Earnings Call: Q3 2019

Nov 7, 2019

Ladies and gentlemen, thank you for standing by, and welcome to TransAlta Corporation Third Quarter 2019 Results Conference Call. At this time, all participants are in a listen only mode. After the speakers' presentation, there will be a question and answer session. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Kiara Valentin, Manager, Investor Relations. Thank you. Please go ahead. Thank you, Chantal. Good morning, everyone, and welcome to TransAlta's Q3 2019 conference call. With me today are Don Farrell, President and Chief Executive Officer Todd Stack, Chief Financial Officer John Kousinjoris, Chief Operating Officer and Brett Gellner, Chief Development Officer. Today's call is webcast, and I invite those listening on the phone lines to view the supporting slides that are currently available on our website. A replay of the call will be available later today and the transcript will be posted to our website shortly thereafter. As usual, all of the information provided during this conference call is subject to the forward looking statement qualifications set out here on Slide 2, detailed in our MD and A and also incorporated in full for the purposes of today's call. All amounts referenced during the call are in Canadian currency, unless otherwise noted. The non IFRS terminology used, including comparable EBITDA, funds from operations and free cash flow are also reconciled in the MD and A for your reference. On today's call, Don and Todd will review the quarterly and year to date results and expectations for the remainder of the year. In addition, we'll provide commentary on our recent announcements and how these advance our clean energy investment plan and growth strategy that we outlined at our Investor Day back in September. After these prepared remarks, we will open the call for questions. And with that, let me turn the call over to Dawn. Okay. Thanks, Kiara, and welcome everyone the call today. We're pretty excited to be here announcing our Q3 results. We did have a strong Q3 and we're pleased with the results across all of our businesses. And of course, strength in the Q3 has given us strong performance year to date and it's increased our expectations for annual performance. Now overall, our operational and financial performance is tracking to deliver a strong year. Our clean energy investment plan and growth strategy is on track and through the quarter we hit key milestones, which I think has been very impressive in terms of what the team has done. And finally, we successfully concluded the final leg of our Sundance DPA arbitration and collected an additional one time payment of $56,000,000 from the balancing pool, which is great news because it has added to our cash flow for the year. So I'm going to just start with a couple of overall comments on our financial performance and of course Todd will get into more of the detail. We earned a total of $305,000,000 of comparable EBITDA in the quarter due to strong performance at our Canadian and U. S. Coal businesses, our Energy Marketing segment, from the efforts and the work that's been done across the company to reduce our OM and A costs and of course because of the one time PPA payment. Now if you take out the one time PPA payment, our EBITDA was flat for the quarter relative to last year. Now what's important here is that the Mississauga and Poplar Creek contract changes that occurred at the end of 2018 we're expected to reduce our EBITDA in the quarter by approximately $30,000,000 So to be able to deliver flat year over year EBITDA with these changes shows that we've been able to increase performance in our remaining key business segments. We see this increased performance as sustainable for a number of reasons and we'll talk with you about that through the call. In total, we've now received $213,000,000 from the balancing pool related to the termination of the Sundance PPAs. I'm especially proud of our team. They held a strong view that the money assets were part of the PPA and I believe that the final payout was a very principled decision. Overall, our free cash flow results for the quarter are also trending ahead of 2018 And the results are for the quarter were in the following areas. Now first of all, strong availability we saw strong availability across the fleet with some of the strongest availability results that we've seen. The entire fleet had availability of 95.2% for the quarter compared to a pretty high availability in the last year in 2018 of 93.7%. This was due to fewer unplanned outage hours and fewer derates at both the Centralia and the Sundance units. Now although the Alberta market saw weaker prices in Q3 relative to 2018, we continue to maintain high realized prices for our Alberta coal fleet with an over 40% premium to the pool price. Our fuel and carbon cost per megawatt hour were lower due to the availability of due to the ability of the Alberta coal units to co fire with the Pioneer pipeline gas, which did come online 4 months ahead of plan, which was just excellent results by the team. Overall, comparable gross margins at Canadian Coal have improved primarily due to the benefits of co firing. We expect to realize further co firing benefits as we reach firm throughput of approximately 130 millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeterscf per day of natural gas commencing this month. Centralia delivered a strong quarter despite lower pricing in the Pac Northwest due to their higher availability from fewer planned outages and strong performance in Q3 enabled us to partially recover some of the loss that they experienced in the Q1. And of course, we continue to deliver OM and A reductions as we transition the fleet. Year to date, we're tracking to 7% reduced OM and A compared to last year. As we look forward at the balance of 2019, we continue to expect strong performance from our businesses. Year to date results combined with our forecast provide us with the confidence to both revise and tighten the free cash flow range to $300,000,000 to $340,000,000 for the full year. So let me turn now to talk about our strategy. Just before I talk more about the milestones we achieved, I do want to briefly comment on the TIER program that the government of Alberta announced last week. In short and simply put, it was exactly what we expected. The carbon levy will remain at $30 a ton with a performance standard for our business, which is at 0.37, which is best gas. This standard will be reviewed every 5 years. We finally have clarity on the credits that we'll receive across our extensive renewable fleet in Alberta. All of our Alberta wind and hydro assets will receive green credits for their generation based off the previously mentioned performance standard. We expect these credits to be worth approximately $30,000,000 annually at the current carbon prices. The clarity on this policy and renewable credits are yet another step in the right direction that support the strategy that we've laid out for you here in Alberta. So let me now turn to our strategy. We are very pleased with the progress we made through the quarter on our clean energy investment plan. Last week, we moved forward with the acquisition of 2, 230 Megawatt Siemens F Class gas turbines and related equipment by buying the KinetiCorp business. TransAlta will redeploy these assets to its Sundance site as part of its strategy to repower Sundance Unit 5 to a highly efficient combined cycle unit by integrating these gas turbines into the existing steam turbines. The acquisition also results in the company assuming a long term non unit contingent power arrangement starting in 2023 with Shell, a strong investment grade company that is also committed to providing more and cleaner energy for Albertans. This advances our coal to gas conversion project by 3 to 6 months. Our initial plans discussed at Investor Day included possible repowering options at both Sundance Unit 5 and KeyPel's Unit 1 for a combined cost of about $1,000,000,000 and total megawatts of $11.80 Changing the plan slightly and installing the 2 F class turbines together at Sun 5 will provide 7 30 megawatts of capacity earlier than expected at a cost of approximately $760,000,000 We like that this plan allows us to have more flexibility in dispatching with 2 units and it gets us to the market with cleaner energy sooner. We do retain an option to repower Keephills 1 to a simple conversion in 2022 as an interim step. And as you all know, the carbon levy here in Alberta has a quick payback, which provides a clear incentive for us to really consider this decision. In the meantime, we'll also continue to permit Keypales 1 as a combined cycle and continue to execute the project to meet the financial targets that were outlined at Investor Day as we move into a fully deregulated market. For the remaining coal fleet, the boiler conversions are well underway. In early July, we issued final notice to proceed on our Sundance Unit 6 and are planning to complete the conversion of that unit in the second half of 2020. We have also we have since also issued limited notice to proceed for the Keypails Unit 2, coal to gas boiler conversion. Our on-site generation strategy, on our on-site generation strategy, we told you at Investor Day that we were expecting, to potentially announce a project, which we did. We executed an agreement with SemCAMS Midstream to construct and operate a new cogeneration facility. Subject to the satisfaction of certain conditions, SemCAMS will purchase 50% of the plant at COD and detailed construction activities have commenced and COD is targeted for mid-twenty 21. Our investments in renewable energy projects under construction are also progressing to plan. All the towers and turbines are now fully erect at both sites. Antrim and Big Level are on track to deliver COD by late later this year in 2019. Windrise execution has also commenced. We were excited and surprised, but very excited to receive AUC approval for the Windrise project ahead of schedule, providing further opportunities to optimize the construction costs and integration. And Windrise is targeted still for a 2021 COD date. Turning to Slide 7, you can see how these growth projects will lift our future EBITDA. We expect to see the benefits of Big Level and Antrim later this year and next year we'll start to see some of the benefits from Skookumchuck as it comes into service sometime mid year. By 2022, we expect to have approximately $60,000,000 of EBITDA added to our run rate. And over the next 3 years, we will have commissioned 6 projects, which required a capital investment of approximately $890,000,000 So I'll now turn the call over to Todd to walk you through greater detail on our financial results in the quarter year to date. Thank you, Don, and welcome to everyone on the call. Before I jump into the financial and operational results, I'd like to start by reviewing the Alberta and Midsea power price trends and what we're expecting for the remainder of the year. In Alberta, the power price during the quarter was weaker when compared to last year, primarily due to a cooler than normal summer in the province, which reduced the number of high load days. The average price in the Q3 was $47 a megawatt hour compared to $55 per megawatt hour in 2018. Even with the lower average market price, our merchant coal assets performed well and we were able to realize a power price significantly higher than the average pool price. For the remainder of 2019, forward curve is in the $58 per megawatt hour range. However, we are highly hedged with approximately 85 percent of our expected production in Alberta hedged for Q4. For the full year 2019, we expect power prices to average approximately $57 As we look at 2020, the final year where our Alberta assets will be under their PPAs, the forward curve is around $55 per megawatt hour, which is supportive of our merchant fleet in the province. The midsea price in the Pacific Northwest settled at US28 dollars per megawatt hour for the 3rd quarter compared to US46 dollars per megawatt hour in 2018. Pricing in 2019 represents a more normalized level, whereas 2018 was positively impacted by a very strong demand in the U. S. West region. For the balance of 2019, production in our Centralia facility is about 85% hedged. Slide 9 breaks down the performance of our Canadian coal fleet and helps highlight the benefits we are seeing from decisions made in 2018. While overall revenues and productions were lower in Q3 compared to 2018, comparable gross margin improved from $103,000,000 to $106,000,000 in 2019. On a per megawatt hour basis, gross margin in Q3 improved year over year by 13%. Excluding the one time $56,000,000 PPA settlement received in Q3, comparable EBITDA increased by $6,000,000 from $73,000,000 last year to $79,000,000 in 20 19. EBITDA margins increased by $5 per megawatt hour from $21 per megawatt hour to $26 per megawatt hour in 20.19. This represents an approximate 24% improvement to EBITDA margins driven by both higher realized price and lower fuel and carbon costs. In Q3, our average realized price per megawatt hour was $67 versus the average pool price of 47 dollars Higher realized prices are driven by ongoing hedging, revenue from ancillary service sales and effectively dispatching our plants during high price periods. We continue to see lower fuel, carbon costs and purchase power due to the increase in co firing during the quarter where we benefited from additional gas but due to the low AECO gas price, which averaged around $1 per GJ during the quarter, co firing greatly reduced the input cost to generate the power. The firm contract on the Pioneer pipeline began November 1, which will further increase our ability to operate on gas. For the 9 months ended September 30, the trend is similar. Excluding the PPA settlements, EBITDA at Canadian Coal increased from 184,000,000 dollars in 2018 to $208,000,000 in 20 19, a 13% increase. EBITDA margins improved from $17 a megawatt hour to $22 per megawatt hour, nearly a 30% improvement in margins. Our overall results for the Q3 were strong and modestly above our expectations. Comparable EBITDA excluding the PPA settlements was similar compared to 2018 with free cash flow increasing by $20,000,000 to $114,000,000 in 20.19 versus $94,000,000 in 20.18. This was a result of strong performance from our business and lower sustaining capital spend in the quarter. Keep in mind that these numbers include the loss of Mississauga and the Poplar Creek contract changes, which previously provided about $30,000,000 of EBITDA in the Q3 of 2018. On slide 10, we've bridged our year to date EBITDA and segment cash flows for 2019 versus 2018 and we've shown the impact of the contract changes to our results. Excluding the impact of these known changes these known contract changes, we delivered EBITDA and segment cash flows higher than last year and in line with our expectations for the 3 9 months ended September 30. Similar to last year, our energy marketing team generated strong cash flows of $30,000,000 in the Q3. For the 9 months ended September 30, cash flows from the energy marketing business have delivered $51,000,000 better than 20 18. Energy Marketing continues to deliver strong cash flow, primarily due to the gain they experienced in the Pacific Northwest in Q1, as well as their ability to capitalize on high levels of volatility across North American power markets. The results come from real time and day ahead trading in the Western market and have a positive impact on cash in 2019 without increasing the overall risk profile of the Energy Marketing Business segment. In the Canadian Gas segment, excluding the impact of contract changes, EBITDA improved by $3,000,000 in the quarter and $14,000,000 for the 9 months ended September 30 when compared to 2018. The improvement was primarily due to lower OM and A compared to the prior year and lower fuel costs at Sarnia due to less steam demand from customer planned outages. Our hydro business delivered good results, generating EBITDA of $28,000,000 in the quarter $92,000,000 for the 9 months. When compared to last year, hydro for the Q3 of 2019 had higher generation due to higher water resources. However, total gross revenue decreased slightly due to unfavorable power and ancillary pricing in the quarter. After net payments relating to the Alberta hydro PPA, comparable EBITDA for the 3 9 months ended September 30 was consistent with the same periods in 2018. As described on Slide 9, Canadian coal delivered significantly higher EBITDA in the Q3 9 months versus 2018. However, this improvement was offset by lower results at U. S. Coal due to the unplanned outage in Q1. Coal segment cash flows were also negatively impacted by the additional planned maintenance at Sundance Unit 4 and on Keephills Unit 1. There were no planned outages in 2018 in our Canadian coal business. On slide 11, we're again showing the buildup of our hydro PPA EBITDA to help illustrate the upside of the hydro assets once the PPA expires at the end of 2020. For the 9 months ended September 30, our hydro assets generated $92,000,000 in EBITDA. However, they would have generated $202,000,000 if the PPA obligation payments did not exist. Lastly, I'd like to provide updates on a few other points. As most of you would have seen from our press release this morning, we have revised our free cash flow outlook range upwards for the full year 2019. Our prior range of $270,000,000 to $330,000,000 has been shifted to the new range of $300,000,000 to $340,000,000 based on the continuing strong performance from our business. I would note that the one time PPA settlement of $56,000,000 is not included in this outlook, but does represent additional cash available to us. Liquidity was very strong in Q3 with $1,400,000,000 available on credit facilities and with $300,000,000 of cash on hand. The cash balances are due to a combination of proceeds resulting from the PPA settlement, positive working capital balances through collateral, timing of capital spend and proceeds from the investment by Brookfield. This liquidity has given us the flexibility to be opportunistic with our equipment acquisitions and funding of our coal to gas investments. During the quarter, we returned $6,000,000 of capital to shareholders through our share buyback program. Our repurchases in the quarter were well below plan driven by an extended blackout period caused by our Q2 reporting cycle and the timing of our Investor Day. We expect to resume share purchases in Q4 and plan to continue to return up to $250,000,000 to common shareholders over the next 3 years through our NCIB. In addition to our boiler conversion and repowering projects, we have 4 gas and renewable projects at various stages of development and construction. All of these projects Windrise, Windcharger, Skookumchuck and Semcams have long term contracts with strong counterparties and would fit well with R&W's existing asset base. We continue to assess these assets for dropdown. And finally, at our Investor Day in September, we provided insight on a deconsolidated view of TransAlta for FFO and for debt to EBITDA. In this quarter's financial report, we provided additional disclosure on how these metrics are calculated. We will continue reporting these numbers in our financial disclosures going forward. With that, I will now pass the call back to Dawn to provide a brief summary before questions. Great. Thanks, Todd. So I've got a short summary a short wrap up here. In summary, I'd like to conclude with my perspective on our execution plan and the advances we've made on our repowering. The acceleration of the combined cycle unit at Sundance Unit 5 is a great example of how having a focused and clear strategy allows us to take actions that enhance our plan and shareholder value by capitalizing on market opportunities as they present themselves. The proceeds from the Brookfield investments on earlier this year provided funding flexibility, which was demonstrated by our opportunistic purchase of the equipment from Kineticore. We also see enormous value in having a long term hedge with a credit worthy counterparty as an excellent addition to our portfolio. This enhances the financial flexibility of the company and we do believe that investors and creditors value a portfolio that has a portion of the cash flows locked in as these projects come on stream and into the market. The Sundance V repowering is now larger than previously assumed and so it does bring forward future cash flows. Keypills 1 is now more likely a candidate for a simple conversion in 2022 and it will still be permitted for a combined cycle unit in the mid-twenty 20. We showed you at Investor Day the simple boiler conversions have very short paybacks and that will be even shorter if the carbon levy escalates with the current expectations under the federal policy schedule. We look forward to providing further feedback in late January in terms of our annual outlook and guidance. Overall, I'd like to give many, many thanks to the TransAlta team and our employees. They worked extremely hard through the quarter. You see the results and you see all the milestones we achieved, and they are just moving everything ahead for this company. So thank you. And with that, I'm going to turn it back over to Kiara. Thank you, Don. Chantal, would you please open the call for questions from the analysts and media? Your first question comes from Rob Hope with Scotiabank. Your line is open. First question is on Canadian coal. Just want to dive a little bit further into the fuel and purchase power savings that you're getting there. Is there a way to quantify the benefit that you saw from Pioneer in Q3? And then as we look into Q4 into 2020, is it fair to assume that absent moves in gas pricing that we could see on a per megawatt hour basis similar fuel and purchase power cost moving forward? Yes. It's Todd here. I don't have a specific number for you. But the trend that you saw over the summer, I would say we're going to increase the volume significantly in 2020 over the amount of co firing as that contract steps up to the full capacity of about 130 MMBtus per day. So we'll see more co firing. We did see very attractive prices on gas over the course of the summer, which did help during that period. Over the course of the winter, we've actually procured a fair amount of our gas needs over the course of the winter. But as you know pricing on gas shifts quite a bit between summer and winter profiles. So I think you'll continue to see definite savings from both the fuel cost as well as the avoided emissions cost as we go into 2020. Yes. And the only it's Brett. I mean just simply on a carbon basis, if you take a typical coal unit at $30 I think it's about $18 a megawatt hour. And then when you're burning gas, I think you're closer to $6 So a difference of about $12 per megawatt hour on the gas portion. So if you think about burning kind of 139 TJs a day in around that zone just co firing that is the carbon saving multiplied convert that into a megawatt hour and you can get the savings. So Rob does that help? Yes, that's great. Thank you. Okay. And then more broadly speaking, we've seen you move forward with SemCAMS on a cogen. We've seen Suncor do one as well as Pembina do a small cogen as well and speak about further cogens. How are you thinking about increasing behind the fence generation and how it would affect forward pricing and kind of the overall supply demand mix in Alberta? Well, I mean, we've seen if you go back and you look at load growth in Alberta and you look at how it's been supplied, I mean, it's a lot of load growth from 2000 until 2019 was supplied by a combination of investments that we made and the cogeneration. So as we look ahead, our models do incorporate a lot of cogeneration going forward as we set our forward prices and think about our investments. Just remember that 99.9% of what TransAlta is doing is replacing existing supply and we've actually taken supply out of the market. So because we've shut down Sundance Units 12. So, we don't so as we look at our estimates of pricing, we incorporate in cogeneration. I mean, you can sometimes it's half and half, sometimes it's 2 thirds, 1 third in terms of how new growth is supplied. But you really have to look at where the developments are in the province. You have to look at who can add cogeneration. You have to assess that against the ISO's plan for growth and our plan for growth. But net net, Alberta has been supplied significantly by Cogen and it's a great way to supply the market here. All right. Thank you. I'll hop back in the queue. Great. Thanks Rob. Your next question comes from Robert Kwan with RBC Capital Markets. Your line is open. Great. Thank you. Maybe I'll just continue on the cogen side. I'm just wondering in your detailed modeling and expectations, how much cogen do you think is that will be developed is going to be meeting new demands associated with as we've seen with new industrial facilities versus cogen that we're seeing being built to meet existing demand effectively taking them off the grid? Yes, Robert, we see that as proprietary information. So we don't share that kind of detail with the market. I mean if you can I think EDC potentially has some ideas there that you can look at that's public, but maybe Yes? And the Robert, the ISO just published their long range plan. And I think it's a good source because I think they try to predict what the mix will look like. But you'll see they've got pretty good growth still projected and more combined cycle coming in to serve that growth. Yes. Just broadly, if you want to think about the decision making though, when I think about the last 20 years, I mean, been here the whole time, what I've noticed about the cogen is, an incremental capital decision by an oil and gas company. So you have to be a company that has significant cash flows that you have nothing to do with to want to allocate capital over there. We do find that people will start with pretty large ambitious projects. And then over time they narrow down as they get closer in. They start with I'm going to do it all myself over time they tend to go look for a partner in cogeneration. So when I'm doing the analysis or when we're doing the analysis with the team, we do a risk assessment of every project based on the actual underlying cash flow of the company. And I mean all else being equal, most oil and gas companies would be putting their capital towards what they do best and the returns that they get out of their business and it's a secondary impact. But that's been the trend in the last 20 years. It could change in the future, but that's how we look at it. Got it. If I can just finish on the ISOs market power mitigation proceedings and just your thoughts after looking at others' submissions, it seems like many were supportive of the current framework like you were, but there were also I'm wondering if you can comment also specifically on couple of submissions, talking about dealing with single participants on a one off or case by case basis. Yes. How interesting. You can co figure. I'll try not to say what I want to say on this. But I think at the end of the day, when I look again, when I look back over the last 20 years, there have been situations where the buyers in the marketplace had significant market power and the Alberta market adjusted to that using their FEOC regulation and using the OBEG and a number of different ways to ensure that we had an efficient market through the whole for the last 20 years. So my belief is that if you actually look at kind of a light touch here, we've already got in place all of what's necessary to ensure that participants don't engage in market power behaviors. We also have an obligation under FIOC to make sure that we have a positive obligation to make sure that we are not doing anything that would express market power. So that's an important thing for TransAlta and we've got the value set in this company to adhere to that, as you know. So I think, I don't know what to expect. You never know what regulators are going to do. But I do know this that if people participate in market power behaviors here in the market they will be investigated by the MSA, number 1. And number 2, they will keep prices in a range that will bring on more supply. So I don't know why they would do that. And I think we've had 20 years of experience creating a competitive market with a robust spot market price. And so I have a lot of confidence that the market works today. Your next question comes from Mark Jarvi with CIBC Capital Markets. Your line is open. Yes. Hi, everyone. Maybe I just want to talk a little bit on the shift in the Sundance repowering. Two questions, I guess, is one is the CapEx per megawatt goes up. What are some of the offsets to preserve the returns you guys talked about at the Investor Day? And then any incremental views on what to do with Sundance 34? So I'm going to turn over to Brad. Yes. I mean to as Don mentioned, this really helps us to some extent advance the opportunity. So we see that as return enhancing. But at the same time, remember by getting a long term contract here, provides a lower risk investment too for us and we think that's very positive. And so when you blend all that together, we see the returns still very attractive from a risk adjusted basis. In terms of the other units, yes, we're still no change from what we communicated at Investor Day. We'll still evaluate those coming to the New Year next year. And it's fundamentally really on the outlook for the market fundamentals. But also as Don says, just the payback on some of these as we said at Investor Day is pretty high on simple conversions. So we'll take next year to evaluate that and keep you posted. Yes, I'd say, Mark, a couple of things from my perspective. So having been in business for a long time, I tend to be a proponent of those workhorse type machines that the F class are. They're excellent to operate. They are stable and they have a when you look at the overall life of contract and you look at the maintenance cost along with those kinds of machines, they're typically lower than some of the newer machines that may have a slightly higher heat rate, but are much more expensive to maintain. So that's one thing. Number 2, remember we have a portfolio. So we can actually do something like this and then do a different kind of configuration at a different plant. And when you blend everything together, and you run the math, we get some benefits out of the diversification. We do get significant benefits out of having 2 machines on 1 steam turbine. So that allows us some dispatch capability as well. I think the final thing is, if you look at the federal rules on carbon tax, for the province here to stay, in compliance with the federal program. And of course, we just had an election here and we know what the federal program is going to look like. The federal program goes from $30 to $40 to $50 by 2022. So getting on gas sooner and saving greenhouse gas reductions makes a huge difference. Overall, these machines are here, they're built, they're ready to go. That significantly reduces construction risk and execution risk. So we factored all of that into our decision making. Okay. And then is there any other sort of additional benefits of doing that transaction by those turbines by essentially potentially getting those out of the hands of someone else who might have built more capacity in the market? Was that at all in the sort of motivation for that deal? Well, no, not really. I mean, at the end of the day, we would only we could only put a price in for those assets that would work in our portfolio. So at the end of the day, I don't know what they were planning on doing. I didn't really care. I just know that Brett and his team had a bit of a sense that this was a way to accelerate our program and the Connecticut guys, I think, saw that as the best opportunity. Okay. And then we've seen some commentary and some deals around either merchant or corporate PPAs for wind or solar in Alberta. I know in the past you guys have indicated you didn't think merchant wind was great for just how you guys think about financing your business and funding growth. But what about the prospects of finding commercial industrial offtakes for renewables in Alberta? Is that something you guys see as increasingly something you could work towards? Yes. Listen, we've had a team that's been talking to people quite a bit on that. We already have quite a bit of merchant wind. We don't need to add to our merchant wind portfolio. And as you saw from the tier, we now have some additional revenues coming in because of the carbon offsets that they provide. And we've got some of the best wind that there is really and we'll have wind rise coming on and all the rest of it. So my view is the team talks to every industrial customer here. If there's opportunities to build for people, we would do it. We would encourage them not to build new and to use some of the existing because it does have a it's good wind and it was built at a good time. It's got a good cost structure. But net net, we'll see what I know is if you build more wind in Alberta, you're going to need our coal to gas because the wind blows here all pretty well at the same time and we need to back it up. Okay. And my last question is maybe around TransAlta renewables and dropdowns. You talked Skookumchuck and Windrise. Is there an optimal timing around you guys would think about a transaction or any sort of other factors that go into how you think about sequencing dropdowns to TransAlta Renewables? Well, if we told you that, we'd have to kill you. So there's always an optimal timing and you'll hear about it when everybody else does. Okay, thanks. Okay, thanks. Your next question comes from Jeremy Rosenfeld with Industrial Alliance. Your line is open. I'll try not to ask any questions, it will get me killed. Just thoughts on the supply cushion. Brett, you referenced ISO Publishing, the update. And the supply cushion looks like in winter, it gets to be pretty tight, both this year and probably next year as well. So any thoughts on positioning the portfolio looking forward for potential upside in trading revenue and that type of thing? Yes. I mean, as always, winter would be, just given the load increases that go on. So, yes, we just I mean, there's no I don't think any change to what we have been doing. We'll position the fleet accordingly. We're really looking more long term on the investments. So Todd, I don't know if you Yes. Maybe a way to think about it, Jeremy, is Todd talked about I think our hedge portfolio was at 85%. Pretty highly hedged with balance. Yes. Pretty highly hedged with it. But you'll see that it's not 100% hedged. That's right. And the reason as you know is in Alberta being short of supply when a whole bunch of coal plants decide to take a rest on a cold day is a disaster. So we tend to carry production into the year in order to be able to withstand that. The second thing is because we now have our Sundance units are merchant, right, so they pretty well sit there and wait for those days. And we have the ability to capture some of that when it does occur, if it does occur. Now you also have to remember it is Alberta. So we had the I think the wettest summer probably ever, coldest summer we've ever seen. Everybody is expecting a really cold winter. And you never know in Alberta we could have the hottest winter ever. So anybody who thinks I can tell you I've looked at 1,000 of years of wet weather data, at least 1,000. I've looked for correlations all over the place and it's a random walk. So, the supply cushion could be short under cold weather conditions and it could be fine if the weather tends to be mild. And nobody knows what the weather will be. Okay. I'm hoping for wetter for skiing, but anyway. If we look at the same thing looking farther out. So if you think about the merchant portfolio in Alberta from a long term perspective, maybe 2025 and outward after you're through all your boiler conversions, after you're through repowering, is there a hard number or something somewhere where you want to get the portfolio in Alberta to from a long term basis, so that you have some kind of hedge position or long term contracted position on a sustainable basis going forward? Yes. Yes, you're thinking about the what we've got you're thinking about the Shell contract, would we want more of those in our portfolio? Is that how you're Yes. Is that what you're trying to evaluate? Yes. Yes. That's so as you know, we're pretty conservative here and the management tends to like long term contracted assets even if they have slightly lower returns than merchant because that's our DNA, right? So I would say that we've still got a lot more work to do. I wouldn't really want to give you any sort of I don't want to say something here that we'll go away and do some analysis on and then regret. But I would say having some portion of our fleet contract is going to be a it's always going to be good. Especially, I really like to have a portion of something hedged when it's coming online because typically when plants come online it depresses the price a bit. So you kind of want to have some of that in there. I think the other thing that we have to do Jeremy is there will be a lot of analysis on what Alberta looks like when there is more of when our fleet is more on gas. Gas runs at higher availability and tends to it doesn't tend to have some of the same issues as Frankenthal coal does. So we'll have much more operational flexibility when we get out there. I think if we mix the operational flexibility with our desire to have some consistent cash flows in our portfolio, so that we have so that Todd will be happy when he goes to finance bonds and we'll have lower rates on that. We'll be doing all that mix and more to come on that. It will take a bit of time to think that all through. But in general, if we could get other long term contracts with large industrials that are creditworthy, you would see us trying to engage in those. Okay. That's great. I appreciate that. That's it for me. Thanks. Your next question comes from Patrick Kenny with National Bank. Your line is open. Good morning. Yes, just back on the SUN five PPA, I know you can't provide too much detail, but I was just curious in general how you think about IRR for high quality PPAs in Alberta relative to building merchant. If you are going to be looking at potentially additional corporate offtake agreements, what would you say is the fair spread and hurdle rates between merchant and contracted? Yes. I mean, it's a little tough to answer that, because we do look at it truly from a portfolio and we'll always have a merchant component. For example, our hydro is a merchant to be able to capture those kind of peaks. But and you got to remember the contract is not unit contingent per se even though you reference it signed to a specific unit. But yes, I mean I would say generally you're going to look at probably 300 basis 3% higher for merchant. But again, it's a bit dependent on the technology, the age, where it's situated, what markets you're in. So that's just a broad rule of thumb? Yes. I would say take that 300 basis points as a bit of a midpoint and think about it this way. The longer the contract, the fewer the base you might have you might take even a bigger reduction. The more pass through of cost, the more it's tied to actual heat rate of the machine. So there's a number of considerations there. But generally, you pick up stability in your cash flows, that are financing costs, a whole bunch of things that you can plan around that kind of offset those reductions in returns. Okay. Thanks. That's helpful. And then you mentioned the lower gas prices this summer having a positive impact on coal firing margins. But I guess at the same time, it's reduced drilling activity in the central part of the province. So perhaps you could just provide a bit of an update on how you're thinking about ramping up volumes through Pioneer over the course of 2020, 2021 as well as just securing long term supply to the other pipelines coming into Sundance and Keephills? Yes. So we're again, no real change from what we communicated at Investor Day. We're targeting to get up to that $350,000,000 $400,000 a day eventually once we're fully converted. We're well positioned here over the next year or so given the Tidewater pipeline plus we indicated we have incremental firm capacity in the existing line there. And so, yes, it's just a matter of working with parties. The drilling activity always ebbs and flows and we never saw the low, low prices being sustainable for the producers and that's not in our planning. So we do expect those to improve and drilling to be sufficient. And yes, so we'll as I said at Investor Day, we'll keep you updated as we Yes. And I think Patrick, we're talking to of gas guys as you can imagine. Really our volumes even though it seems like a lot of gas to us are in that rounding era of what Alberta produces in terms of gas. So that's helpful. What we do know is that this curtailment whatever they did with TransCanada this summer that alleviated some of the curtailment issues so that the guys could get their gas into storage has helped to increase prices and get them closer to what you're seeing today. Those kinds of prices were what we had in our models. Because remember that we're using gas and the offset is what we got to pay on carbon. And so net net, what we know from we've got gas we've had gas guys on our board and we've got John Gilbert on our board. But as you get into this current pricing regime that we're seeing, the guys get out their drills again. So, because they become more profitable. So, we're starting to see evidence of that. Okay, that's great. Thanks. And then just lastly on the NCIB, stock is up nicely here this morning, but still a little bit lower than where you've been in the market buying this year. So just wanted to confirm that given the extra free cash flow here in 2019 that the NCIB is still attractive in your view from a capital allocation standpoint? No, you're absolutely right. It is an attractive price. And as I mentioned earlier in the call, we plan to be back in the market here in Q4 as soon we're out of blackout. Okay, great. Thanks guys. Thank Your next question comes from John Mould with TD Securities. Your line is open. Good morning. Maybe starting with the SemCAMS cogen project, it's shown as a potential drop down to R and W in your deck. It's fully contracted on steam and I think half contracted on electricity. So does TransAltaCore potentially take on that merchant risk in a drop down scenario? Or are you comfortable with the cogen going to RNW with some level of merchant exposure? Yes, John. We've as you can imagine, we've had some kind of early discussions with the Board of TransAlta Renewables. So they understand the project and that there is a bit of a merchant component to it. And in general, we prefer fully contracted assets at the TransAlta Renewables level, but I wouldn't rule out the notion that having a modest bit in the context of the whole portfolio of Merchant Power being available to being accepted by TransAlta Renewables, given TransAlta Corporation's ability to manage and dispatch that into the market is likely okay. Okay. And then just on the Shell PPA, I appreciate you don't want to detail individual contracts. But just more broadly speaking, what's the minimum contract length you need to characterize an agreement as long term? It should be. So I would say a medium term contract is 5 years and anything longer than that is long term. Okay. Helpful. And then just lastly on the U. S. Coal results in the quarter, I know in your remarks you pointed to strong unit availability. Can you just give a little more color on what drove that big gross margin increase in the quarter? Sorry, I missed can you just repeat your question? The U. S. Results in the quarter were much better than the quarter. Yes, yes, U. S. Results. So in last year, we had a lot more unplanned outages. And so even though prices were high last year, the plant wasn't available to take advantage of high prices. This year, we saw strong pricing in around the $30 level and the plant had great availability in the quarter and really was able to capture those prices. Yes. I would say if you look at Centraleon, you look at our trading business, our trading business, we have a lot of real time traders and they arbitrage and move power from the North to California. And this year has this volatility that's occurred because of all the renewables in the California market that have to be backed up has benefited both Centralia and Centralia and the trading business because they chipping away every day and moving power all over the place. So that's been very helpful. I think as you look ahead, we know that Unit 1 comes off at the end 2020 plus you've got a bunch of coal plants coming off in that region that all have been supplying baseload power that has been sort of a nice complement to the hydro in the Pacific Northwest. I just think that there is a lot more volatility coming forward as we look at those markets. So we're starting to see for the first time some actual uplift as a result of that. Yes. But John, to Todd's point, the specific answer was the amount of purchase power we had in Q3 of 2018 was significantly higher than it was in 2019. So we were able to supply a lot more. So we made it as opposed to having to buy it in the marketplace. That's probably the biggest driver between the results quarter over quarter effectively on the comparative quarter base. Okay. Thanks for all that color. Those are all my questions. Thanks very much. Thanks, John. Your next question comes from Chris Farfoe with Calgary Herald. Your line is open. Hi. My apologies if this question has already been asked. But I'm curious, Dawn, if you could tell me what are your thoughts on the government's new tier program and more specifically how it's going to affect the company going forward? Yes. I mean, I thought the TIER program was well first of all, it was expected and I think it's a good program kind of overall because what it does is it enables companies like ours to make decisions like the ones that we've been making. There's a price on carbon, but there's also a performance standard. That performance standard is incredibly important for us in terms of our the already existing renewables investments and also important in terms of making our coal to gas transition. So it's a good program. I'm really hoping that it stays stable as we go forward in terms of the performance standard. And I think the world is moving towards carbon being priced and we're ahead of the game here and we need to get credit for that. Can I ask you what do you expect the financial implications of it will be in 2020 versus 2018 or 2019? In other words, will you be paying more or less or the same under the program? And just to follow-up on a completely different issue, can I ask you what your outlook is on the electricity pricing in Alberta in 2020? Yes. So the it is the same because it was expected to be $30 and a 0.37 performance standard. So there's no Which is the same standard in price that's currently in the market today. Yes, same standard in price. So the market expected that. And then the current forward price for electricity in 2020 is around In the $55 to $60. $55 $60 which has been, Chris, if you look back over the last 20 years, on average, Alberta trades in that sort of $60 $55 to $60 range. So it's a great price for consumers. There are no further questions at this time. I'll now turn the call back over to Kiara Valentin.