TransAlta Corp (TAC) 2017 Q3 法說會逐字稿

Good morning. My name is Leandra and I will be your conference operator today. At this time, I would like to welcome everyone to the TransAlta Corporation Third Quarter 2017 Results Conference Call. (Operator Instructions) Ms. Sally Taylor, Manager of Investor Relations, you may begin your conference.

Thank you, Leandra. Good morning, everyone, and welcome to TransAlta's third 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.

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 on our website shortly thereafter. As usual, all information provided during this conference call is subject to the forward-looking statements verification, 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 comparable 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 Donald will review the third quarter results and discuss our progress to meet TransAlta's 2017 goals and priorities. 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, everyone. Today's call is going to be relatively short for us as we're preparing for an Investor Day Conference on December 6th in Toronto. During our Investor Day, we'll lay out our plans for the company, given the many improvements we've seen in the past year and the optionality that we've gained once the Sundance units roll off their PPA at the end of March. We are in the process of making several key decisions that will guide our gas conversion strategy and position the company during this time of transition. And we'll be ready to talk about our plans in light of these strategic decisions when we see you in December.

Now 2017 is shaping up to be a year in which we are accelerating our plans and positioning the company for success in our financial goals for both 2017 and 2018. In 2017, delivering the cash flow we promised, achieving our debt reduction targets and positioning for new growth are three of our main priorities. So today I'll focus on how we did during the quarter and how we expect the rest of the year to play out. At the end of the call, I'll give you a bit more of an outline on what you can expect from us on our Investor Day.

So turning to activities and results in our third quarter, all of our business units delivered results in the quarter that were in line with expectations and I'm pleased with their performance so far this year. The coal team overcame some of the production shortfall in the Alberta mine with better performance at Centralia, which was actually very great news. And they were also able to get back on track earlier than expected, so lots of hard work out at the mine by the mining team.

Now the statistic that I liked most in the quarter is that so far this year, as of the end of September, we've accumulated CAD 224 million of free cash flow. We are delivering against our annual target of CAD 270 million to 310 million in free cash flow and we're starting Q4 in a very strong position.

So for perspective, in 2016 for the whole year, we delivered CAD 250 million of free cash flow, so being in a position where we've already got CAD 224 million in the bag is a great feeling for everybody here at TransAlta.

So what we're seeing is that we're growing our cash flow over and above our previous run rates. Now you know that's mainly due to the cash flow that we're now receiving from South Hedland as we brought on that growth project and the additional cash that we're getting on our coal payment. We continue this year to work on our corporate initiative, which we call GreenLight. That initiative in this year is cash neutral. We are spending money to lower the run rates for 2018 and we expect as we come out of 2017 and stop that spending, that you'll start to see that cash show up in our run rates and that's part of our improvement that we see for 2018 as we go into 2018. Now we will give you our guidance on December 6th, so you'll see how that all works when we get there.

We also advanced in the quarter our initiatives to secure project financing with some of our contracted assets and the treasury team did a great job of raising CAD 260 million in bonds secured by the Kent Hills wind farm. We did receive the news of the PPA termination for Sundance. And during the quarter, we worked on the transfer of the Solomon assets back to FMG. Last night, somewhere in the middle of the night, we received a check from FMG for $324 million, so we now have that money in the bank somewhere in TransAlta in Australia and coming to Canada. And in March, we expect approximately CAD215 million from the Balancing Pool for the PPA termination.

So those two events together, what we received from FMG and what we'll receive from the Balancing Pool, now put us ahead of our plan on debt reduction, which really does allow us to start thinking about how to use some of our cash at the back end of next year for growing TransAlta renewables.

Now the statistic I like least in the quarter was our Alberta coal availability, which was down mainly due to the coal production shortfall, which led to derates. Now once those Alberta PPAs are terminated, we will benefit from increased operational flexibility and we'll be in a position to ensure these units are running economically.

We are currently reevaluating the timing of capital spending and when to time our conversions over the next few years, and we'll get into more detail on that during our Investor Day on December 6th.

We also advanced our growth initiatives in the quarter. We did submit two clean energy projects into the renewable energy procurement here in Alberta. The submission involves more than two years of planning, and we put forward some very competitive projects.

In addition to those ASA submissions, we also submitted two other bids in the U.S. As well, we put a proposal to build and operate a solar farm in Centralia mine into Puget in the Pacific Northwest.

So winning all of these projects would be a great problem to have, but we're more practical here at TransAlta and we know that there's a lot of, as you all know, there's a lot of financial capital out there. So we'd be happy if we got a couple out of those six different initiatives that we bid during the quarter.

As you all know, a big part of growing TransAlta has been getting ready to commission South Hedland, which took place on July 28th and we now are being paid by Horizon Power for their part of the plant. We do continue to have a dispute on the commissioning with FMG and we expect clarity in respect to that dispute in quarter 4.

So to sum up, our year to date cash flow is tracking ahead of where we were in 2016. We are exceeding our debt reduction goals and we are accelerating our ability to strengthen the balance sheet.

Our prospects for further growing cash in 2018 have strengthened as we've gone through the year. Not only will we gain a full year of cash from South Hedland and realize savings from our GreenLight work, we will also have some potential for upside as we sell output from the Sundance units into the market here in Alberta.

So with that, I'll turn the call over to Donald who will take you through the specifics.

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 9 months of the year of CAD 832 million was up 6% over last year. This is due to higher price in the Pacific Northwest, the settlement of our price and taxation dispute with the Ontario Energy Financial Corporation, the payment under the off-coal agreement with the Providence of Alberta and the commissioning of the South Hedland power station in July of 2017.

For the quarter, EBITDA from our operating assets of CAD 252 million was slightly better than last year. This number excluded EBITDA from energy marketing and our corporate overhead.

As expected, third quarter and year to date EBITDA from our Canadian coal segment is lower than last year. We were already expecting a result in Canadian coal to be negatively impacted by higher coal costs due to higher strip ratio and availability of equipment at the mine when we start a year.

However, in addition to those challenges, we faced lower performance from our mine operations during the first half of the year, driven by labor issue, unplanned equipment availability and geotechnical issues.

During the third quarter, we successfully implemented a recovery plan and were on track to meet the year-end production target. However, availability in August and September was impacted by the recovery as we derate our coal unit to build inventories. Additionally, our fuel costs for the remainder of the year will be increased by more than CAD 3 per ton.

Turning to our U.S. Coal segment, results for the third quarter and year-to-date have improved by CAD 11 million and CAD 41 million and total CAD 24 million and CAD 68 million respectively as we benefit from higher price on merchant and contracted revenue, and lower transportation costs for coal.

Canadian Gas EBITDA was up CAD27 million year-to-date over 2016, primarily due to the CAD34 million settlement received from the OEFC during the second quarter of 2017. This more than offsets a reduction of our gross margin at our Windsor plant.

Energy Marketing results during the third quarter improved on a year over year basis with EBITDA of CAD 12 million compared to CAD 10 million last year. However, on a year to date basis, results are below our expectation, due to lower margin in the first quarter. Earlier this year, we reset our guidance to CAD 50 million to CAD 70 million of comparable gross margin from energy marketing, down from initial CAD 70 million to CAD 90 million. At the end of September, our comparable gross margin was CAD 36 million.

Let's turn the discussion to our free cash flow. For the third quarter, free cash flow increased CAD 44 million for a total of CAD 99 million, compared to CAD 55 million last year. The increase was driven firstly by a decrease is sustained capital of CAD 22 million compared to third quarter of last year, which is due to timing. And secondly, by the partial payment of a long-term receivable from a customer in Australia. In 2016 and early part of 2017, we reduced our FCF to reflect the increase in long-term receivables and now we're reversing this as we receive the cash.

On a year-to-date basis, sustaining capital of CAD 173 million is CAD 14 million lower than the first nine months of 2016. We expect 2017 full-year of sustained capital to be between CAD 245 million and CAD 265 million. The reduction in sustained capital will be offset by increased investment in productivity capital. Also affecting our free cash flow for the year is the IRR amount paid to our noncontrolling partner in Ecogen for their share of the OEFC settlement.

As you see on the power slide, Slide 6, our results over the past three years have not been impacted by the Alberta spot price, due to the high level of contracted cash flow. Both EBITDA and FFO have increased year over year and this year we achieved the highest third quarter results since 2013. During the same period, the average Alberta spot price for the quarter has dropped approximately 78% from a high of CAD 84 in 2013 to a low of CAD 18 last year.

In 2017, we are starting to see price increasing in Alberta, with average third quarter price increasing by CAD 7 to CAD 25. On a year-to-date basis, average power price in Alberta have increased CAD 5 over last year to CAD 22 per megawatt hour. This is partially due to the increase in the carbon tax in 2017.

Our fast results reflect a strategy of maintaining a high percentage of contract regeneration and hedging in our portfolio. Looking out to 2018-2019, with the termination of the Alberta PPE we will have much lower volume of our generation contracted than we have had in the past and we are reviewing our hedging strategy.

Power price in the province are in the range of CAD 44 to CAD 45 per megawatt hour for 2018 to 2020 and given the marginal costs of our coal plant going forward, with the expected increase in carbon tax in 2018, we don't see a lot of value in hedging our portfolio at these levels. This is consistent with our strategy of increasing our flexibility in managing the plants to optimize the profitability of our assets in this timeframe. As a result, we will be shifting our strategy to maintain our exposure to the potential upside in spot price relative to the price we could hedge at today. Over time, if prices increase, we will reevaluate our strategy and reduce our exposure to volatility in power price.

Let's move on now and talk about our balance sheet and credit metric. As you can see from Slide 7, we used cash on our balance sheet to repay our CAD 400 million of bonds maturing in June. We currently have access to CAD 1.4 billion of liquidity between TransAlta and TransAlta Renewables. As Dawn mentioned, we received a termination from FMG for the Solomon power station repurchase and therefore we expect to have approximately CAD 250 million to CAD 300 million on our balance sheet as of December 31st, 2017.

With the Sundance PP termination proceeds of approximately CAD 250 million in March, we should be in good position to repay the $500 million bond maturing in Q2 of next year.

Turning to slide 8, during the first 9 months our FFO to adjusted net debt ratio improved from 17% at the end of December to 19.2% at the end of September as a result of the reduction of our net debt by more CAD 200 million and an improvement in adjusted FFO.

Half of our debt reduction this year was achieved by allocating a large portion of our free cash flow to debt-free payment. Additionally, our balance sheet benefited from the strength of the Canadian dollar at the end of September.

Our goal is to improve our debt metric high end of our target of 20% to 25% FFO to debt by 2020 and we are ahead of our plan on reaching that goal. Our plan at the beginning of the year was to raise CAD 700 million to CAD 900 million to fund the construction of South Hedland and repay CAD 800 million of debt maturing in 2018. As we previously discussed, we closed at CAD 260 million bond offerings secured by the Kent Hills wind farm and CAD 197 million of the proceeds was used for the early redemption of the Canadian hydro developer outstanding non-record debenture.

This is another example of our strategy of issuing project level amortizing debt, aligning our debt with the life of the asset. Over the next six months, we will receive in excess of CAD 550 million in proceeds from the PPE termination, which will be used to reuse our net debt and provide greater flexibility in executing our financing plan and the timing of redeployment of the capital.

Turning to our cash flow growth target, we remain confident in our ability to deliver CAD 400 million of free cash flow for the period 2018 to 2020. We will be providing more detail on our assumption to achieve this at our Investor Day.

During the quarter, our Solomon power station was commissioned and is expected to contribute approximately CAD 80 million to EBIT and FFO on an annualized basis. We receive our first annual off-coal payment of almost CAD 40 million in the third quarter.

FMG repurchased and subsequent PP termination at Solomon was not expected at the beginning of the year and that's a negative impact of CAD 50 million to our free cash flow for the next year. However, we are confident in our ability to redeploy the capital over the next 24 months.

Starting in January, our renewable asset in Alberta should be impacted by the implementation of the carbon tax. We are still working closely with the government of Alberta pursuant to the MOU we signed with them in November to make sure our renewable asset in the province are [inaudible] early post 2018.

Lastly, I would like to reiterate that we made significant reduction in our cost structure and we continue to implement our cost saving issues. We are currently advancing our plan for 2018 and we are seeing the impact on the bottom line and remain confident that we can deliver CAD 50 million to CAD 70 million in recurring savings.

With that, I will now pass the call to back Dawn.

Thanks, Donald. So in summary, the quarter was good and we're well positioned going into Q4 and feeling very positive about the remainder of the year.

So in closing, a few comments on our plans as we move into 2018. So first of all, our steps to execute our coal to gas strategy are becoming much clearer and we'll be in a position to share our plans with you in early December.

Earlier this week, the federal government released its proposed rule to allow coal plants to convert to gas. Based on these new rules, each of our units will be able to run between 5 and 10 years past their current life, adding a total of 75 years of operational life to our fleet.

We are really thrilled with these rules and I'd like to thank John Kousinioris and his team, who worked diligently with both the federal and the provincial governments to ensure that those rules not only worked in terms of missions requirements, but that they worked so that these plants would be competitive in the new capacity market that's being designed here in Alberta. So a really important piece of work that's been released now by the federal government and important to how you evaluate TransAlta and its future.

Now in the 2018 to 2020 period we do now have much greater flexibility on how to run our Sundance units and as I said earlier, we'll talk about what we're going to do there at our Investor Day. But what you've heard from Donald is that we are now shifting our approach to hedging the market here in Alberta. We've now given the team the ability to be much more flexible and enter into hedges when we're comfortable that the prices incent the dispatch of those units. Now that's a very different position for TransAlta to be in and we'll be talking about that again in December.

And then kind of finally as we exit the year here, we are finding that the management team now can start to turn its attention to growth and spend much more time on that.

So all this is to say that in December we'll be presenting concrete plans for where we're taking TransAlta and how we are positioning to achieve our aspiration to become Canada's leading gas and renewable company.

I hope I've given you enough reasons to show up in Toronto on December 6th. We're bringing the management team out. We have lots to share and we will have a lot of decisions made by then and some very concrete plans. So it will be worth the effort that you'd have to take to come to something like that. We look forward to seeing you there.

And with that, I'm going to turn the call back over to Sally and we're going to take questions on the quarter and the rest of the year.

Thank you, Dawn. As we've mentioned several times, we are going to be hosting an Investor Day the morning of December 6th at the Royal York in Toronto. So for those of you who are unable to attend in person, a webcast of the presentation will be available on our website as well.

With that, Leandra, could you please open the call up for questions from the analysts and media?

(Operator Instructions) Ben Pham, BMO.

I wanted to clarify the disclosure on the free cash flow impact of the Solomon. Was it CAD 15 million or did you say five zero million?

It was CAD 50 million, five zero.

And when you think about your longer-term guidance of CAD 400 million plus, so you have a negative impact from Solomon coming off of that. And so now you're assuming that you could redeploy those proceeds into a similar asset with a similar return to achieve that guidance?

That's the objective that we have, yes.

And just sticking with the guidance, could you maybe walk through with Sundance the Balancing Pool [inaudible] at dispatch rights to you and you've indicated you think that could be the cash flow neutral to you. And maybe just talk about some of the levers that's driving the assumption.

Basically once the PPAs are terminated, which will happen at the end of March and the PPA have clauses in it in terms of how you think about those termination payments, we effectively get paid out for the capacity payments that we would have gotten paid over the period of 2018 to 2020. And the units are returned to us and the dispatch rights are returned to us.

And this is what, Ben, we'll be talking about at Investor Day, so now it's up to us as to how we dispatch those units into the market and we don't -- as you recall, in the PPAs there's pretty strict performance requirements and there's penalties and incentives based on what the Alberta market looks like. All of that all goes away and those units become ours. We decide how to dispatch them, we decide what capital we need to spend on them, we decide what availability targets we have for them.

Now we have to think about that relative to also positioning those units to be on gas and to be ready for the capacity market. So those are the kinds of decision that we're making. But just generally think about it this way, we've now got a pretty large portfolio of merchant generation and prior to this, we would have been in a position right now as we were going into 2018 where around 90% of our portfolio would have been hedged. We're now significantly unhedged and we've changed our hedging strategy so that we can get more comfortable with prices before we even lock in prices and dispatch those units.

So it's a very different game for us in 2018.

Rob Hope, Scotiabank.

Maybe looking down into Australia, can you maybe provide us a little bit more color on the South Hedland PPA dispute with Fortescue? Is Fortescue taking power right now or what is the nature of the dispute?

John Kousinioris speaking. Because we're in the middle of a dispute, to be honest, it's not something that we're able to actually talk to you much about. I can tell you that we're in a dialog with Fortescue on the commissioning and the dispute sort of centers around whether or not we met all of the criteria that was required to actually technically meet all of the commissioning requirements for the plant.

So we're working through that with them. And we continue to supply power in the normal course to Horizon Power from the plant. But just given where we are with them unfortunately there really isn't a lot that we can do in terms of comment.

And then maybe just switching gears in terms of the liquidity available to RNW and yourself right now and the organic projects that you have in front of you. It seems like this would be putting forth capital late 2018. Or are you seeing other opportunities that you could accelerate the deployment of capital, whether it be M&A or other opportunities?

Yes, and I think I've said this on many calls before, Rob, there's lots of opportunities, lots of assets that are trading hands right now. And there's lots of transactions that are happening. What we're seeing though is that the transactions are being done by the financial players, not the strategic players. And it's kind of odd to me, being in the industry for 32 years because typically one used to think that the financial players were the ones that wanted the higher returns. And the strategics were the ones that people called them strategics because they'd be like okay, those guys will dive to get projects. But the financial players are -- they seem to have unlimited free capital to put into assets and so we're watching transactions trade at very, very low returns that don't fit into our portfolio.

So our team, we bid a lot, we do get into the second round of a number of transactions, but we are consistently seeing ourselves being beat by the financial players.

Now, whether or not that starts to change, capital markets change, I don't know, but right now we're kind of holding our powder free for returns that we think TransAlta Renewables and TransAlta shareholders will want. But lots going on.

Mark Jarvi, CIBC Capital Markets.

Going back to the last question and the liquidity that's in the RNW after the Solomon sale, is there any way that cash gets back to TransAlta specifically or is it largely going to be sort of stuck or held at RNW until they can deploy that?

Clearly that would -- like RNW will have to make a decision. But there's a way for sure to basically move the cash from RNW to TransAlta. There's intercompany debt between the two companies that we have still. There's potential, like other [inaudible] downs, so if we choose to do so, there's a way for us to move the cash from one entity to the other, if that's best use of cash for RNW and TransAlta.

Just to clarify on that, when we look at our credit rating, especially with S&P, they do look at the company on a consolidated basis. So you should just consider that as you're thinking about that.

I was thinking more of redeploying the capital at the R&W level of how soon that could be done and whether or not there's any chance that capital doesn't go back out to sort of restoring the lost free cash flow from Solomon and goes to debt retirement or something like that.

Well if you think about in my comments I talked about we bid basically, I think it was -- altogether it was five different -- four farms and the solar project in Washington State. All of those are fantastic projects for TransAlta Renewables. They're all awesome contracted renewables.

And going along that same line, in the past you've talked about opportunities for solar in Australia. You didn't really mention it today. Is that still something that's a possibility or is that something you find a bit a harder to get done?

We're still working on that project. They keep shifting their sands over there in terms of their rules, which is something that we see in all jurisdictions that are trying to bring in renewables and trying to deal with carbon pricing. So there's been a bit of a shift over there, but net net that project's still very viable. There's a team that's still working on it. At one point, we were thinking about selling off the carbon credits and looking at the energy on a merchant basis, so there's a bunch of different ways that we can do it. But yes, that project's still on our list.

And then previously in your commentary outlook, you talked about incremental debt financings now with the PPA termination payment and the cash coming in from Solomon, is there any expectation that would be more project-level debt done in the next 12 months?

That will be depending on like our success on some of the growth initiatives that we have. So currently, like we will sit on the [inaudible] of liquidity between now and March of next year. And depending on the success that we have on the growth, we may go back to the market to raise capital or we may not. That will be dependent on our success on the project that we submitted recently.

I think in terms of timing, we would have done that this year, but now that we have the proceeds from Solomon and the PPAs, it allows us to kind of shift that work out another year.

So nothing to be done on South Hedland in terms of levering that asset, putting project-level debt --

No.

Andrew Kuske, Credit Suisse.

Maybe this is a question for Dawn. And it's just how do you think about the asset positioning that you've got in Alberta with the market transition that's underway? And obviously you've got a lot of experience in running those assets, so I'm confident on that side of the operations, but how do you think about just the market risks from a market operational standpoint as we transition to the capacity framework? And then both up and down from a pricing standpoint.

So my view is if I look at Alberta and I look at Canada, it's generally -- so if I look at Canada generally as an economy and I look at Alberta, I do think that it's going to be fairly flat here for a while. So we are in no way positioning the company for a big upsurge in growth. If we get an upsurge in growth, raw, we've got lots of opportunity to play into that. But we're kind of positioning for a slow-moving kind of economy in the next of years.

That being said, we think that the market is getting more -- as the years ago by, we're still seeing growth in the province on megawatts and some of the surplus is getting moved off. And as that surplus moves off, we're seeing some upward tick in prices. And remember that once the PPAs come off, we think we'll return to a more proper bidding regime here in Alberta. So we don't actually believe that the low prices in Alberta here were based on supply and demand. We think there was quite an impact from just the PPAs moving around.

So having that left off the market, we think prices will start to recover. Now remember they have to recover enough to make it profitable to run our plants and so that gives you a sense of how to think about some of the direction that they need to go.

As we move into the capacity market, we think that in the early years of the capacity market there'll be a lot of capacity available still, because we still are running pretty flat profiles on our growth. And it depends on some of the rules for the capacity market, whether or not they allow opportunity cost bidding for the energy or marginal cost bidding will determine kind of what the energy prices will look like. But we just kind of always go back to the same rule of thumb, which is on average for there to be a healthy power market that gives the right amount of generation for reliability in the province and for the consumer, you just go back to long-run marginal costs. And so if you think about long-run marginal costs in Alberta would be a combined cycle plant with a lower gas price. So that's a big thing you've got to put into your models.

Most people would have had a CAD 3 to CAD 4 long run gas price in the past for their long-run marginal cost. We're now looking more in that CAD 2.50 range as we think about long-run marginal costs. And then we think about what is the capacity payment that's required for a brand new plant.

So if you think about a brand new combined cycle plant, CAD 2.50 gas, what capital you need to make a capacity payment and then what that energy becomes with the carbon pricing in it, that gives you a sense of where we think prices will go and then we take that price and we put it back against our assets. And what we'll be showing you on Investor Day is how our plants, our coal to gas conversions are more competitive than that for quite a long period of time. And then as the market has to build, we continue to run those plants and make money off them.

So Andrew, you've got to come on December 6th because that's where you're going to get all the answers.

I will be there. I will commit now. But maybe just a follow-up, because that's a very useful answer and just you mentioned the CAD 2.50 on gas. Given just some of the quirkiness in the Western Canadian gas market, is there potential downside bias to that assumption? And then the natural corollary of that for you or the benefit for you is effectively given the coal to gas conversions, you could actually make more money in that kind of environment than you may in a higher price environment.

Yes, that's right. And so I do think there's downside and I do think it's interesting, because you've got to think about it -- what does it mean in an energy-only market and then what does it mean in a capacity market? So in an energy-only market, you've got to determine whether or not if that downside is too much downside, then plants [inaudible]. So really what ends up happening is the dispatch, how people bid into the market probably have a bigger impact on pricing than let's say the gas price would.

As you go though into energy-only market, if you have certain rules, that downside actually reduces prices. But net-net the way our models are showing -- are working, lower gas prices absolutely benefit going to gas sooner. And those are the kinds of decisions we're trying to make right now.

Robert Kwan, RBC Capital Markets.

Maybe going back to your comment on you've had to see for a while a lot of the financial players have been chasing the returns down. I'm wondering, do you see that potentially as an opportunity to take advantage of a lot of these entities and their views on returns by partnering would help your funding, as well as improve the cost of capital of your bids?

Well you must have been reading the goals that I took to the board yesterday because one of our top goals from our growth perspective is to seek out partners on the financial side because we think we have a lot to offer in terms of our knowledge of the markets and our ability to run plants and our ability to structure and work in the regulatory regime. And most of them need that kind of expertise.

So yes, I do see that, Robert, as a potential and that's going to be part of the work that I'm going to be doing in 2018 with our team here.

Turning to hedging, in terms of just the comparisons of the numbers '17, 2018, 2019, without getting into too much granularity, but is the shape of your hedging profile relatively similar to those three periods, just thinking about the seasonality as well as the on peak, off peak within days?

I'm sorry, are you asking are we open all year or what are you asking?

Just more on the sense of as the price moves up, is that a similar shape throughout the years or is that potentially a function that you've hedged kind of more on peak seasonally and on peak within the days and that's moving the price?

So clearly what you will see are just probably more like what I call like dynamic hedging. And like trading through -- take benefit of the capacity that we have. And we will basically very similar to what we're doing in Centralia obviously, where we basically have a merchant plant there and using this as an option. So that's the way that the traders that are helping us on the hedging will probably look at this.

And let me expand a bit. So Robert, just people probably have forgotten and we used to talk a lot about this with our investors and with the analysts. But we had this kind of four-year ladder strategy and we had this set of rules that we pretty well stuck within where by the time we got to October of, let's say 2017, we would have been 90% for 2018. We would have been between 80% and 90% for 2019, between 60% and 70%. So we kind of laddered it out.

But as we started to come into this year and thought there was some chance that the PPAs would come back and we'd end up with a big open position, we had some choices to make, right? And for sure when we got the news in September we had to really face into this. And it was whether or not we would continue with that.

And we've decided that when you look at Alberta, we do believe the bias is to the upside in Alberta as I just discussed with Andrew. And what we've done now is we've given our teams the full flexibility to either hold that power and dispatch it into the spot market, or if they see good hedges, they can hedge us by going forward.

So when we come in December and we come with our views of our outflows for 2018 and 2019, we're actually going to probably have more of a range around them because we are allowing ourselves to be more open. So there'll be more variability in the cash flow, which you guys will have to get used to. And we'll show you what that is. But the marketing team will also -- Jennifer will give you a sense of how they're thinking about hedging the market and they'll talk about how we're using this dynamic hedging to do that.

So all that is to say that we've given our teams more flexibility now to make sure that we've got the right prices, because we can't run these units at a loss, as you know. And so either the pricing is there and we run them or the pricing isn't there and we don't. And that's the way that we have to think about it.

And if I can just finish with a question on GreenLight. You've made the comment that you expect it to be cash neutral in 2017, is that correct?

Yes, that's correct.

But the amount of cash going out the door, both in OpEx and CapEx, is up fairly significantly from prior disclosures. So is it that it was actually going to be accretive to cash previously? I think you're spending CAD 45 million to CAD 60 million this year in total and the total program savings was CAD 50 million to CAD 70 million annually.

At Investor Day we'll provide like more granularity to all this. We have some [inaudible] CapEx that are basically are over, like recovering over like two or three years. And the cost of the program will be basically paid this year by the savings that we're having this year. And next year we should be at least at CAD 50 million to CAD 70 million, but we'll share more information at Investor Day on that.

So just to be clear though, you are almost at the full run rate for 2017 and under the prior expected spending it was going to be accretive out of the gate?

No, it was never going to be accretive out of the gate. So I've just got to go back and get the guys to show me what numbers you're looking at because some of the increases in the operating costs could be because we're bringing on new plants that have new operations. That adds operating costs. So I just have to look at that because that's not what I would have expected. I'll have to let you know.

Avery Haw, TD Securities.

Just on your shifting hedging strategy in Alberta, to capture more upside on power prices. I'm just wondering if you've maintained dialog with the debt rating agencies on what your plans could be and if they're onboard?

Yes, we had discussions with rating agencies. They don't give us any credit for like the hedging basically. Like rating agencies look at long-term contracts. That they gave us a lot of credit. But the short-term hedge that we have in place, they are not giving us a lot of credit for that. So that's another a problem.

And I would say that frankly in their view, if we're more competitive and we kind of make more cash and pay down debt sooner, they'd rather us do that than hedge and minimize the benefit. So I think that was the major part of our shift. When we shifted our hedging strategy, those discussions with the credit rating agency helped us crystallize why we were doing that.

Maybe just a final question on Alberta. Now that you have -- there's been another iteration with the working groups on the capacity market front, are there any new updates that you can speak to from your perspective? And I'm generally just wondering whether or not everyone's still on the same page when it comes to major aspects of design or if you're beginning to see a bit more disparity between participants as the details become narrower and narrower.

It's John. We're actually at an interesting time in the development of the capacity market in the province. I think, as you know, there's been a couple of Sam 1, Sam 2, which are basically the straw Alberta market that's been developed. And so far, I think, there has been what I would call a reasonable level of alignment, and I think speaking for TransAlta, we've been pleased generally with the direction in which the capacity market has been going.

What's in process now is a lot of the sort of heavy lifting and the detailed work that's going to take place. There is a consensus around a number of factors, but there were differences too in each of the five streams of working groups that they're dealing with and that our team is involved in. We're actually directly involved in four of the five.

So there's work that's going, there'll be differences of opinion that will need to be worked out in terms of the specific mechanics along a variety of the technical elements of the capacity market ranging from things like offer mitigation, all the way to making sure that the capacity amounts that -- capacity factors that various types of generation will be able to have will be brought in.

So there's a lot of work to do yet. I mean we're a year or so away from this being landed. But I think what you'll see over the course of probably the next two months or so, two to three months, is a more detailed set of where things are going directionally. I think we're generally supportive and the view that we tend to take is that if you look at the capacity market in the 2020s, the pricing that you should get in total, and by that I mean the capacity price, and the energy price in the market, should broadly approximate, at least from our perspective, fundamental supply-demand outcomes in the marketplace. So that's how we look at it.

I would say that what all participants share is the view that at the end of the day, just whatever the design is, that the market has to be strong enough to be a market and incent behavior without additional intervention over and over again. So if the worst outcome for Alberta will be to have a pretend capacity market, where it's just really a regulated construct of a way to deliver some value to the existing incumbents and some way to attract new incumbents, but it's not all that real and it requires intervention year after year after year, that is an outcome we're all against. So it has to be a good enough design that it's a real market. It really does incent people to do things, like for us does it provide us with enough incentive to want to convert our plants and keep running them now that we have the federal regulations that say that we can do that? And for new incumbents, does it incent them to come and build power plants here if they're needed?

And we're seeing a lot of -- in the U.S. you're seeing a lot of attempts to continually intervene in the markets there. You're seeing -- there's this dispute now going on with the Department of Energy down in the U.S. where they want to keep coal plants on because they have 75 days of supply in the coal pile and they're worried about winter. And it's really just an attempt to keep coal plants on. They're subsidizing nuclear plants to stay on, so the capacity markets there are seeing a lot of intervention and as soon as that happens it just drives up investment. So we're all aligned to that.

Now the details of some players I think would like more capacity value and less energy, and others would like more energy value and less capacity. And it completely depends on what your portfolio is. So if you have a gas plant or a hydro, the good news about TransAlta, if you have our hydro, you don't care because you can make money in either market. But on the coal to gas, you probably want more of an emphasis on the capacity side. If you're a combined cycle gas plant, you want more of an emphasis on the energy side.

So depending on what -- you can almost game it out by looking at the portfolios of the different players. At the end of the day, I don't think anybody really cares about the details, they just care that it's an actual market and not a set of -- my view would be if it's just a re-regulation with a lot of intervention year after year, then we shouldn't do it, we should just either -- we should probably just re-regulate because it just starts to become a silly set of rules.

Jeremy Rosenfield, Industrial Alliance Securities.

Just a couple of high-level questions and couple of cleanups here. First, if you look at what's happening with sort of stalled PPA terminations for other companies in the Alberta power market, I'm just wondering if you have sort of a base case that you've incorporated into your own outlook for the power market. And maybe if you're interested in sharing that with us.

I don't know about the other guys. My base case for us is that we believe fundamentally that the Keephills PPAs will likely stay on till the end of their duration. So we won't have those plants back until the end of 2020. And then Sundance is done. So that's what our base case is for us.

Another high-level question. If you look at just the overall portfolio of TransAlta, do you think maybe that the market is penalizing the company, penalizing the stock because of the maybe concentration in the Alberta market? And perhaps whether that should guide your ambitions on the growth side and how you might look to diversify the portfolio going forward.

I think the market is in terms of penalizing, because I think they are, because there's a lot of cash in the company compared to the stock price. But I think it's more a little bit of the uncertainty in Alberta. So it's a combination of we're shifting from an energy-only market to a capacity market. We just talked on the call about all the different things that people want out of that capacity market and people not really having the confidence that the capacity market will lead to long-run marginal costs being the prices that you can expect, because that's really economically what it should do.

So I think there's some worry about that. And I think we haven't been -- because of the uncertainty around the company, do we have PPAs, don't we have PPAs? When the PPAs roll off, what does that mean? What does the hedging strategy look like? All of those questions, it's just too many questions for investors and it's too complex.

So what we're endeavoring to do in December is lay down our plans, simplify, be real clear about where we're going and I think that as the market starts to see that simpler way of doing things, I think that will -- and they get confidence around this cash, the cash that we created last year, this year and the next year, I think that will take some of that penalty off.

Just one cleanup at the end here. There was mention of Canadian coal fuel costs being a CAD 2 per megawatt hour additional increase. I think that's in the outlook there, in the MD&A. I'm just curious if that was in relation to the year-to-date fuel costs or if it was in relation to something else?

No, basically it's the recovery of bond that is causing our fuel costs to be higher than what we're expecting.

And it was CAD 3, not CAD 2. Just to be clear.

(Operator Instructions) Patrick Kenny, National Bank Financial.

Question for Donald, and then I guess a follow-up to the question with respect to the rating agencies. But as mentioned, your contracted profile drops next year from, call it 80% to 90% down to 55% or so. Yet Donald, we haven't seen any change in your target credit ratios I guess yet. So I'm just wondering, even though your debt levels are coming down, given your business mix is becoming more merchant, your thoughts on what the optimal capital structure should be beyond March 31st just relative to the old metrics of 3 to 3.5 times debt to EBITDA and 20% to 25% FFO to debt.

A few things. First, clearly our capacity under contract is going down, but when you look at our FFOs that are under contract, the reduction is a smaller number. So that's one thing.

We clearly need to manage the financial risks with the business risks, so clearly we've left that contracted cash so business isn't increasing, but at the same time, we're reducing our debt accordingly. And the way I'm looking at the PPA termination is like it's a credit positive because we're getting like all the CapEx in Canada is supposed to have, like over the next three, four years, we're getting that upfront, we're applying that right away on the debt, and we still have the options on running the assets and making margin on those assets.

So for me, it's a potential increase in cash flow before managing the asset appropriately and we have the right -- like we're making the right decision, but we're also getting the cash on the capacity payment of fund and we're applying that right away on the debt. So for me that was like a credit positive from a rating agency perspective. Clearly our strategy going forward is to basically continue working with them, making sure that the rating understand what we're aiming for. Like when we say our goal is to be in the 20% to 25% and what we say is we need to be at the higher end of that 20% to 25% and that's what we're aiming. We won't be there, like we will be in the 20% range by the end of the year. Next year we should continue to improve on that fund and we continue on our strategy of reducing the debt. Our growth strategy is currently adding contracted cash flow. And the FFO from the company is still highly contracted. When you look at our gas and renewable business, it's highly contracted.

And then maybe for Dawn. Just clearly hedging at CAD 49 for Sundance generation is not a good trade, but just given the size of Sundance three to six, relative to the overall market, and the ASOs target reserve margin of 15%, clearly that target is not met without at least some capacity of Sundance on the grid. So just wondering if you see any potential for some sort of contract for differences agreement with the ASO, just to keep at least a couple of the Sundance units online? Or has that ship sailed and is the market really facing a situation where if forward prices don't move higher from here, all of the Sundance units could be offline come April?

There's been no contact by the ASO to us, I'm not expecting -- nobody's phoned over. And I would have expected some of those discussions to have happened before those PPAs came back. But I think you're 100% correct, if the prices stay where they are, the units aren't economic. So you have to expect for those units to run there's to be more price in the market.

Adam Mitchell, Polar.

Quick question. Given the significant amount of free cash flow you'll generate in '18 and the fact you've already achieved your debt reduction targets, if you don't win some of the six or so new RFPs, and you continue to get crowded out by financial players, what's your plan for what looks like excess capital that you'll have?

As you know, there's always an annual or a biannual or a quarterly discussion on capital allocation and we have several choices. We can strengthen the balance sheet even further and get it ready for what we think will be some great opportunities in the market. Because typically when you go through these cycles of people diving down for returns, they run out of cash and then returns start to go back up again. And I've been through this before in my career.

So when some of these guys have blown their wads and find out they actually won't make any money doing that, returns tend to come back up. So we can build our cash on our balance sheet even more. We can start to think about our dividend policy, we can think about share buybacks. All of the above are available to us and we constantly think about that as we go forward. We're just not prepared to take low returns when there are other, better alternatives in the marketplace, including waiting it out a bit.

So all of that is something we discuss all the time and we'd continue to have those discussions if we saw that there really wasn't the growth opportunities that we thought were good for the company.

And does the board look at the dividend policy and share buyback policy on a quarterly basis?

We would typically look at that annually. And in certain circumstances you start to look at things more quarterly because it becomes a decision that's more imminent. But typically on an annual basis we have a capital allocation discussion.

Mitchell Moss, Lord, Abbett.

I'm learning to understand, there's been a bunch of different gas price numbers that you said you're using for modeling assumptions around building new combined cycle. And did you guys say it was CAD 2.50 gas?

Yes, so in the Alberta market, our best advice would be a range -- you kind of do a range between CAD 2 and CAD 3 with CAD 2.50 being your kind of middle range. And those are [inaudible] prices, and so you've got to adjust for transportation and things like that. But in the Alberta market, gas has come off significantly. One of the earlier people talked about some of the -- there's some challenges here on the pipelines, but typically those challenges go away fairly quickly as people put some compression in and fix that up. But in the short term, it's even lower than that.

There just is a lot of gas backed up here in Alberta and the gas producers really would like us to get on to converting our coal plants to gas as soon as we can so they can get some demand here.

In terms of that deconsolidation process that -- those kinds of discussions with S&P, have you found any indications from S&P about whether or not the agency would look at TransAlta sort of on a deconsolidated process at any point, in a deconsolidated entity anytime soon?

I don't think it will happen anytime soon, but my goal is to be there by some time toward the end of our 2020 period. We should be in that by 2020, 2022, we should be able to get there. This is a things also linked to the amount of recorded debt that we have in TransAlta and as we repay the recorded debt and we pay this using, like project-level financing, that will help our case, because there will be less debt at the corporate level. But all that being said, we still have some work to do with them. We're pitching this to them, like every time we're meeting them, we're showing them deconsolidated metrics every time. But they're just not ready yet to make that decision.

And finally, as you start to think beyond 2020, do you think that you'll be able to start to give guidance on where you see things post 2021's really the auction, I guess an auction occurs or kind of what's that point of when the forecast -- post 2020 forecast can be sent out to us?

In terms of giving cash flow guidance, what we're endeavoring to do, and we're going to see how well we can do this for you for December, and if we can't get it in December, it'll be some time next year. But we're just trying to think about how do we give you some rules of thumb? And then how do we make sure that our public disclosures give you the information you need so that you can convert the thinking and the capacity market into cash flows for TransAlta. So we know that that's difficult for you because we've got our models run and we know kind of what they look like with various assumptions under the capacity market. We haven't turned our attention to how do we get our disclosures right so that you can figure that out. So we'll have some ways -- we're going to start to give you some ways to think about that as you're modeling the company when we see you in December.

I would now like to turn the call back over to Sally Taylor for closing remarks.

Thank you, everyone. That concludes our call for today. If you have any further questions, please do not hesitate to reach out to myself or Alex in the Investor Relations team.

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