule and a round number for our gas for that portion that we would have sold, have it been running. And for the first quarter, we would have made right around $5 based on the power prices that Alberta experienced and our pricing for the gas that we deliver. And above and beyond that, we'd save, whatever, $0.20 to $0.40 of transportation costs by putting the gas directly into those -- into that power plant off of the Inter-Alberta system. So those are, yes, very promising future aspects to our market diversification that haven't kicked in yet, but they are -- we're excited about them and they're on their horizon, and there's a real will in Alberta to see natural gas and power become more prevalent in our power delivery. We're part of the LNG consortium as well, and that's another thing out there on the horizon that there's some earlier discussion on the soft LNG prices, but Darren alluded to the fact that the Asian countries, although they've had a bit of a soft winter and has been compounded by the demand destruction with COVID, there's still a really strong move to natural gas substitution of coal and a lot of these facilities are going to feed into that. Again, we'd like to be part of that if the ingredients are right for that particular marketing opportunity.

[Darren Gee, President, CEO & Director]

Yes. So that's a little more color on the diversification, [ Stephen ]. Hopefully, that answers your question?

[Unknown Attendee]

Thanks. You answered it.

[Operator]

I'm not showing any further questions at this time. I would now like to turn the call back over to Darren Gee for closing remarks.

[Darren Gee, President, CEO & Director]

Okay. Well, thanks, Joel, and thanks, everybody, for listening in this morning and for a lot of those good questions. We're hopefully through the worst of it now with respect to both the pandemic and perhaps some of the commodity market disruption. And hopefully, we're on the recovery as slow as it may be. The bright spot for natural gas, obviously, is as we take oil offline because we've got too much in storage and the associated gas comes off, and we're short gas in North America. So Peyto is pretty excited about that prospect and finally getting some more constructive gas prices moving forward. Obviously, we're a gas company with 85% of our production basically focused on natural gas. So all of that is very good for our cash flows and makes us quite a bit stronger. We're looking forward to getting through this summer into next winter where we can even enjoy stronger gas prices again. So we'll be back to you in Q2 to let you know how breakup is gone, and how we got back out in the field. Hopefully, the spring rains won't be too bad. And we'll be back taking advantage of some of these great opportunities that we see on the horizon. So stay tuned, and we'll talk to you after the second quarter.

[Operator]

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.