Good morning. My name is Christine and I will be your conference operator today. At this time, I would like to welcome everyone to the TransAlta Corporation Second Quarter 2017 Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be question-and-answer session. [Operator Instructions] Thank you. Ms. Sally Taylor, Manager of Investor Relations, you may begin your conference.

Thank you, Christine. Good morning, and welcome to the TransAlta second quarter 2017 conference call. With me today are Dawn Farrell, President and Chief Executive Officer; Donald Tremblay, Chief Financial Officer; John Kousinioris, Chief Legal and Compliance Officer; and Brent Ward, Managing Director and Treasurer. The call today is webcast and I invite those listening on the phone line 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 on our website shortly there after. All information provided during this conference call is subject to the forward-looking statement qualification which is set out on Slide 2 and detailed in our MD&A and incorporated in full for the purposes of today's call. The amounts referenced are in Canadian currency, unless otherwise stated. The non-IFRS terminology used, including comparable gross margin, comparable EBITDA, comparable funds from operations, comparable free cash flow and comparable earnings are reconciled in the MD&A. On today's call, Dawn and Donald will review the second quarter results and discuss progress made against TransAlta's goals and priorities for 2017. After these prepared remarks, we will open the call for questions. With that, let me turn the call over to Dawn.

Thanks, Sally, and welcome to TransAlta and welcome to everybody on this call. We've covered a lot of ground since our first quarter call and first I want to talk about how we've advanced our financial strategy. Our business units have delivered results that were in line or above expectations for the quarter. I'm pleased with our performance as we look at the first half of the year. With this improved operating performance from the businesses, we have allocated most of our free cash flow and the proceeds from the sale of the Wintering Hills wind project to reduce our debt by $184 million, which is what we said we would do. We have been advancing the company-wide Greenlight initiative, which is expected to result in new efficiencies and cost savings starting in 2018. We will be using the expected proceeds from the repurchase of the Solomon power station to strengthen our balance sheet and support new growth projects. And finally, we advanced our initiative to put project financing on some of our contracted assets. Now, the second area of focus for the year and of course for the quarter was our focus on advancing growth. In July, we were really excited to commission the South Hedland power station and we met the conditions under the PPA for Horizon Power, who we now welcome as a customer to TransAlta and they began purchasing power as of July 28th. We also negotiated the expansion of the Kent Hills wind farm to 167 megawatts and we extended the Kent Hills 1 PPA by two years to 2035.Our third area of focus of course is advancing our off-coal strategy. We continue to work with both the provincial and federal governments to formulate regulations that will govern the conversion of our coal fleet to…

Thank you, Dawn, and welcome to everyone on the call. As you can see on Slide 5, comparable EBITDA from our power generating asset for the first 6 months of the year has grown year-over-year for the past three years, with strong performance across our portfolio. For the quarter, EBITDA from our operating assets totaled $270 million, an increase of $70 million or 7% over the second quarter of last year. On a year-to-date basis, EBITDA of $580 million was up 8% over last year. During the first half of the year, EBITDA growth was most notable in our U.S. Coal, Canadian Gas and Wind & Solar segment. This number excluded EBITDA from Energy Marketing and our corporate overheads. On the slide, you can see that second quarter and year-to-date EBITDA from our Canadian Coal segment is lower than last year. This wasn't a surprise as we were expecting higher coal cost and lower realized price from our on-contracted generation when we issued our guidance. As discussed on the Q1 conference call, the higher fuel cost in the first half of the year was due to lower equipment availability and the higher strip ratio, which requires handling more overburden at the mine. The development of new pit areas during 2017 and 2018 will improve our strip ratio moving forward. However, as Dawn mentioned earlier, we are facing lower performance at our mine operations due to the emerging labor constraint. This has negatively impacted the amount of coal produced and reduced our inventory by 1/2. We have notified our customers and the AESO of our intention to derail the unit in periods of high supply and low demand for the next two months so that we can build our inventory and preserve grid reliability. This will negatively impact our availability, generation…

Thanks -- thanks, Donald. I'm going to spend the last few minutes of the call to update you on the work we've been doing to advance our transition to gas and renewables. The regulatory environment in Alberta is moving forward and our team is engaged in the process. Changes in the Alberta market continue to provide some really strong future opportunities for TransAlta. Work continues on studying the criteria and defining the operations of the province's new capacity market. We are in early stages, but we continue to believe that prices for energy and capacity will be set to maintain system reliability, but also to ensure that returns will be fairly compensated for the incumbent and new generator. Our focus on bringing the lowest cost capacity to the market remains steadfast. During the quarter, we were able to get regulatory approval to run Sundance Unit 2 for 2 years beyond 2019, which is its current expected end of life. This new date will allow us to put Sundance Unit 2 in contention for a coal-to-gas conversion if the market needs new capacity by the time we get to 2020.Our team continues to work with the federal government to ensure that we can run our converted gas-fired operations at our Sundance and Keephills plants for at least 15 years on gas. We are also hoping that plants such as Keephills 3 and Genesee 3, which are much more efficient and which currently have lower greenhouse gas emissions and will have much lower greenhouse gas emissions if they are converted to gas, will be granted additional life and will be able to run well into the late 2040.As part of the MoU we signed with the province of Alberta last November, we gained assurances that greenhouse gas credits will be given to…

Thank you, Dawn. Operator, we would like to open up the call for questions from analysts and the media please.

[Operator Instructions] Your first question comes from the line of Robert Hope from Scotiabank.

Yes. Good morning. Maybe to start off on Highvale, could you add some additional color on exactly what these labor constraints are, what brought them on and why you do not expect that higher coal costs will persist into 2018?

Yes. Just in terms of -- as you know, in November we announced the new policy framework which included the off-coal payments for TransAlta as we move towards getting off coal in this province. And then by April, TransAlta announced our intention to advance our movement off coal on to gas of our power plants. So effectively what that did unfortunately is really, really made a lot of the people that worked up in that mine nervous. And as you know, Alberta is also opening some new mines up in north, so there are a lot of good jobs for our people there. So where we -- and I'll take accountability for this -- where we got behind is as there was higher attrition and people leaving, experienced people leaving to go up north, we were having trouble getting experienced people to work for the mine because of its expected short timeframe. People don't want to move their families in if they think they're only going to be there for three or four years. So we got behind on our hiring and that caused an issue that we didn't get ahead of fast enough. So we've now corrected that. We're doing -- in the short-term here we've been able to hire contract miners who have been able to come in and really work hard and give us a lot of assistance while we're turning that around. We've had to retool ourselves and I think we'll have to retool ourselves over the duration to ensure that -- we do have to expect higher turnover in the mine because of its short duration and we do have to be able to train people much more quickly on the equipment and then accept sort of the additional supervision that will be required with people that will be less qualified. So I think at this point the work that we've done on it here to make sure that we can get back where we need to be by the end of September is very solid and very strong. And then as we go forward into 2018 and 2019 -- we'll continue to update you on -- it's really our ability to manage a labor force in a mine that has a shorter life and that's making sure that we have all the contingencies in place to overcome some of the anxiety that the people have up there.

All right, thank you for that color. Switching gears, looking at RNW, with the Solomon proceeds as well as the refinancing of Kent, you could have a significant amount of capital there and you did reference some opportunities you're seeing in that vehicle. Is that more on the M&A side, either third-party or drop downs or would RNW be potentially where you would be investing in Alberta Renewable organic projects?

Yes, I mean it really does -- so we do have the Alberta Renewables call coming and so it really positions us with some cash for that. And we have a number of projects that we -- on the M&A side that we have been looking at, but frankly we're being pretty picky because of capital. So now we'll continue to be picky because that's the kind of investors we are, but now that we see both the cash coming from Solomon and from the financing of the Kent Hills assets, it gives us some opportunity actually to be a little bit more strategic and to do something that's a little bit bigger than what you've seen us do in the past. So that's where the team is focused.

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

Hi, thanks. Can you guys add more color on Centralia during the quarter, just haven't seen strong numbers I guess for a while?

Well, like two things, Ben. First, mark-to-market, which is mostly like timing. The one with mark-to-market is timing because like those hedges that were marking to market are like economic hedge, and depending on power price, like we capture EBITDA like sooner or later during the year. Well, that's one. The other impact is FX. Like even though like the Canadian dollar both -- in the quarter very strong, like the average for the quarter was like lower than last year. So we basically got like some FX gain as well in Centralia. So those are the big driver. Plus like very cheap power price in like the Pacific Northwest in Q2, where we're normally like are shutting down and buying power to basically supply the contract we have with Puget. So those are the driver.

And that's a cash realized gain you guys are booking too or just moving --

Net unrealized, it's unrealized.

Okay, all right. And some of your commentary on the balancing pool, just waiting to see what happens there. But can you -- do you have a sense of timing on this? Obviously, this is uncharted territory. But how do you guys kind of manage -- if the balancing pool does give you money, I think it's six months or so until you get it and you want to convert earlier. How do you guys kind of mash it with the timing of the pipeline approvals?

Well, there's a lot of different ways to think about getting gas to that plant, and as and you can imagine, when we first started down this road, we had some pretty traditional ways of thinking about how we could get gas there. But since we've announced that, we've had -- everybody in Calgary stopped by to see us with some pretty interesting proposals. So we can see some different ways to potentially get gas to the plants. But I just want to underscore, I mean there's still a consultation going on. The consultation is with customers. And really the balancing pool has to take into consideration whether or not customers in Alberta will be better off or worse off by the termination of the PPA. So at this point, we're ready to go one way or the other. And I wouldn't promise at this point any early conversion, because frankly having a very -- having a plan that's organized that kind of gets done in the 2021, 2022 time frame makes a lot more sense to us. But to the extent that we can see some ways to get a bit of gas there earlier, that may bring some earlier things or it may even allow us to take Sundance Unit 2, which I announced earlier is now back in contention for the running for capacity, it could be a plant -- it could end up being our first plant converted, because, as you know, we're mothballing those units and it would be easier to convert them when they're offline. So that's basically how we're thinking about it. But I am not making a bet either way as I -- I think it's a complex discussion and I'm not sure customers are going to think it's beneficial to them. So I think there's a bit of road to go here.

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

Good morning. Just going back to the question along RNW, the entire -- available liquidity and stretching maybe your scope and possibilities, are you looking at any corporate transactions given there's a bunch of sort of -- in the state for sale potentially? Is that something on your radar or is that just off the table completely?

No, nothing is off the table for RNW. I mean, there's a lot -- like you say, there's a lot of renewable assets around. Just remember, though, that there's also a lot of money chasing that and the financial guys are chasing just absolutely the lowest returns you can imagine. So as our team looks -- what we do is we always look and say, okay, what is it that we could add here? Is there some sort of synergy with our existing operation or is there some reason that somebody -- if they are big packages of assets and they have got long-term contracts on them and they are really, really simple financial plays, their returns they are bid down to nothing. We don't want to build a company on returns that are bid down to nothing. So nothing is off the table. We look at everything. Our investment committee meets weekly on different things that the team is working on. But we're pretty picky and we have been and I think that has served us. So a little bit of patience. We deploy that capital, but you like the returns when we get it redeployed.

Okay. Then going back to Centralia, given where prices are and they continue to be weak, just maybe you can comment based on where the hedge book is whether or not the results realized in Q2 could also happen again in Q3 or the back half of the year for that segment?

The answer to that is no. Like basically we're -- like most of the generation that we have at Centralia basically is hedged and we're marking it to market. So like I don't expect Q3 to be at the same level.

Okay. And then in the MD&A there's some commentary about some initial spending on upfront design work, engineering work for Brazeau, that $5 million to $10 million will that be expensed and come through G&A? And then just wondering as you think forward, you think with that project, are you looking to build that out in sort of one large chunk or would you consider sort of a phased build out of that pumped storage facility?

No, it's -- so that money is capitalized, so it's not going to the G&A right now and it's really for the early geotechnical work that we're doing and the environmental work, all that, all the baseline studies that have to be done so that you can prove that what the impact would be of the project. And also we need -- we'll work -- we're doing -- we're taking a very early approach to working with the First Nation partners out there. But when you look at the project, it actually -- the way the engineers have looked at it, it actually could be done as a 1, 2. But it's not as efficient for the system overall to do that, because you mobilize all that labor and all that construction and then you demobilize and then you remobilize and you demobilize. And that's where the big expenses are on a construction project. So currently we're working on it as if it's one big project. And frankly by the time it would get in place, there will be a significant need for it because it would be a 2025 start time with -- construction start time in that 2021 timeframe. So right now we would like to keep it in one big project. And it's -- all the work we've done on it on the financing side -- if the government does the PPA with us, we can finance it at very, very low rates today. It's important to get that done today because who knows what interest rates will be in the future. So there's really, really low cost to capital for that, which benefits Albertans with low price storage and capacity. So that's how we're trying to -- we're aiming on it.

Your next question comes from the line of Robert Kwan from RBC Capital Markets.

Good morning. Just coming back to Kent Hills, I just -- as you get closer; really you're ending up a shorter and shorter duration on the mine. So I'm wondering how you think of -- how do we think about the very short-term, where it sounds like you've got a bunch of extra costs, to kind of get everything back on track. But as we think out over the medium-term, does that still not lead to an elevated level of cost, whether that's having much more staff just to manage the attrition or paying people to retain or contract mining?

Yes. Robert, that's certainly something that we're working on right now. So as we give you guidance for next year, we will have considered all of that to see just is there -- there might have to be -- there might be a different algorithm that's required to run it in the short-term, but of course our job is to keep the cost as low as possible and look for the ways of doing that. So I wouldn't want to answer that right now. I want to be cautious as we look ahead because these are real issues as you can imagine. But at the same time, I do think there's -- there will be some ways to see if we can do this without the cost being too high and we will give you more guidance on that as we go into our guidance for 2018.

Okay. Just following on that then, is that something you also think about with respect to the coal power operations or is attrition over time okay just given less staff needed to run gas plants versus coal plants?

Yes, that -- I mean, the big important thing there is it's a massive amount of attrition that's required as you go from coal to gas. It's a very different number of people. So that -- on that side of it, that can be quite helpful. But at the same time, we've been managing this issue now at Centralia for a long time. So we -- the Centralia -- it's surprising -- it's not surprising, but for power plant people when they look ahead and they see Centralia Unit 1 shutting down potentially at 2020 and 2025, all else being equal, they will take a job if they think there's a plant that's going to run longer. So we have other mechanisms that we use in terms of retention packages and things like that which we will have to put in place. But net-net it's not as difficult an issue with the plants. You're right on the money with that.

Okay, got it. If I can just ask about the hedging in the chart on Slide 6. Looking at the second half of the year, recognizing that those bars are expressed in megawatts, is the amount of megawatts already taking into account the derates on the coal plants and it's not just straight kind of rated capacity?

No, they're not. Normally, however, when we basically hedge, we take into account the fact that the availability will be at a certain level. So there may be some buffer in the hedging program that you have there.

Okay Then when you say it isn't, does that mean that the hedging is actually higher because of the derates or is this inclusive of derates for at least 2017?

If you look forward for the next 2 months, we may have more percentage of our production that will be hedged over the next 2 months.

Yes, you to remember in Alberta our hedging group finds out about what's going on in our plants the same time the market does. So they now have to adjust their hedging program to reflect what they got the news on this morning at the same time that you did.

Understood. And if I can just finish on Centralia. It sounded, Donald, like from your answer earlier that a bunch of the strong results in Q2 was more the unrealized mark versus economic dispatch, is that fair?

Yes, a big portion of this is the timing on the hedge exactly.

Your next question comes from the line of Jeremy Rosenfield with Industrial Alliance.

Yes, thanks. I just wanted to come back on the contracted Alberta portfolio position and just with regard to the Sundance PPA. So if the balancing pool does terminate the PPA, would you -- based on where you are in terms of contracted just right now in that portfolio, do you think that you are actually over contracted potentially going into 2018-2019 assuming that Sundance won't run as often if that PPA is terminated?

So is your question, are we over contracted in the event that the Sundance units come back from the PPA?

Yes.

Is that your question?

Yes, exactly. Like what would --

So given like the -- the chart that we have in the deck is basically contract and hedge. If the PPA roll off, like that will create more length in our portfolio. And clearly like when that happens, that people that are hedging the portfolio will have to take action. But at the same time, the people running the plants and -- we will look at the economic and we will make the appropriate decision in terms of -- like that we will dispatch those units.

Yes, the simple way to think about it is if you take 500 megawatts -- well, if you take the megawatts of each unit -- in our hedge forecast today the PPAs are included as a hedge. So when we get the money for the PPAs, they become open and we take those hedges out and you'll see that we have more open exposure and then we'll have to decide whether or not we're going to hedge those or just leave them open in the market. And all of that has got to be determined once we tell the market what we're going to do in terms of how we're going to run the plant, because we have a very different operating regime with the plant if they are not under the PPA.

Right. What I'm getting at is basically, based on what the outlook for market prices might be, if Sundance comes out of the market, what's the consideration in terms of the portfolio contractedness today looking forward? Though, essentially --

Yes. So remember all that happens is Sundance is not hedged, but it's still in the market. So the question is, without the PPAs what happens to prices. And when the PPAs are extinguished, their dispatch rights come back to TransAlta. Today we have to dispatch them based on what the PPA say and what the buyers want. Tomorrow we dispatch them based on what we think is the right dispatch for the economics of the market. So there's lots of people there forecasting what prices might do if the PPAs are taken off. So what you want to be able to do in your thinking through this is say to yourself, okay, what will actually happen to market prices and then what's the new margin that TransAlta will get off those plants when they dispatch them into the market? Now, we may hedge some of it, and if we do, we'll tell you that we've hedged some of it. But we can also -- we also have the option to keep them open if we think prices are going to rise.

Right. Maybe if I can just ask it in response. The question is really, would you proactively look to shorten your portfolio length with the recognition that market pricing might increase?

When you say proactively, what do you mean?

No, I think -- so are you saying would we --

I mean, today.

Would we hold more open than we have historically if we thought prices were going to rise? We have the ability to do that. Yes, we have the ability to do that. Yes, we like the idea of making more money.

Okay, thanks for that. And then just -- the other question was just -- whether the balancing pooling has been in discussion with you specifically regarding the Sundance or just as a general consultation and there haven't been any specific bilateral discussion?

Yes, Jeremy, it's John Kousinioris. We've had a very introductory discussion with the balancing pool, but what they're going to do with the PPA's, as Don alluded to before, is really their decision having gone through the consultation process. So we have not had any kind of extensive discussions with them at all on this point. And to the extent that we have had discussions, obviously they would be confidential. But they're going through their process and we respect their process at this point.

Your next question comes from the line of Adam Mitchell from Polar Asset Management. Your line is open.

Hi, guys. I was just wondering if you can walk me through the flow of funds from the Solomon proceeds. I guess you're set to receive -- or TEC Pipe that receives $335 million of cash, which is about $420 million. Where does that go pro-forma that transaction, it goes all down to renewables?

The answer is yes, given like there's like tax implications as well. So that will create a taxable gain. So that's why like the -- we expect the Canadian proceed to be between $350 million to $360 million. And what TransAlta renewable own, it's an economic interest in the plan. So there will be a reduction of that economic interest to the different like financial instrument that we have there. So we have tracking pref, we have pref share and we have like notes. And like the money will flow through those instruments to TransAlta Renewable.

And that's expected in what month?

We are expecting FMG to exercise their option in November based on the notice they gave us.

So you get the proceeds in November, okay.

Yes, that's right.

So I guess Renewables will have close to $1 billion of liquidity pro-forma with that transaction, right?

Exactly.

Okay. And then the first -- I guess the first -- so you'll sit on that liquidity looking for potential growth opportunities. And I think you make reference in this -- one of the slides, say on Slide 8 that the money could be used to retire debt at Renewables. Given that you've already -- it looks like you've refinanced the credit facility that TransAlta provided to Renewables, the only other debt that's available to be prepaid is the Canadian Hydro Developers Bonds, correct?

That's correct. And there's also like timing because like -- to make all payments, so we haven't made a decision yet on what we're doing. We are also planning to raise like between $240 million and $275 million in Kent Hills, which is a subsidiary of TransAlta Renewables. So that's also additional proceed that will be in TransAlta Renewable by the end of the year and we will also have to decide what we're doing with that.

Right. What about -- is the convertible debt that's held at TransAlta, is that pre-payable at all?

Like clearly it's only payable in 2020 I think. But clearly like if we -- there's -- like that's one option. If we decide to move cash from TransAlta Renewable to TransAlta, there's potential drop down. But like the priority is to grow the company more than to do a drop down or to be paid the convertible debenture.

The next question comes from the line of Robert Kwan from RBC Capital Markets. Your line is open.

I just wanted to come back to one thing, Dawn, you talked about earlier in terms of if the power purchase arrangements come back to you and the dispatch rights and in the very different operating regimes you talked about, in terms of -- although there's no prohibition on economic withholding, I'm just wondering your thoughts on dispatch control given the revocation of OBEG?

Yes. I mean, the way I've always looked at it is I think the -- I think it's -- the accurate thing is to have the appropriate level of pricing for electricity over the long-term to have a competitive economy, and that's basically what we're guided by. So the way we think about dispatching is on the basis of long run marginal costs and our long run marginal costs would include a return for the equity and a payment, both a payment -- a repayment principal on the debt and an interest on the debt, because that's really the cost, the overall cost that have to be incurred. So to us, we have kind of our financing cost, our fixed cost and our marginal cost and they affect -- and we would calculate our cost at a reasonable rate of return based on what we see in this power sector and what you can prove in the market as reasonable. So that's how we think about it, Robert.

Okay. So directionally you're comfortable with the data based on the fully-loaded cost versus the marginal cost?

I am comfortable with that I can defend to customers and to the market and to everybody that long run marginal costs are appropriate in a time of excess demand.

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

Thank you, Christine. Thank you, everyone. That concludes our call for today. If you have any further questions, please don't hesitate to reach out to the Investor Relations team.