Good morning. My name is Christine, and I’ll be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation Second Quarter 2018 Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer session. [Operator Instructions] Thank you. Sally Taylor, Manager, Investor Relations, you may begin your conference.

Thank you, Christine. Good morning everyone, and welcome to TransAlta's second quarter 2018 conference call. With me today are Dawn Farrell, President and Chief Executive Officer; Brett Gellner, Chief Financial Officer; and Todd Stack, Corporate Controller. Today's call is webcast, and I invite those listening on the phone lines to view the supporting slides, which are 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 information provided during this conference call is subject to the forward-looking statement qualification, which is set out on Slide 2, detailed in our MD&A and incorporated in full for the purposes of today's call. All amounts referenced during the call are in Canadian currency, unless otherwise stated. The non-IFRS terminology used, including gross margin, comparable EBITDA, funds from operation, and free cash flow are reconciled in the MD&A for your reference. On today's call, Dawn and Bret will review the quarterly results and the outlook for the remainder of the year. After these prepared remarks, we will open the call up for questions. With that, let me turn the call over to Dawn.

Thanks, Sally. Welcome everybody, and hello to everyone who’s joined our call today. Let me start today by saying that I’m very pleased with our quarter and the performance of the business so far as we’re moving through 2018. This quarter, we delivered cash flows from the business well above last year. And the improving financial results over last year are primarily due to our performance from our hydro and Canadian Gas segments and Brett is going to take you through some of that detail when he gets to his section. Now, as many of you know, this is first quarter that Sundance units moved from contracted baseload assets with long-term PPAs to flexible merchant assets. I’m glad to report today that the team is doing a great job of dispatching our assets into the market here in Alberta when they are both needed and when they are profitable. I’m also happy to report today that we are well ahead of our plan on replacing recourse debt and reducing our debt overall. During the first six months of the year, net debt was reduced again by $345 million and subsequent to the quarter, our finance team completed our off-coal financing, which they did an excellent job of, and we used that money to repay our 2019 bond early. Brett will get into the details, and he’s pulled together some excellent charts that will show the results that we’ve achieved to date. What’s important here is that our balance sheet is now very well positioned for anything that we want to do in the future. We did make the decision in July to permanently retire the Sundance Unit 2. Our analysis was informed by the work we did on the capacity market, which also clarified that the rest of our units…

Okay. Thanks Dawn and good morning everyone. So, I’m going to start with our segmented cash flows, and we think these are important metrics because they show the cash flows from each of the businesses before pre-tax, before tax and interest. So, good barometer of how well we're doing in the business. So, you will see from this chart, our segmented cash flows totaled $203 million during the second quarter. This is an increase of $50 million year-over-year. All our generation segments except Canadian Coal contributed cash flows equal to or better than last year. This was driven primarily by two key factors. First, as John mentioned, our hydro fleet benefited from higher prices for ancillary services, which are required by the ISO to maintain good stability and reliability. Our merchant coal assets also benefited from higher prices, although this was more than offset by the higher carbon costs, higher per unit coal costs, and the one-time costs associated with mothballing some of the units. We expect some of these costs to improve over the balance of the year as we align our cost structure to having fewer units operating. The second biggest driver is lower sustaining capital, which again is expected, given we have mothballed some of the units. On a year-to-date basis, segmented cash flows were significantly higher than 2017, a key contributor to this increase was $157 million one-time payment that we received for the termination of the Sundance B and C PPAs. This payment really is effectively a prepayment for the capacity payments that we would have received over the 2018, 2020 period had the PPAs not been terminated. So, now total free cash flow as you can see from this next chart has been significantly higher compared to the last two years on both a…

Thanks, Brett. So, as we step back from the quarter and we look at the bigger picture, you can see from our results today that we successfully stabilized and adapted our business to the new realities. Currently, we are both transforming and growing the business off a very strong base and value is being realized in the form of stable and growing cash flows. The Slide on Page 11 outlines the many initiatives we’ve undertaken, which have resolved much of the uncertainty and led to further clarity on where we're going with this company. Investors today are beginning to recognize the value of the hydro assets here in Alberta and how the hydro and coal fleets work together today. What I'm the most certain about today is that the cash flows from the hydro and coal and the coal to gas, which is yet to come which we are investing in, the cash flow from those businesses here in Alberta are here to stay and they are growing. So, when you add together the $150 million dividend that TransAlta shareholders receives from TransAlta Renewables, with the dollars that are coming from the rest of the company, including the assets here in the Alberta market, the cash is growing significantly to 2021 and the balance sheet is the strongest that’s ever been. So, with that period of stabilization well behind us, we’re also in the home stretch of our transformation. Last month, we moved on to even stronger ground with respect to the capacity market. The latest rules released in July indicate that we will be well-positioned to compete successfully for power contracts with our assets. This is an area where questions marks have simply fallen away. I’m also pleased with the progress the team is making on TransAlta Renewable. They are persistent in finding good investments with great returns will eventually grow the cash flows that we received from that entity. Investors supported that growth through the equity issue that was also done in Q2. All positive for TransAlta shareholders, as well as TransAlta renewable shareholders. So, thanks to everyone who worked hard over the quarter. We’re keeping this call a little bit shorter, so that I'm going to turn it over to Sally, so we can get right into Q&A. Thank you.

Thank you, Dawn. Christine, could you please open up the call for questions from the analyst and media?

Thank you. [Operator Instructions] Your first question comes from the line of Rob Hope from Scotia Capital. Your line is open.

Good morning everyone. Just wanted to start off with the hydro assets. Can you walk us through the delta in the results from Q2 versus Q1, how much was ancillary? And then also can you add some color on, I believe, it's your June presentation, you said that these assets could generate $75 million to $100 million of EBITDA in 2018, but you've already done $66 million and then, also does this give you additional confidence that you can reach that $225 million to $275 million EBITDA run rate post PPAs?

Okay, Rob, it’s Brett here. Yes, so on quarter-over-quarter, most – just the way PPA works is, most of our margin is on the ancillary services side of the business. The ancillary side is – the prices for that are very much correlated with what you see for energy in the market. So, when you see stronger energy prices you usually see stronger ancillary service prices as well. So, Hydro is well positioned and a big participant in the ancillary services market. In terms of the balance of the year, again I think that’ll depend to some extent on how prices will lean here to the back end, but yes, we’re tracking well so far. Remember there is some seasonality in these assets because of water levels and so that comes into play. And then in terms of your long-term question as you recall from our Investor Day, we laid out the road to the higher EBITDA from these assets and really it has to do with the way the financial contract is structured in that. We have obligations to pay on both the energy and the ancillary and in return we got a capacity payment for that come in new markets, we will still get a capacity payment because of the new capacity market and then we will have the energy and ancillary to our account. So, it’s really governed by the nature of that financial contract. So, I don't know if that answers your question?

Yes, it did. That was helpful. Thank you. And then, may be moving something a little bit more broad, and Dawn touched on it in her opening remarks. If we look at RNW, it was developed as a way to highlight the value of the renewable assets, but the relationship between the two, one could argue that the value of the wholly-owned assets at TA are not being recognized, specifically, the hydro and some of the coal units there. So, just wanted to get a sense of what you could do to better highlight the value of those assets or realize the value of those wholly-owned assets there?

Yes, I mean, I think this is a great year to start to really prove that up. So, if you look at, you know in this year we’ve had the Sundance units go from contracted to merchant. We have a more normal market happening here, so we're seeing more normal cash flows. On the hydro, I think frankly, as we go through the year people will start to realize that throughout this whole period from 2015 and 2016 and 2017 as we’ve been adapting the business to sort of the business realities, we’ve actually never really missed a beat when it comes to cash flow performance and we’ve been growing the cash flow here. So, I think our first job is to show investors that when you look at the fleets here in Alberta, the combination of the hydro and the coal together today and the hydro and coal gas tomorrow produces substantial cash flow. And so, when you add that 150 that we get from renewables, which will eventually grow over time as we add assets there to the actual cash flow that we’re printing here in the Alberta market because we are needed for reliability in this market. We can extract value from the market as we dispatch our assets into the market. I think when you add those two together you see that there is significantly more cash than I think people expected. So, I think this year makes a big difference in terms of proving that up one more time. We’ve proved it up for the last three years, you got to prove it up one more time, but – so I think that’s the first step. Beyond that, I mean there’s always lots of financial structuring type ideas that come our way to prove our value, I think fundamentally showing our investors that cash flows are there, and they are solid and they are there for the long-term. This business has a long-term nature do it. I think it’s probably the most important step we can take. And Brett will add.

And Rob, if you – to your question specifically, around is the value being recognized on the TA Corp? I mean by looking as you know, if you assign, you look at the value of RNW and you back that out of what is in the current share price for TransAlta there’s no question the market from our perspective is assigning a very low TEV to EBITDA multiple, two very good assets to Dawn's point. Ones that will have a long life to them, and think about that that includes our hydro, which we would argue is very valuable and perpetual. The coal assets, which will get converted to gas and have longer lives to them, plus the trading and the other assets that are not there. So, we're thinking through how we might be able to show that going forward in future investor presentations and so we showed that a little bit again at Investor Day, but we continue to just portray that going forward.

Alright. Thank you. I appreciate all the color. I’ll hop back in the queue.

Your next question comes from the line of Patrick Kenny from National Bank Financial. Your line is open

Good morning. Just wondering if there was an update on finalizing the take-or-pay agreement with Tidewater? And maybe an update on your thoughts to go in for 50% of the capital cost of the pipeline, you know, especially now that your balance sheet is in much better shape than you would have thought when you first entered into the deal?

Yes. Good question, Patrick. We're still working through the agreements, but from our perspective more or less full steam ahead here and things are progressing as we have communicated. From an investment perspective, again as you recall, we’ve made investments in natural gas pipelines before. We own partial interest in the one in Australia. So, to us this is very much an extension of providing fuel to our assets. So, we have not made that decision yet, but certainly it is one we’re still evaluating and to your point we’re well-positioned to fund that.

Yes, and I think you want to also remember Patrick that we spend capital each year in the mine to get the coal out. So, that capital is coming down if we invest in the Tidewater pipeline, net-net it is not that much different in terms of capital requirements. So, it makes a strong case for us making that investment.

Okay, great. And I might have missed it, but was there any update on securing a second source of gas supply for the coal plants?

Yes. No updates. As you are going to appreciate our value and all our options there, I mean our first objective here is to get the Tidewater up and running. We do have our pipe in there today. It’s smaller in size and that’s what’s allowing us to coal fire. It's got limitations in terms of how much gas we can get in there, and so we do need to get Tidewater in, but we will be looking at our broad gas supply trends. We are evaluating our gas supply in transport strategies, and as we have something to announce we’ll let you know but it’s part of our overall converging planning.

Okay great. And then lastly, just wondering if you could provide a bit more color on these data center opportunities out there, just to cross the portfolio. I mean should we view the BitCity deal at Sarnia as somewhat of a template for future deals, kind of the five-year fixed price in deal? And then also maybe you can touch on what the hurdles or challenges might be in attracting some of these data customers to your Alberta merchant fleet?

Yes. So, I think, Patrick it’s fairly early days for doing deals with these data centers. You know, I talk to executives in our industry all across North America and everybody is being approached by these data centers and what they tend to be looking for is any place where they can find surplus power in that $30 to $50 range that kind of is their sweet spot. Now, we were - BitCity I think was, you know we haven't really told about the contract prices, but BitCity I think was attracted by the location and there were other factors that allowed them to be in a higher costlier section because Ontario’s definitely that. So, I think, the five-year outlook is appropriate because I really think that’s the length of their businesses and they have to do a lot of capital reinvestment over time, so things change. So, I think that makes sense for them. I think in Alberta to the extent, in order to attract them to that kind of market we’d have to figure out a way to serve them directly behind the fence. So, we've got people that are looking at that. Certainly, when we talk to that head of BitCity and other people like them, if you can provide them with that surplus power quickly and on a shorter-term contract, I mean they are located in your service area. So, we’ve got a team working on it. I think its early days. I think there’s tons of opportunities because there’s lots of data, it’s going to be necessary, especially as people get into these driverless cars. So, but all I would say is, it’s pretty early days there.

Alright, that’s great. Thank you very much.

Your next question comes from the line of Mark Jarvi from CIBC Capital Markets. Your line is open.

Hi good morning. I wanted to just start with the Canadian Coal segment. Year-over-year, we saw reduction in the O&M costs, obviously, with the shutdown of units. Wondering whether or not – I think there is for the room for improvement on the O&M level but also maybe even just fuel cost in terms of where gross margin could be in the coming quarters?

Yes, I think there is kind of two things there. One is, as we – and as you can imagine, I mean first of all on the fuel cost going from a 12 million ton mine down to a much lower level of tonnage. So, in all of these kinds of operations there’s lots of fixed cost that have to be attacked. And Wayne and his team are doing that. So, they are looking for ways to reduce the fixed cost overall to be able to get that per unit cost down, on the fuel side, and we do anticipate that there is more room there as they move through the year. The same is true on the OM&A cost. Remember, Sundance was a 6-pack plant with lots of common costs across all the units that created the economies of scale in the first place of having a 6-pack plan. So, as you move to 2 units and then potentially come back up to 4 as the market conditions improve, those fixed costs per unit move up and down. So, again, the team is looking there. So, as we look ahead at our projections, and as we gave you our guidance on our free cash flow we do see more improvement, particularly on the OM&A per unit going forward. So, I think you’ll start to see that coming through our numbers as we go into Q3 and Q4 of this year.

Okay. And then just following up on the comment about – in your comments about being the upper end of range of free cash flow guidance. Obviously, the hydro results [indiscernible] what are the other sort of factors that you feel more confident today about hitting the upper end of the range?

Yes. I mean the number one thing is, if the pricing in the market continues as it is then it continues to be volatile. You know that’s where the opportunity comes to be at that higher end of the range. So, it’s - we don't see any reason for the market to substantially change. And then of course the other one is, as we deliver on our performance on our cost reductions, both of those together are really the key factors for that.

Okay. And then, just wanted to go back to the capacity market design prepared remarks, also just you made a comment about Sundance unit from the retirement of – shutdown of unit 2, so just maybe what you're thinking about current design, the balance of the units at Sundance and whether or not it makes sense to convert and move forward with all four units or sort of some rationalization more of those units?

Yes. So, we’re done with the rationalization. So, the – remember, you probably don't remember, but I unfortunately do. Sundance units 1 and 2 were the first you to units that were built in their early 70s and in preparation for a very big boom in the power market at that time because of the high oil prices. They are the smallest units. They were quickly put together. The design has improved massively from the first few units to 3, 4, 5, 6 and then of course [K 1 and 2]. So, given that they were smaller units, had 350,000 operating hours on them, they would have taken the most capital to run into the future and they would have had the shortest life because of the federal carbon tax rules. So, when we were looking at how the capacity market was shaping up, we could have – there was a return available to us by converting those units, but we just found that it was minimal and it didn’t meet our hurdles for those kinds of units. So, we decided to permanently shut them down, which allows us frankly to stop spending money on the mothballing because mothballing does cost money. It costs money to keep those units ready and able to start back up. So, when we looked at the capacity market evolution from January into June, we saw significant reshaping of that market as the ISO did what I think was an exceptional job of really listening to the input from stakeholders, and what you really see there is to make it simple as you know capacity and energy together needs to be about a $60 prize for there to be a return on the capacity. When you look at the way the market shaped up. it now has pushed enough revenue into the capacity side to make – call the gas units are quite competitive in the marketplace. And so, what that does is, it enables us now to start deciding, which units we would invest in first. So, the team is looking across all the Sundance units and the Keephills units. We'll make decisions probably here in October about what are the first units to go. I think it’s also important for you to know that as Tidewater comes on, we actually, the coal firing opportunity and I think Brett talked about coal firing in his comments, but those comments shouldn't be lost on you, there is huge opportunity in, as Tidewater comes in, before we've even converted to use gas in the mix and get our costs down, because effectively it reduces the carbon tax bill. So, net-net all of that is to say that the capacity market has shaped up to have the right price signals for investing in capacity it’s got the right price signals we think now for all of those units to clear and we don't have any plans to consolidate any further.

Okay. That's good color. And maybe I’ll just – the last question around the carbon tax offset the federal level, we're hearing [indiscernible] about it and revision softening, obviously, differences between provincial policies and the federal. But wondering what you guys are thinking if it impacts at all your plans for conversion timelines on how you guys think about positioning your [indiscernible]?

Yes, I mean, I think – so first of all the announcements earlier this week by the federal government were directed at the tradable sectors. So, it was with any sector that has to compete in the international market for business because of cost. So, they did do some adjustment to the levels. They did not do any adjustment to the non-tradable sector, which power belongs to it turns out. We only fell into the local market. So far, we don't expect any changes on that front. As we do our scenarios, it is a lot of the algorithms had to consider how the plans will dispatch in the energy market and really the cost of energy in the margins for energy and as you know as plants are dispatching up and down, you know there is different heat rates involved. And they have to also consider the price of gas. And what we see is just the price of gas has come down so significantly that when you add together the dispatching requirements with gas, these units are much more flexible on gas and their capital costs are way lower and so costs are lot less to maintain them on gas. So, those are the kinds of considerations. Right now, we wouldn't see any change in our plans on the conversion side. About the only thing that we may, we do have to think about is, if there was a change in the carbon tax, suddenly it wasn’t there. You know, our plans would have to would in the short-run we’d want to start some of the units back up because they would be more competitive than the existing gas plants that are running today. So, there might be a short-term opportunity there, but long-term this fleet is headed for gas.

And Mark, the only other add is, remember, it's the carbon support, and don’t get us wrong, but there is other regulations that drive our decisions like being able to run longer on, if we convert under the federal rules, if we stand coal, we probably have to invest into SOx and NOx where as if we convert, we do not just see maintenance capital required on gas versus coal is quite different. So, when we look at these decisions there is a whole bunch of things that we look at.

Understood. Appreciate those comments. Thank you.

Your next question comes from the line of Ben Pham from BMO. Your line is open.

Thanks. I had a question on the commentary around share buybacks for second half. And it sounds like you're being bit more direct about how you see the pace of share buybacks versus last quarter where I think you might have mentioned, we want to get that to a certain position and then consider share buybacks, maybe I guess more of a subtle change, but also since that time, you've lost a CFO. So, I guess, my question really is, is this pace of share buybacks, is this always in the game plan for Donald and the entire team or is it just kind of a slight shift and how you guys think about things where debt is versus maybe where Donald was thinking about things.

Yes. So, let me start by saying there is absolutely nothing different here today than there was under Donald. So, the plan that Brett and I are presenting here today and where we are going is exactly what we all as a team agreed to, and agreed with our Board, and have agreed with the credit rating agencies and all of the people that matter here. So, there’s no change from that. I think what we said in the first quarter and maybe we weren’t as clear is that we were going to be very prudent in the first quarter because any kind of share buyback that we do has to account for that we're going to reduce that final debt in 2020, and we have to have the cash to be able to do that. So, it was really contingent on whether or not we were more optimistic about our cash flow forecast then less optimistic. So, I think what you can take from what Brett and I have talked about today is that we’re pretty optimistic about the cash flows and we’ve been very clear about the cash flows being at the top end of the range, which does afford us a little bit more flexibility on buying back shares in the back half of this year. So, I think that's all you can take from it as we are optimistic about where the cash is at.

Okay, that's great. And then Rob brought up pretty interesting questions on the hydro and $47 million in the quarter you annualize that, I mean, it's with the seasonality. I mean, if the hydro can generate that much under PPA than it generally bodes well for post 2021. What I'm curious about though is in past years, even during peak pricing, you've never really seen $47 million, may be 1 or 2 quarters. So, can you comment on maybe the ancillary market, is it different now than it was before, is it more function of the megawatts being bigger, regional differences and maybe just a bit more color on any differences on ancillary for hydro?

I don't actually think there is any, I mean I have to go back and do some real research with our team to see if there is any railroad differences in ancillary market, but I have in terms of my reviews, I haven't seen a major shift there. I just think, and we said this all along, and I think we’ve got to just get our messaging through. When you put a carbon tax into the market here, it reduces the amount of megawatt-hours demanded by the coal fleet because it has got a higher cost structure and that it needs a higher price in order to clear the market. But what that also needs is the hydro gets that margin into it. So, I think it’s just a reflection of the – of just how the carbon price is starting to move through the market and it does create more volatility, which hydro loves. I think in terms of taking 47 and multiplying it by 4, remember we get most of our water in the spring and then we have a bit of storage that we can carry into the summer and the fall. And it’s critical from a reliability perspective that we hold that water and have it there when the system needs it. So, the hydro has always been a very valuable resource, but I don't think it’s any change in the ancillary services market at all. I think it’s probably more on how pricing is being affected by compliance cost.

Okay, great. Thanks a lot, Dawn.

[Operator Instructions] Your next question comes from the line of Robert Kwan from RBC Capital Markets. Your line is open.

Maybe, if I can just continue here on something hydro-related and your – any commentary you got on the capacity market framework with respect to mitigation, and it looks like – I am not sure you will agree, but it looks like actually significant proportion of the market, maybe mitigated on capacity, but the energy seems to be a lot more promising. And if hydro is really kind of an energy in ancillary, is that actually kind of an upside for your hydro assets just based on how that framework seems to be falling?

Yes, and again, I think the important thing to look at for TransAlta is the fleet, right? So, we have got the Sundance units, the Keephills unit, we've got part of Sheerness, part of Genesee, and we got the hydro. And when you add all that – and when you put that in the big pot and you mix it altogether and bake the cake, the combination of where we can get capacity we see some assets get a lot capacity revenue, we see other assets get a lot of energy revenue. The hydro actually gets both. It’s a very, very strong asset because a, it’s got a low-cost base as you know, depreciated assets for a long period of time. Not a lot of sustaining capital is required for those assets. So, it’s a great – it can basically be a capacity price taker and make good money in the capacity market. It gets a good new cap in this market. So that’s positive as well. And then of course if it turns out that there is more revenue in the energy market than hydro will pick that up and there might be a little bit less capacity revenue in some of the other assets. But net-net when we look at – when we model the full portfolio, I think the our most important thing is, you have got a really good set of stable and reliable cash flows coming from the Alberta Business.

Got it. If I can also come back to the Sun 2 [ph] retirement decision. You fought pretty hard to get the ability to swap the years with Unit 1 and you talked about kind of the age of the units, but I thought a lot of work and capital went into the plants when the boiler tubes failed. So, I'm just kind of wondering with all of that, how that factored into the decision or do you actually also see the capacity market when you model it out, it's actually balancing that closely on an edge, that taking out one unit out is really going to help you right across the fleet?

No, no, I mean as you know we’ve fought not to have to put those water walls in and we would have been just as happy to shut those units down in 2013, and if it were not for the way the PPA worked and the arbitration worked and if we had been smart enough to come to a deal on that, those units wouldn’t have run pass that timeframe. So, I think we didn’t have to fight that hard to move the years over to the unit, the government just gave us that ability to it. It kept us with an option in the market as we were modelling, we thought that there would be one more unit that would clear into the capacity market and in fact it does clear in the capacity market. It just didn’t meet our investment hurdles. And so, when it comes to – we’ve told the market we're really disciplined about allocating capital. I think we keep demonstrating that and I just wasn't prepared to put money into our marginal asset. So, it really was the decision we made on that asset on a standalone basis.

Got it. So, it was more of a hurdle rate decision?

Absolutely.

Yes. Got it. If I can just finish on Centralia. It looked like in the quarter, there's some reference to major maintenance being done last year and that's why the maintenance capital was down this year. So, was there a turnaround taken in or has it been deferred, I guess, specifically just as we're seeing Mid-C pricing quite strong, are the units running at pretty high rates in the third quarter?

Well we don't talk about the third quarter until we get through the third quarter, but, yes, the units, I mean, first of all, we spent less and more per year based on what the actual work is in the plants, and some of the maintenance as you know is time-based on some of it is condition based. So, when you look at any given year, what is behind it is a very strong technical plan that determines when you have to spend the money. We also of course have to consider for unit one that there’s only a couple more years left on it. So, we estimate the operating now as going forward and think about how to spend based on that. We always spend our money during the time when the units are dispatched off because of the hydro conditions and this year was not different and the units are operating well as we go through the quarter here.

That's great. Thank you.

Your next question comes from the line of David Quezada from Raymond James. Your line is open.

Hi, thanks. Good morning, everyone. I just had a good question on the TransAlta Renewables side, I’m wondering if you have any new kind of new, kind of high level thoughts on the opportunities set for RNW, I know you have been active in the U.S. and Canada via drop down so far this year, and does the new and the now stronger balance sheet at the TA level maybe open up RNW more to do. I guess direct transactions outside of the yield curve relationship?

Yes. So, I would say first of all there is a massively strong balance sheet at TransAlta Renewables level, and of course that is a great currency and we can also, if we really saw some huge growth opportunities it’s got a good currency if we wanted to expand it using equity, but for now what we see is, first of all, as I said earlier to somebody else, the acquisition market is super floppy and the valuations are super high and they’re not the stuff that we like all that much. So, we continue to look at a bunch of acquisitions, but for the most part they never meet our investment hurdles. Where we see real value is in the market for more of a behind the sense cogeneration, and sort of corporate clients that are looking for green in their portfolio. There is a huge demand coming from there. They tend to be – they are not big place, they tend to be single, more like $80 million to $100 million. We’ve got the companies set up to be able to do quite a few of those a year and frankly they got better returns and then the kind of returns that we want for that entity. So, as we look at Renewables today, we’re pretty, we see some really good stuff on the Greenfield side. Now, it takes a little bit longer to get those cash flows coming in, but that also allows us some good flexibility in terms of financing. So, TransAlta Renewables in itself is a strong entity for growing itself and then of course – and I think that makes a big difference to where we go from here.

That's great color. Thank you very much.

Your next question comes from the line of Chris Varcoe from Calgary Herald. Your line is open.

Hi. This is question for Dawn. Just to follow-up on your comments earlier, wondered if you could just give us a little more color about what would happen if the carbon tax was removed either in Alberta or across Canada, would you slow down or alter your plans at all on the conversions of the coal plants, I'm just wondering whether you would change your strategy at all?

Yes. I can't really speculate on all the things that could change, but here is my perspective on how I look at it. So, we’ve done enormous research on what customers want from us as a power company and remember TransAlta doesn't really sell into – we don't sell to the homes. We’re not a retailer, we sell either to the wholesale market or to large industrial and commercial customers, with big, big loads. And our research shows that despite what’s going on in any sort of political environment, you know you’ve got one-sided – one a carbon tax and other side it doesn’t and you’ve got all sort of stuff in between. What the corporate customers, our corporate clients want from ours is low cost, green, and reliable and firm power. And what they’re telling us today is they would like to have their portfolios weighted more heavily to Renewables and over time they would like to get 100% Renewables and they would really like to get us to be investing in storage, particularly battery. So, if they had their preference, they would be picking Renewables with battery. So, when we stand back from it and we look at the demand for power, and we look at the people who buy power and the purchasing department, they want low-cost and green and it turns out that price of green has come down significantly. Though we can actually provide them with that and that’s where we’re focusing. So, our future focus is all about firming up green and we’ll do that with gas. Over time, we will be investing in more batteries and storage to firm it up, and it is really to meet that demand because that’s where we see the demand coming from, which basically says whatever the policy environment is, we think that the way to go is gas and renewable.

So, would you change it all the timing of the conversion? I guess, I’m just really wondering more on the conversion issues, whether that would change your SKU the way you look at the timing of those plans being converted to gas.

Today, when we look at gas prices and the reduced maintenance cost, and the dispatchability of these units and the flexibility they bring to the market, it shows that we wouldn't change the timing, we’re not spending a lot of time running in new scenarios because at the end of the day, what we’ve proven is, whenever the policy changes we can adapt very quickly to that, and our fleet is valuable across all scenarios. So, today, we wouldn't and we will wait and see and if things change we might make some changes in the future, but generally when you look at our fleet overall, long-term we want to be clean by 2025.

Okay. And lastly, just little off topic here, but could you give us your outlook and how you see the Alberta electricity market and the prices in the second half of this year and into 2019?

I mean, I think, the market is stronger than people thought it would be. We certainly, if you looked at the chart that Brett put up there, it’s a great start because it shows you that demand has grown even through a recession and it has continued to grow, which helps with the stronger pricing. And so, I mean, my call would be the pricing. I think if you look in the forward market Brett’s got those numbers, it’s as solid as it was in the second quarter here, but maybe Brett you can give a sense of that pricing.

Yes, I mean the forward outlook right now is for Q3 and Q4, Chris, kind of in the 63 to 57 in Q4. So, not too far, a bit above Q2. Q2 was around 56, just to give you a sense, but I think it is important to. If you look at that chart, that we did put up there and you go back a few years, I mean, we saw prices in that range and even higher at some point. So, I mean, the prices at now have a carbon price as well in it, but they’re not. They’re good prices, but still competitive and provide low-cost power.

Thank you.

There are no further questions at this time. Ms. Sally Taylor, I turn the call back over to you.

There actually is a question that we can take.

Okay. My apologies. The next question comes from the line of Mitchell Moss from Lord, Abbett. Your line is open.

Thanks for the call. Just wanted to first ask, in Q1, you guys had a capital structure FFO to net debt tab or slide, the slide is not in there, but do you guys still believe that – are you still targeting the 20% to 25% FFO-to-debt for 2018 to 2020, and the 25% to 30% post-2020 FFO-to-debt?

Yes. Our targets have been changed, and if you go to our segment or MD&A you will see those detailed calculations if you want. Yes, we didn’t present that here today, but certainly nothing has changed from that.

Yes. Our numbers are up to 21% about, and we are still targeting exactly the same range.

Okay. Great. And you mentioned, I think October is when you start to make decisions about the coal to gas switch. When do you see CapEx spending for those decisions to start to ramp up?

Yes. So, as we’ve communicated – as we have talked about in the past. We're still kind of in the 2021 start period for some of the conversion. So, we expect to spend a little bit of money prior to that, but most of it will be in starting in that 2021 period. Some of that could slip into the 2020 period, but it’s not significant dollars given the low cost per unit.

Yes, remember it is about – it is between $40 million and $50 million a boiler. So, we would start having to procure equipment in that 2019 period. Depending on how many we do at once.

Okay. And I guess within the expectations of retiring – of meeting these FFO-to-debt and also retiring your 2020 maturity, you also factored some level of spend for the boilers, basically, I guess starting in 2019?

Yes. We, obviously you run different scenarios depending on market prices and a whole bunch of factors, but given we’ve already repaid the 19’s [ph] units advance we’re very confident our target and those are like 2020s. So, lots of free cash flow is going to be generated from here to there.

Yes, remember that, so before today, we had 800 million due, November 2019 and November 2020, we now have extinguished the November 2019. We’ve got all the way down November 2020, and Brett showed you where our balance sheet is compared to our peers. So, we’ve got a lot of flexibility here, and it is still depending on where the cash flows are. We’ve got, you know we’ve accounted for that kind of spending as we go forward. So, it’s a really good position.

Okay, great. Thank you very much.

There are no further questions at this time. Ms. Sally Taylor, I turn the call back over to you.

Thank you, Christine. And thanks everyone for joining us this morning. Please don't hesitate to give me a call if you have further questions.

This concludes today's conference call. You may now disconnect.