Ladies and gentlemen, thank you for standing by, and welcome to Peyto's first quarter 2020 financial results conference call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question and answer session. To ask a question during the session, you will need to press star one on your telephone. If you require any further assistance, please press star zero. I would now like to hand the conference to our speaker today, Darren Gee, President and Chief Executive Officer. Please go ahead, sir.
Okay. Well, thanks, Joelle, good morning, ladies and gentlemen. Thanks for tuning in to Peyto's first quarter 2020 results conference call. Before we get started today, we'd 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 m spacing rules, we've got the full management team. We've got JP Lachance, our VP of Engineering and Chief Operating Officer. Kathy Turgeon is here with her, Chief Financial 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. 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 fears 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. We were all extremely careful and successfully got the job done. 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.
Congratulations to the whole team on a job well done. I'd also like to take this opportunity to thank all of our frontline healthcare workers in the province who are also putting their lives at risk every day to ensure that we have the full capacity of the healthcare system available to all those Albertans that are in need. Onto 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. 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. I suppose so far that's not been the case. However, our team here at Peyto remained 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. 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. 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.
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, drier 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'd 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 the oil supply side, as now we had potential shut-ins being promoted. Storage was filling rapidly.
The OPEC plus plus 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. 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. 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 were 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. Lee is here this morning. Hopefully, he can talk a little more about how those might continue to evolve this year. 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. We've got some great initiatives for the rest of the year, which 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 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 would the demand for condensate.
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 two to three 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. 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 out 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. Even with our low costs, that translated into the lowest net back 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 non-cash impairment of around CAD 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. Unfortunately, the extreme volatility in commodity prices translated into fairly extreme volatility in our earnings. 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. Joelle, perhaps we could throw the line open and just take some questions from those listening in.
Thank you. As a reminder, to ask a question, you'll need to press star one on your telephone. To withdraw your question, press the pound key. Please stand by while we compile the Q&A roster. Our first question comes from Fai Lee with Odlum Brown. Your line is now open.
Hi. It's Fai here. Darren, I just want to talk a little about the impairment test that was performed. Does it reflect your hedges in place and the diversification arrangements?
Yes, it does. Those arrangements were included in the reserve evaluation. 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 thousands more locations, obviously, to choose from, and the independent reservoir engineering firm will pick from those for the next five 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. We try to direct them a little bit as to what's the most profitable looking species that we're drilling from. For the last year or two, it's been the Cardium with its high liquid yields. 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 dramatic change in the commodity price, we would bring a lot more of our drier gas opportunities forward earlier in the forecast for development.
There's little sort of changes within the way the reserve reports are constructed that don't adapt to such a dramatic change in commodity prices, obviously. The reserve report is relatively fulsome in that it reflects all the parts of our business.
Okay. That's kind of where my follow-up was going to go. It looks like one of the criticisms of the reserve engineers is that the price assumptions or the valuation companies, the price assumptions they use have always seemed to be quite aggressive relative to where the forward strips are or where current prices are. Certainly, the deck looks, what you've outlined in the NDA, looks a lot more realistic. In terms of valuing your book value, which is close to, I guess, CAD 10 per share, it seems like, am I interpreting correctly when it looks like it's more representative of the NPV 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.
Yeah. 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. 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 costs. When they're looking forward and forecasting what they think commodity prices are going to be, yeah, of course, they, I'm sure, incorporate what the strip is going to look like. They also know what the industry's supply cost is.
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. 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? In some ways, we can criticize them for their belief in the commodity price being different than the strip. The reality is, the strip sometimes isn't all that right either. 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?
We like to beat on those guys because, yeah, they make a forecast of commodity prices, and everybody who makes a forecast of commodity prices is generally wrong. Nobody really knows what the forecast is going to be. These guys go out on a limb, and in their defense, they do see what everybody's conversion costs are. From that, I'm sure they determine what the commodity price needs to be. Maybe, when we look at the independent engineering firms and we see a forecast that's higher than the strip today, what we really should conclude from that is that the supply cost is actually higher than the strip today. One would expect that activity levels would probably drop off if those strip prices continue to persist. They have to get above what the company's supply costs really are to be manageable.
Okay.
Sorry, that doesn't really answer your question. It's a little bit more background, perhaps information on those independent engineering firms.
No, I was just wondering.
All this stuff is changing quite rapidly, and next quarter, we're probably going to see significantly different forecasts from those guys, and that's going to flow through to a significantly different impact on our reserve values. 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.
Okay. The book value of your assets now, it seems like with the impairment and the changes, it seems to match You're marking to market almost a bit to the assumptions laid out by the reserve evaluators. Is that kind of the way to think about it?
I don't know. Is that how you would look at it, Kath? I don't think from a book value perspective.
I'm not really clear on.
Sorry, Fai, I'm not sure what you're getting at, but.
Yeah.
Okay. Maybe I'll follow up offline with you.
Okay.
Thanks.
One thing to just add, Darren, which you covered that well, the reserve companies have begun to calibrate the near-term prices a lot closer to the strip. The strip at the end of the year is just what would be erroneous to just plug in a current momentary strip that occurs at the end of the year. It can vary quite a bit over the course of the year, depending on the season. I think the reserve engineers, as you stated, are trying to look at the big picture and the true supply-demand on the out years while calibrating the in-years or the near years closer to that strip.
Okay. Thanks. That's all for me for now. Thanks.
Okay. Thanks, Fai.
Thank you. Our next question comes from Doug Younghusband with CIBC World Markets. Your line is now open.
Yeah. Thank you for taking my call. Lots of moving parts. Not always fun, but it's never boring, right?
You say so, Doug.
You mentioned higher costs in the quarter due to COVID preparation. I'm presuming those are expense costs, but over time, they'll average out in future quarters, I'm hoping. Were they sort of one-off additional costs?
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?
Add those points down, for sure. Typically, in the winter, as well, methanol prices typically go up because demand goes up in Alberta. Q1 is typically higher. This year, we weren't too sure what the supply chain might do, so we did purchase a few things, some 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. It accounted for some, but not a lot, and it will average out into Q2. That stuff, we didn't use any more. It's just kind of sitting in inventory at the moment.
Sure.
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. I don't think too many people saw that one coming.
Yeah.
Yeah, I don't think so.
You know, we are anticipating lubricating oils to go down. It's not a one-to-one 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. As well, it's tied to the Canadian dollar.
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? The sort of simple view is Qatar can't sell its gas at a reasonable price, so they've got a surplus. Maybe some of the export capacity out of continental U.S.A. is going to get backed up or is backing up, which then affects Canadian prices, which moves south or volumes moving south. Is that a potential scenario to Canadian prices or North American prices?
Yeah, 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. 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. 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 that LNG backs up into North America and helps sort of counter the short supply in North America? That's the bearish 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 isolations and shutdown of their economies is that they've got cleaner skies over there, and they've got cleaner air to breathe. Now all of a sudden, the direct linkage between that dirty air they were breathing and the coal they're burning becomes more evident. 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?
Good point. Maybe a silver lining there.
Yeah, 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. How quickly can that happen? We saw in the U.S. that that happened over a period of years. 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-
Right
LNG facilities. Over the next six 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?
Just one more moving part. Last question.
Yeah.
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. 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. I presume there's some effect there other than just to the condensate portion of your liquids.
No, you're right. We sell our butane typically as a percentage of oil price. We try to link it to WTI so 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. We sell it locally here to a lot of the refineries in Alberta. If, obviously, demand for gasoline is way down and jet fuel is way down and the products that they produce are way down, then they're not going to be needing the same amount of feedstock.
Right.
Demand for butane could fall a little bit. Propane is 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, off 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, prices generally have fallen a little bit. We look at propane and butane storage levels in Western Canada. They're very low, 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, they're falling quite quickly.
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. 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 those products are going to continue to rise and be strong, and so therefore, we'll keep needing a lot of those NGL products.
The Pembina export project, too, I believe, is on the near horizon here with respect to exporting propane off of the West Coast. That will add to Ridley, 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.
Did Inter Pipeline, did they announce something on their PDH plant, too ?
Well, they're still proceeding.
Lower and higher cost? Is that what they announced? Something like that.
Well, yeah, the cost is still. They're looking for another partner to try to help absorb some of that cost. I can't remember the startup date. 2022?
Yeah.
Yeah. Well, that's another 20-some thousand barrels of propane a day. A lot of good positive constructive things on the near-term horizon with regard to the propane market in Western Canada.
Gentlemen, thank you. Carry on.
Yeah, you bet.
Thank you. Our next question comes from Aaron Bilkoski with TD Securities. Your line is now open.
Thanks. Morning, guys. I was just curious, you were one of the few companies to proactively build some internal condensate storage. As sands producers have announced shut-ins, have you guys actually seen volumes being shut in? Are you producing into those storage facilities? Just any color on that would be helpful.
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. 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. 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, that would be really disastrous because we'd have to shut in all our production. 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 one 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. In some ways, 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. All this could still come to a head 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. We needed to be prepared.
We thought this was a pretty cheap bit of insurance that we could put in place that would cover us for a short period of time while we reacted to what was going on.
Oh, perfect. Thanks for that.
You bet.
Thank you. As a reminder, to ask a question, you will need to press star one on your telephone. Our next question comes from Travis Wood with National Bank Financial. Your line is now open.
Yeah. Good morning, guys. Darren, in your-
Hi, Travis.
opening remarks, you mentioned kind of costs both on the capital and operating cost side. I thought that you set that up to address that. 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 the pipeline issues taking place at the moment?
Yeah, you bet. Maybe Lee, I will hit you up for just some color on capital cost savings, what we have seen in Q1 and maybe what we might see for the rest of the year.
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. With that, we're starting to heighten our frack intensity. We've lost a little bit of ground on our per well cost on that front. We continue to see a lot of performance gains. Offsetting a lot of that is a lot higher pad efficiencies. 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. 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. We have a lot of really open, transparent conversations. We work together. We've seen a lot of oil-based inputs, like diesel fuel and drilling fluid-based oil fall in excess of 25%. 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's really thinning up where they can. There's been a lot of employment loss as a result. Everybody's 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. 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 sometimes get a little amazed that we still continue to see these performance gains despite drilling 1,000 of these things. It's really a function of just everybody kind of putting their best heads together and finding ways to improve those timelines.
In general, I think we're conservatively anticipating overall 10% reduction, and that's really surrounding what we're seeing in the near term on just service cost pricing reductions. With some continued efforts on performance improvement, hopefully that improves, and between that and pad efficiencies, hopefully we can offset the bulk majority, if not more than the cost increase we see from increased frack intensity and some deeper, longer laterals.
Okay. That's the capital side, Travis. Todd, can you put some color on the op costs and initiatives to reduce those.
Yeah, for sure. Like Lee mentioned, we've been talking with service providers, and they've been willing to reduce costs in some areas. We're going to see that through the year. Basically, since 2018, we've been negotiating road use costs with road owners, and we've seen some pretty good gains on that. At the end of last year, we had two significant reductions to a large number of our wells with two road owners. Now, due to the lag in billing, we won't really see those cost benefits until Q2, but they will continue in perpetuity. We'll continue to work on that throughout this year. We're talking to a couple other road owners as well. Hopefully, we can get them to move a little bit on their rates. As I mentioned, lubricating oils, we expect those to fall. 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. We expect to see that fall throughout the year. We usually renegotiate our contract that somewhat floats on the Canadian dollar, but that we renegotiate that usually in the summertime at the low price point. We get a benefit from that. As well, here early in Q3, we plan to commission our water disposal well and facility. That should help us to see a bit of a modest reduction in our water handling costs for the rest of the year and going forward. I guess a bigger point, finally, we're starting to see some reduction in government fixed costs. We know 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're hoping that it's significant. CAPP has been asking and working with the government for quite some time, about a year and a half here. Hopefully we'll see something meaningful come from that, and something beyond 2020. I think with AER, I think they've agreed that their budget will be reduced going forward, so that will be something that's not just 2020.
Yeah. Okay, good. Travis, does that answer most of that?
Yes. That's great. Thank you.
Thank you. Our next question comes from Derek Wenger with a private investor. Your line is now open.
Yes. Two questions. I came in late. I apologize. One, when will the balance sheet be published? Two, was there any change to the dividend?
No change to the dividend this quarter. 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. 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 CAD 0.01 a quarter. We're cutting our capital back by CAD 50 million midpoint of guidance. 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
No, I'm just talking about the balance sheet in general. I didn't see it on the press release. I don't see it on SEDAR.
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.
Okay. Thank you. I'm sorry.
Yeah, no problem.
Thank you. 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.
Okay. Thanks, Joelle. Is there one more question there?
Yes. The question comes from Steven Young with a private investor. Your line is now open.
Thank you for taking my call. I think no one expected the AECO prices would do so well relative to the North American prices. Diversification and hedging was a very quick move. I just noticed that the diversifying activity costs about CAD 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 future benefits of the diversification? Thank you.
Steven, that's a great question. In the winter months, our basis differential between AECO and NYMEX that we locked in is about CAD 0.10 cheaper than in the summer months. That's part of the reason that maybe the diversification activities are getting a little bit cheaper. Also we've diversified to a couple of other hubs. We've got some diversification, not just to NYMEX, but also to Ventura, Emerson. We've now actually going forward added on some Malin diversification as well. All of this is still very expensive relative to the existing basis today. 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 basis diversification deals in place a year or two ago when AECO was a CAD 1.50 and NYMEX was CAD 3.
At the time, that was the cost to get out of AECO and get to some of these other hubs. At the time, we didn't know AECO was going to be reconnected or fixed. It was very much a broken market for about two years. We were suffering through that significantly. We couldn't hedge forward at AECO because we were at prices that were too low. A lot of times there, we had even negative prices. 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.
They were very expensive, and we're now paying the price for that and will for probably another year. 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 that combined with that basis gives us a fixed equivalent price back in Alberta. If we can get anything over really CAD 2, we're doing just fine at Peyto. It's the CAD 1.50 that was obviously a bit of a tough slug for us. 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.
Hindsight'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 two years of the CAD 1.50 AECO were obviously driving a lot of producer behavior. There was a lot less gas being developed in our basin, now we find ourselves a bit short in the basin, which is providing strength in the price. Now, it's only really in the last six months or so that the U.S. market has seen these very soft gas prices that are now driving producer behavior. 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.
They're going through, arguably, a transition similar to how we had to in Western Canada. 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, quite frankly, 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 Project that we are going to be direct connected to in a couple years' time Scott, what were you looking at, the power prices versus the gas prices?
Would've made a fortune.
Yeah.
No, power price peaked to the maximum of CAD 1,000.
Makes a lot of Canadian dollars there.
for about a week or just under a week in January. It's interesting. For January, overall the average, we would've made CAD 10 a gigajoule in a round number for our gas for that portion that we would've sold had they been running. For the first quarter, we would've made right around CAD 5 based on the power prices that Alberta experienced and our pricing formula for the gas that we deliver. Above and beyond that, we save CAD 0.20-CAD 0.40 of transportation costs by putting the gas directly into that power plant off of the intra-Alberta system. Those are very promising future aspects to our market diversification that haven't kicked in yet, but we're excited about them, and they're on the 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. That's another thing out there on the horizon that there's some earlier discussion on the soft LNG prices. Darren alluded to the fact that the Asian countries, although they've had a bit of a soft winter, and it's been compounded by the demand destruction with COVID-19, there's still a really strong move to natural gas substitution of coal. A lot of these facilities are going to feed into that. We'd like to be part of that if the ingredients are right for that particular marketing opportunity.
That's a little more color on the diversification, Steven. Hopefully that answers your question.
Thanks. You answered it.
Thank you. 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.
Okay. Well, thanks, Joelle, 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. 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. Peyto's 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. We'll be back to you in Q2 to let you know how breakup's 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. Stay tuned, and we'll talk to you after the second quarter.
Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.