TransAlta Corp (TAC) 2016 Q3 法說會逐字稿

Thank you for standing by. This is the Chorus Call Conference Operator. Welcome to the TransAlta Corporation 2016 Third Quarter Results Conference Call and Webcast. (Operator Instructions) At this time, I would like to turn the conference over to Jaeson Jaman, Manager, Investor Relations. Please go ahead, Mr. Jaman.

Thank you, Zubane. Good morning and welcome to the TransAlta Third Quarter 2016 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 Todd Stack, Managing Director and Treasurer.

The call today is webcast and I invite those listening on the phone 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. All information provided during this conference call is subject to the forward-looking statement qualification, which is set out in the slide deck and detailed in our MD&A, and incorporated in full for the purposes of today's call.

The amounts referenced (inaudible) 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 third quarter results and progress made against TransAlta's goals and priorities for 2016. After these prepared remarks, we will open the call for questions. I will now turn the call over to Dawn.

Thanks, Jaeson, and welcome to everyone who has joined our call today. It's November here at TransAlta, so that usually means I'm going to lose my voice in about the next hour and a half. So I apologize if I'm a bit hard to understand, and we do have backup in the room.

So much to update you on today. Today I'm going to provide you some thoughts on our quarter end, my takeaway from some of the things that are happening here in Alberta and in Canada, and I'm also going to talk about the progress that we're meeting--the progress that we're making as we meet our 2016 goals.

Now just to remind you, our 2016 goals were to achieve our operational, financial, and safety targets, and I think we're doing a great job there, to reposition our capital structure, to grow our portfolio of contracted gas and renewable assets, and then finally to secure a mutually beneficial culture and vision arrangement here in Alberta.

So I'm going to address the first three goals at the beginning of our discussion here today, and then I'll address the fourth role in my closing remarks.

So let me start with an overview on our quarter and year-to-date results and my analysis on how the business is progressing in this environment.

When you look at slide five, which is on the screen now, you can see that we've surpassed the 2015 results for the quarter and year-to-date for our financial metrics, which include EBITDA, FFO, and free cash flow. Improved results during the quarter and year-to-date are the result of positive contributions from the renewable assets that we acquired in the second half of 2015, solid performance from our gas and renewables portfolio, and cost reduction initiatives across the fleet that we implemented in 2015.

The last metric, adjusted availability, measures operational performance across our fleet and is particularly important in our Alberta coal fleet for units that are under long term PPA contracts. That's why in 2016 our adjusted availability is up to 89.3%, which is also an improvement over 2015. So for me, all of these metrics together clearly demonstrate that we're continuing to build our execution advantage here at TransAlta, which was one of our strategic themes that we introduced at our AGM earlier this year. The other two themes were about wins and history repeats and more to come on those as we get to the end of our conference call today.

We now have slide six on the screen and you can see that on the past couple of calls, we've talked about this notion of free EBITDA performance and the contribution from our renewables and gas-fired fleets. This is important because I want you to see how our performance is increasingly less impacted by the returns from our coal fleets. As our Chairman noted on our AGM, our transition to becoming a clean energy company is well underway.

Slide six shows that our free EBITDA for the year is $$608 million. And here you can see the renewables in gas-fired assets account for roughly $$450 million or 68% of our free EBITDA. And you can also see that (inaudible) free EBITDA for renewables and gas-fired assets on a year-over-year basis and that's increased from $$347 million last year to $415 million this year, which is a 20% improvement.

So let me briefly return to our goals. We told you we would reposition our capital structure by completing between $$400 million to $$600 million of project level financing. Now we didn't close any project level financings during the quarter and you know that we did complete $$165 million in the first quarter of this year, which has contributed to our very strong liquidity position that you can see in our results. As Donald mentioned last quarter, the demand for project financing remains very strong and we continue to have a very solid set of potential qualifying assets.

I can tell you that I'm very confident based on the work that our team is doing that we'll meet our goal this year of closing $$400 million to $$600 million of project financings for 2016.

Now as many of you know in the near term, our key project regarding growth in our portfolio for our contracted gas and renewables assets is the completion and the commissioning of the South Hedland combined cycle project. The South Hedland project continues along at a pace that we'll have it operational in mid-2017, and expect to deliver against the financial and operational targets that we've set for it.

We've also been working this year on a number of contract extensions for gas assets. I believe that we will be successful here and you should hear more about this on upcoming calls. And also you know that we successfully extended our contract with our Akolkolex facility with BC Hydro to--for 30 years. We do continue to accept acquisitions that are building a good portfolio of greenfield projects here in Alberta. We've got two in another part of Canada and also in Australia, and we'll inform you of those projects once we meet both our (inaudible) hurdles and (inaudible) some more certainty.

So after Donald's comments, I'm going to close with some comments on our fourth goal. And with that, I will turn the call over to Donald for his comments on the quarter's performance and our progress in meeting our other goals.

Thank you, Dawn. As Dawn mentioned in her opening remarks, we had another solid quarter both financially and operationally. All of the businesses delivered better or similar results to last year. Our liquidity position continues to improve. The construction of South Hedland is on track and we're advancing our project financing initiative.

Slide eight provides the segmented operational results for the third quarter and year-to-date. For the year, our total EBITDA is up 14% to $$94 million, mostly due to significant improvement in Canadian coal, wind and solar, and energy marketing.

Taking a moment to highlight some of the business segment performance for the quarter, you can see that Canadian coal EBITDA came in at $$99 million, $$2 million lower than last year. Cost reduction and efficiency initiatives were offset by higher standard costs for coal resulting from heavy rains and unplanned outage at the mine. These conditions negatively impacted our coal production and coal quality in Q3.

The impact of this event has carried into the early part of the fourth quarter, but our mining operation group has developed a plan to recover a large part of the shortfall in production within the fourth quarter. Canadian coal availability was in line with prior year at 85% in the quarter, as compared to 86% in the same period in 2015.

Wind and solar provided $$9 million of additionally EBITDA during the quarter. This was due in large part to a $$5 million contribution from assets we acquired in the second half of 2015. The wind resources in eastern Canada were also better than the prior year, partially offsetting the low price for wind in Alberta.

Power price in Alberta settled at an average of $18 for the quarter, compared to $$26 per megawatt hour in the third quarter of last year. Year-to-date price has averaged $$17 per megawatt hour, compared to $$37 per megawatt hour in 2015.

Price did pickup slightly in September and October as a result of higher level of planned and unplanned outage in the province. However, we do not expect this price level to be sustainable. Our view is that when units return to service, price will return to the lower level that we witnessed earlier this year as the market remains oversupplied and PPA buyers are not bidding to maximize the value of their portfolio.

Consistent with prior quarter, our hedging program continued to effectively mitigate the impact of low price on Canadian coal, allowing us to achieve price in the range of $$50 to $$55 per megawatt hour this quarter on our uncontracted generation. Gas and hydro were not impacted materially by lower price and perform as expected given they are largely contracted. Even better, our hydro asset in Alberta generated additional margins during the quarter with the team actively managing our storage and taking advantage of the optionality of these assets.

Slide nine is an overview of our liquidity we have maintained since December 31, 2014. The average liquidity during this period was $$1.3 billion. Throughout the year, we have maintained our liquidity at $$1.5 billion and at the end of the quarter, our liquidity stands at $$1.7 billion.

We anticipate a high level of liquidity to be available at year end as we expect to complete project financing using some of our contracted assets. This increased flexibility will be of paramount importance as we enter a significant transitory period for the Company. We also need to complete construction of South Hedland and repay USD400 million of debt that is maturing in the second quarter of 2017.

As demonstrated at the bottom of the slide, we have consistently moved the mark on adjusted FFO to adjusted net debt. Our goal is to be at 20% FFO to debt in 2018 when South Hedland is online and contributing financially for a full year.

As for 2016 guidance, we are tracking to be well within the range we communicated for EBITDA. However, we believe our comparable FFO is likely to be at the lower end of the $$750 million to $$835 million range, as we expect our financing cost to be slightly higher. FFO also excludes change in unrealized mark-to-market gain that are including our EBITDA.

Finally, our sustaining capital will be lower than our guidance as we defer the rehabilitation of our water diversion project out to 2019 when the power price will support the investment. We also have deferred some capital at our Sarnia generating station to 2017, as the plan is not running as much as anticipated due to the low price environment in Ontario. Some of the reduction is also due to improvement in our capital efficiency and making sure we invest wisely in our portfolio. These actions will all contribute to us achieving our free cash flow target.

Before I return the call back to Dawn, I just want to note that we are still expecting a decision on the 2013 Keephills 1 force majeure dispute shortly. In Q4 of 2015, we adjusted our provision for the arbitration to 50%.

I will now hand the call back to Dawn for our closing remarks.

Okay. Thanks, Donald. Just--I mean you all know that we're continuing with our discussions with the provincial governments on compensation for the capital that is stranded under the proposed Climate Leadership Plan. Now, since we're working under a confidentiality agreement, there's nothing further that I can say on that matter. But I do have some other comments on the general environment that we're in and there's been a lot of it--announcements, since the last call.

Since we last talked to you, there has been lots of ongoing announcements about the federal government's approach to climate policies. This has included a proposed $$50 carbon price in the provinces by 2022, as well as potential infrastructure investments and support for introducing a new green energy investment. And as well you know that yesterday there were also announcements about the--some issues in the renewables markets here in Alberta.

All of these announcements must now be factored into how we think about future electricity investments here in Canada. And while the conversations around energy are changing frequently, one thing appears to be clear. Most of the proposed investments and taxes are intended for the longer term. And so, we do believe that in the short to medium term, our coal plants will be needed to power the Alberta system and support our economy. So given the changing natures of these conversations, we are very much focused on making sure that we have really built a lot of optionality into our investment planning as we go forward here in Alberta.

Now to this end, we are considering several choices to maximize the value of our fleet. We've talked to you about those in earlier quarters. But just to remind you, first of all, we can run the plants that we have today in the Alberta market on coal until 2030, and then we can convert them to gas to provide backup peaking to a market that will have more renewables. So that's an option. Another option we have is we can convert the coal plant to gas earlier at the end of their PPA period roughly in the 2020 timeframe. We have other options, including expanding our hydro, which are significant, and our wind operations, and then finally, we can add solar to fleet given the right kind of call from the ISO.

So converting the coal plants to gas either now being sort of that 2020 timeframe or in 2030 will depend on our--we very much believe will depend on our ability to work collaboratively not only with the provincial governments, but also with the federal government. Because we do need to have a framework that allows us to understand--that has certainty and clarity on emissions standards and carbon pricing as we go forward. That framework has to protect new investments and maintain the economic viability of our current plants.

We know that our plants are needed for at least the next 15 to 20 years. So we all know that Alberta is going to a 30% renewables standard by 2030. There is no way in Alberta to add renewables to the system without having several plants like ours to back them up. So Alberta must have several plants to provide low cost base load and backup power to ensure system reliability and to ensure the kind of pricing we need that will undermine our resilient economy. If we're going to continue operating these plants, our investors must see that new rules and regulations will allow for recovery of and a return on their capital.

Now, electricity and energy have always been at the heart of the economy here in Alberta. And we know that any changes must support our communities at a time where frankly jobs are critical to the provinces' families. As such we believe that governments have a strong incentive to work with us to ensure that a transition away from coal in this province is carefully managed.

So in our view, the Alberta coal fleet offers a unique transition opportunity. Why? Coal to gas conversions are low cost. These investments are only about 10% of the total cost of new combined cycle plants. And additionally, the investment return horizon for a converted unit is only 10 to 20 years. This is far shorter than the 30 to 40 years required to recover investments in new combined cycle gas plants. And since carbon based electricity will grow increasingly uncompetitive, using a shorter timeframe is the prudent choice to make for our investors.

We will continue to work towards the goal of achieving fair compensation for our stranded Alberta assets. But now we've had to add a second (inaudible). We must work with the provincial and the federal government to create a certain regulatory framework that supports investments in carbon fuel plants as backup from renewable. Transitions, as you know, are never easy and navigating a successful energy transition in Alberta and across Canada is both necessary and required.

Now, we believe the standard by which to measure a successful transition is grounded in our team of balanced wins. The decisions we make must--or the decisions we make must come from balancing the needs of our diverse operating stakeholders. And I said before that we know what these needs are. Our customers are clear that they want reliable and affordable power. Our investments want to be assured that their capital is safe and they will earn fair competitive returns on any investments whether they be in renewables or they be in gas or future investments in a coal plant.

And of course, our citizens and government want clean and cleaner energy and a strong sustainable economy. Now we believe that these views were echoed by Premier Notley's comments made during her State of the Province address a few weeks ago. And in particular, her statements on the Climate Leadership Plan were as follows. She said that we will be starting on a framework for a conversion later this fall, and then she also went on to say that as part of the government's plan, they will set out a program to provide coal emitters with some of the capital they need to close the plants and to invest in cleaner power production. And of course, they (inaudible) in Alberta. They also said that they will set out how proponents will be able to bid in Albert's market to help replace coal power generation, and I think that news came earlier this week as people talked about the set of new rules that are emerging for the renewables call that will come.

And then finally, they said that they will set out more details on how they will promote the construction of clean renewable energy, wind, solar, thermal, which of course includes gas, and hydro power efficiently, economically, and without undue subsidies. So based on those comments, we were pleased with the general direction being taken by the government, including the development of a framework as a provision of capital for converting some coal to cleaner forms of power production.

So we've always said that we recognize the need for change and the importance of making decisions that work for today and tomorrow. And of course, in 2000 when the Alberta system was transitioned from a regulated to a market based electricity system, we did learn an important lesson there as well. And that is that balanced always wins.

So in closing, the key takeaways from the call today are this. First, the first three quarters in 2016 we've had solid financial and operational performance and we've leveraged the Company's execution advantage very well. And I really want to thank all the employees that have just done amazing work and continue to do so as we go forward into 2017. Second, we're progressing on all of our 2016 goals and we don't see any place where we'd have to change--where we won't deliver a goal.

And then, finally the--transitioning the Alberta system off coal will require us to complete a fair compensation agreement--a fair coal compensation agreement with the provincial government. It will also require much greater certainty on the future path of carbon taxes and emissions standards for carbon-based plants to support the system. We will make sure that before we invest your money in carbon-based electricity here in Alberta, we will have a way to recover that capital with a return.

So with that, I'll return the call over to Jaeson for questions.

Thank you, Dawn. Zubane, we're now ready to move to the Q&A portion of today's call.

Thank you. (Operator Instructions) Rob Hope, Scotia Bank.

Yes, good morning. I was hoping you could comment on, I guess capital allocation, and how you think you will be competitive in the new renewable procurement framework.

So I'll talk about how we'll be competitive and then maybe you can just give me a little more on what you're looking for on capital allocation. As you know, we have TransAlta renewables. It's a very strong currency in the marketplace today. And it's got great capacity to add projects in it, just given its current capital structure. In Alberta, we have existing wind farms that are close to transition and would be very competitive in terms of expansion. So when we put those two things together, we believe we're one of the top competitors here for any of those projects that will be bid on in the upcoming call.

So just--can you just explain what you're thinking about in terms of capital allocation?

Maybe I'll just frame it this way. Just--or I'll maybe go in a bit of a different direction. Just in your comments, you did mention if you were going to invest capital, you'd have a clear line of sign on a return and of capital.

Right.

Does this allude to the fact that you will not be investing on a merchant basis and that you'd be looking for contracts for any capital?

Yes.

All right. That's helpful. Thank you.

Yes.

Linda Ezergailis, TD Securities.

Thank you. Just a follow-on question with respect to some of the changes that we're starting to see in the Alberta market. I'm wondering what sort of effect this most recent announcement on the renewable procurement process might have on the merchant markets and your legacy assets? And at what point in terms of these changes might you look to the government to provide certainty, not just on new investments, but on your legacy investments with a return on and of capital potentially type more fixed contract?

Yes, I think, Linda, that's hopefully--that's really what I was trying to say in my comments. I think, as you know and I know as we go forward, as more renewables come into the system, they have to be backed up with capacity from thermal in the short to medium term. And maybe over the longer term, you might see battery storage or things like that or even storage from our hydro facilities. And in the short term it's going to be backed up by thermal. In order for us to make investments in those thermal plants, we have to be able to get our capital back up.

So I do think as we move forward here in Alberta--as you know, we've got time. The market is fine here in the next couple of years. But as we move forward we have to some way of ensuring that investments that we make to backup the system are recoverable with a return.

Okay. And just further beyond your thermal for your wind assets, what might happen to pricing? How correlated do you think the wind resource might be in the province to maybe put additional downward pressure on pricing when your wind plants are actually generating? And do you know the government might compensate you for that if--.

--Yes--.

--All of this new power is coming on, on the wind side?

Well, I think the government has the stated objective of getting to 30% renewable. To do that I mean it's a combination on new and old, right? Alberta already has a significant number of renewables in system. And I think again as the market is evolving in order to go through this transition I can't see an outcome where you effectively hurt the old fleet in order to bring in the new fleet. So I do think there will be significant discussions with the ISO and the government on how to ensure that incumbent assets are not disadvantaged in this transition. And that includes our wind assets.

Great. Thank you.

Jeremy Rosenfield, Industrial Alliance Securities.

Thanks. I have a few questions here. Just to be clear--and let's go back on the coal compensation issue. The government has not indicated to you at this point in which direction exactly it would like to go. And you're still expecting to see something from the government by the end of this year.

So we have said all year that we thought it would take about a year to do this work. And I can't comment on just kind of what the discussions have been. But I can give you--I am pretty confident that we will have something done on that by the end of the year.

Okay. And there's a little bit of a disconnect that I'm seeing and I'm trying to understand. Do you still believe that the market structure itself will not change even though inherently obviously the contracts for renewables will be there? But do you think there could also be some kind of contract put into place from the government to support some of the existing thermal capacity as well?

Listen, I don't think I've ever said that I don't think the market structure will change here in Alberta. I think I have been pretty clear that I think it has to change as we go through this tradition. I do not see a way through the existing market structure to stay the same. So I believe the market structure will change. I think the market structure has to figure out how bring in renewables with the least amount of subsidy. And they have to account for all the incumbent assets that are here today, and has to assure that any of the assets that backup the system from renewables are profitable. So I don't expect the market structure to stay the same.

Okay. And then, maybe just clarify one other point in terms of how TransAlta and TransAlta renewables will be--would be approaching the new procurement process for renewable capacity. The goal is still I think--correct me if I'm wrong--to have TransAlta Corp do the development, be a developer of the assets. But ultimately, once an asset it reaches sort of a derisk state to potentially have TransAlta renewables become the owner of that asset or become the holder of the economic interest in that asset.

Yes, that's correct. We can--we haven't changed any of our views on that.

And keep in mind, like by clearly like building wind projects in Alberta in a market that we know on a site that we know very well is like it's probably not as risky as other forms of development.

Okay. Perfect. Great. That's it for moment. Thanks.

David Castagna, Raymond James.

Thanks. Hi, everyone. I just have one question, just kind of a higher level strategic one. How do you think about the potential--I would certainly agree that you are well positioned to go ahead with the renewables in Alberta. But I guess depending on how heavy the competition ends up being there, how do you weigh expansion there as opposed to potential further expansion in Australia? And do you still consider the U.S. wind market as something where you would consider expanding?

Yes. So going back to this sort of concept of capital allocation. The--any of the assets that we'd look at in Alberta would be held up against other projects that we are looking in our portfolio. So we--we're not going to just build in Alberta for the sake of building in Alberta. We do though have some pretty significant competitive advantages in Alberta just given the wind farms that we already have, the expansion capabilities we have, our knowledge of the regulatory market, and our ability to understand what pricing will look like in the future, because we have such a big fleet here.

So I think that the Alberta assets will compete favorably. But we continue to hold them up against returns that we see in other markets. And if the returns are better than the markets we would be going there.

Okay, great. Thank you. And just one other question, a pretty short one I think. Just the--I know the PPAs for the hydro assets in Alberta come up in 2020. Would you recontract those prior to the expiration, or would you--or would that be something that happens once they expire?

That's a really good question and a strategic question. I mean, it really depends on what the market structure looks like and sort of what the pricing is for different sorts of capacity and ancillary services. We are open to either keeping those uncontracted, because I see them more valuable today uncontracted than they are under the current PPA. But to the extent that there is a good contract extension, we'd be certainly--we'd certainly talk to the ISO about extending that.

Okay, great. Thank you. That's all I had.

Andrew Kuske, Credit Suisse.

Thank you. Good morning. I guess the question focuses on Alberta. And it's just how you are approaching just a simple supply-demand modeling analysis of the market just given the uncertainty that exists? I mean, obviously this is straight forward. You can still do the supply-demand. But when you look out into the future just because of the government uncertainty, how do you factor that into your analytics?

Well, Andrew, you know that my background is economics. So this is like kind of the finest thing we've ever done at TransAlta for me. And my team is all cringing. So we model the market 20 different ways. We have modeled in the current market structure, we modeled in this--there could be a capacity market, and we're modeling CFD markets. We're making up all sorts of ways that you could do the market here. All with the--all looking at how do you ensure that you get the right investment return to attract capital. And then how do you ensure that customers at the end of the day pay the lowest price.

We're really committed to an Alberta market that delivers the lowest price in a future where carbon is going to be priced. So we've moved away from just modeling using the energy only market to a lot of scenario analysis. So that really helps inform our investment decision making.

Okay. That's helpful. And then, when you take a look at your scenario analysis, what really winds up being your preferred outcomes in Alberta for TransAlta? And then, how do you parallel that with other jurisdictions where you either have capital in place or look to allocate capital into the future?

Yes, I always come back to a general principle, which is that the services that are being provided by the generator need to be priced. And so, to the extent that over time, not in the short term, because you know Alberta today is mostly provided by base load--supply is provided by base load coal. But over time, as you said, there's more renewables into the system. The--all the generators are going to have to provide more backup and more peaking and more capacity. So a lot of market structures work as long as they give the right price signal to capacity, so that capacity will be built to back up the system.

Very helpful. Thank you.

Robert Kwan, RBC Capital Markets.

Good morning. Dawn, I guess since you were talking about all the different things that the government has put out around what they could be announcing by year end, I'm just wondering, is it your expectation that what they will announce will be really kind of a final framework? Or do you expect them to put forward a framework for further consultation?

Oh, I believe it's next to impossible for any government to put forward a final framework that would give a lot of certainty. But I do think that they will give good signals in terms of the kind of frameworks that they're testing. And then, I do think there will be a lot of consultation and a lot of discussion here in Alberta over the next year or even two.

So I think it's a [gain]. I want to reiterate, we have PPAs. You've seen the performance of the Company. We are--we've really made sure that we solidified the amount of money that we can make here in the market while we're under the PPAs and while we have the current market structure. So we're fine with that. We think that's the right thing to do.

I personally believe and I've said this before, you've got to take a lot of time here if you want to have a really good marketplace. We've--I was just in Germany last week. I can tell you they have blown up every market worldwide by not really considering the implications of this transition towards renewables. So I think the framework will be there. But the kind of discussion that will make the framework work will take some time.

Okay, that's great. And if I can just turn to the Alberta coal fleet, and I have a few fairly small questions. Your nudge down availability for the year. I'm just wondering what's behind that. We've seen a lot of units kind of coming on and offline. And if you can just add some color as to what the driver is and whether that's ongoing.

Yes, I think--well, they had--we had a big fight in the mine rights in the days of [one thousand and one] (inaudible). And so they've been struggling on two fronts. One is some--just struggling with getting that mine so they can get the production out of it. They have a light amount of production, but there's a lot of work that they've been doing there. The kind--as a result of that, we're using a lot of coal in the pile. The coal in the pile has always been in the pile for a long time. So they're ending up with quite a bit of a capacity issue.

So I think it's really just trying to get through that event back to more of a normal period. And of course, as you know, (inaudible) units, we--we're not maintaining those plants any more than we have to under the terms of the PPA because of the life of those plants. So we'd expect to see a different kind of availability going forward with some of those older plants.

Got it. And actually, Dawn, since you mentioned kind of the coal in the mine floods maybe I'll transition the second question there. You're looking at coal costs, I think, in Alberta actually going down a little bit more than what you'd previously guided. So with the weather and the lower availability, usually that's bad for standard costing. So I'm just kind of wondering what's the driver there. Are you going to really ramp up inventory in Q4 to amortize it all?

Well, Donald said in his--the coal team is working on a production plan for Q4 so that they can keep the standard cost lower. So we'll see how they do. They certainly have a pretty good plan, but there's some risk in that for sure if they go through Q4.

But Dawn is the plan largely centered around just building a bunch of inventory to kind of amortize the fixed costs over that amount of production?

Like we also--like we have a mine plan that basically is over multiple years, Robert. And we have some equipment--planned equipment maintenance next year. So we're also building like some inventory, so we can go over that period as well. So it's not basically building inventory to reduce the standard cost. It's basically like a long term mining plan that we're trying to stick with at this point.

Got it. Okay. And then, just the last question. I've got--there has been all this talk around all the carbon plans, whether it's federally or provincially. I'm actually just wondering if gas is still an issue?

Yes. I don't think I've thought about it from the six months. No, I don't think so. I mean, the reality is that, it just would make zero sense to put any capital investments into coal plants. So as we've been building our scenarios here, certainly all of our scenarios are to use existing credits that we've built up as opposed to put new equipment into the plants.

Okay. I understand the first part and the use of the credits. But I think there was also physical compliance rule at some point?

Yes, that's what I'm saying, that requires capital. So you--yes?

So it doesn't make sense--sorry, go ahead, Dawn.

Yes. So it doesn't make sense to put in cap expenditure. So many of our scenarios are trying to figure out how to optimize the portfolio and not have to spend that money.

Got it. So by optimize, you're talking about essentially just having to shut stuff down earlier there?

No, there's lots of options, which I talked about in my speech. We can convert plants to gas. We can--we can always shutdown plants and we can keep them running on coal. So we have a number of scenarios that have a number of different outcomes in them.

Got it. Again, that's very helpful--.

--It all depends on how solid and certainly the framework is, as we go forward.

Okay, that's great. Thank you very much.

Robert Catellier, CIBC World Markets.

Good morning. I was wondering if--just on the Alberta restructuring the market there. I mean, there's--you've said you've a lot of modeling, et cetera, and looked at it a lot of different ways. But do you think there's one sort of restructuring framework that best suits TransAlta's assets?

No, actually we've been surprised. When you do the actual detailed modeling, there are a number of different structures that will work. And again, remember, the criteria we've put in front of ourselves is keeping prices low for consumers ensuring that the assets in not just TransAlta's sleeve, but the other incumbents as well here in the province are to get returns and then also this shift to renewable.

So I've been surprised actually at the number of different ways that you can do it. And I think going back to an earlier question about a framework versus a very detailed assessment of which way to go. I think, as long as the framework recognizes that the thermal backup has to earn a return to provide the capacity for the system, and it also recognizes that over time--I do believe that over time carbon-based fuels are going to be used less and less and there'll be more innovations. As long as the framework has those attributes in it, I think there's a number of frameworks that work. So I don't have any one that I would say, we've got to go here, we've got to go there. I'm just pretty sure that the one that we have today is not going to work.

Okay. So just thinking aloud here, there's obviously a conflict between wanting to keep prices low and reducing the exposure that government has under a contract for differences. Do you think they have to change the rules on how renewables can bid into the market under a revised market structure? In other words, you can't create an incentive where they push the stack down and the government ends up with a huge bill for the contract for differences like we've seen in Ontario.

Yes, I mean, those are all things it have to be considered in the dialogue as we go forward.

Do you get any sense that that's a major part of the dialogue that will actually get to a position where the renewables can't be bid in--disadvantage--in a way that disadvantages the existing fleet, whether it's coal or renewable?

I mean, it would take a long time to have that discussion here on this call. I can honestly say, I don't know how that will come out. But I do think that, I think there's good recognition of all the stakeholders here in the provinces, including ISO and the government of what all the factors are that need to be considered. So going back to my comment on balance (inaudible), all of this has to be balanced as we go forward.

Okay. I'll try just one last time and then that will be it. But how can a contract for differences market work without changing the way renewables bid in? But is it possible to achieve the objectives without changing the way renewables bid into the market in your opinion?

I've seen two market structures--I've seen several market structures where contract for differences either changes the bidding behavior or it doesn't. So I think there's--I think it can work either way.

Okay. Thank you.

Mitchell Moss, Lord Abbett.

Hi. A couple of questions. You mentioned higher financing costs, is that just financing costs for related to expected project level financing?

Like it's a two-fold. Like so we're clearly like raising money ahead of time. So we're doing project managing and putting cash in a bank account in anticipation of 2017 construction of South Hedland and refinancing. We also had a little bit of like a step-up in our financing costs because of the Moody's downgrade last year like marginal. But like that also had like a small impact on our financing cost this year. But it's mostly due to us basically raising cash ahead of time and having like a negative carry on that cash currently.

Okay. But the coupon on the project financing related to South Hedland isn't necessarily higher. It's just that you did a financing sooner.

Exactly. Like, in fact, like it would be like a cheaper rate. But it's just like the timing of us raising the money now versus in 2017.

Okay. And regarding the comments around coal-to-gas conversion, how much--if the 2020 timeframe were to play out as to a need for some of those facilities to run on gas, how much lead time would you need and what steps are you taking now to potentially have some plants be converted to gas in the 2020, 2021 timeframe?

Yes, I mean, the lead time is about now, right? We--and this is part of the work that we're having to do here in the province is getting some clarity, because the more clarity we have the more likely we can make decisions that will get us there by 2020, 2021. The biggest roadblock to that is a gas pipeline, which would need about three years. So that is the kind of work that has to be done if that was to be one of the scenarios that we pursue.

Okay. So the gas pipeline is two years, but--and in terms of the actual engineering of the fuel switch, do you need to take significant steps now as well?

That is actually not that big a deal. That can be done on an extended outage.

Okay.

And engineering on that is not complex.

Great. Thank you very much.

Ben Pham, BMO Capital Markets.

Thanks. Good morning. On R&W, I was just wondering does the recent run up in the stock to that perhaps--how far your decision would drop down to perhaps sound on a portion of your interest.

No. Like it's clearly good. It's a strong currency. So if we decide to use it like it's available, but like no way, like it doesn't create an incentive for us to basically move forward with those strategies.

Even the dropdowns?

Well, like we will likely do featured dropdown, but it will not be driven by the current stock price. We will do the dropdown when it's appropriate for TransAlta to do a dropdown, because we need to pull money from R&W to TransAlta. But like it's not something that we're contemplating at this point.

I mean, in terms of priorities, currency is really--positions us well on the growth side.

And is the hydro fleet still in that potential bucket of dropdowns for you guys?

Like it will be there. But like as we discussed earlier, like the contract is expiring in 2020. We don't know what would be the market in Alberta past 2020. So as soon as we have more visibility on this one, we can like draw better plans. But for now, it's very challenging to value that asset to drop it down into R&W. So that's why like it's kind of like on hold for now.

Okay. And on the coal transition, can you comment on the potential outcomes on compensation--a proposal that you or others may have put in front of Boston and even leading up to a final decision that's coming out by year-end?

No, we cannot.

Okay. And then, on the Canadian coal, there's commentary about curtailments to the PPA buyers. Is that referring to the balancing pool there basically instead of buying cheap spots they're still dispatching and paying a higher PPA contract price?

That's exactly the case. So like, normally, we--when prices are low we see PPA buyers taking the units offline, or it's like, part of the unit offline. The balancing pool currently is dispatching the unit at basically marginal cost and the units are running more than what we're expecting in that oil price environment and that's a bit of a negative for us.

Okay. And then--can you just clarify the hydro? You talked about some water management flexibility. I just want to refresh my knowledge, so--I mean, I thought most of them were--most of your fleets there run upriver. Is there some reconfiguration or is that some other asset that's driving that?

I mean, they are run upriver. But we also have storage and we use that storage all the time, and in fact that's why we have good capacity out of those facilities.

The North Saskatchewan system has like significant storage at Brussels and Bighorn. That's what you think.

Okay. All right. Thanks. Thanks for taking my questions.

Rob Hope, Scotia Bank.

Yes. Thanks for taking another follow-up. Maybe moving over to Washington. Do you have any comments on the state ballot initiative that could see additional carbon costs be put on Centralia?

No, we just--we'll just--we're just like you. We're just going to wait and see what happens there.

So your existing framework where you're shutting down the units wouldn't add some sort of shield to this potential?

As Dawn said, (inaudible) we're watching the matter closely. We're waiting to see what the outcome of the vote is going to be next week. And we're looking at what the potential implications are, but we're not in the position right now where we can speculate to be honest.

All right. That's it. That's helpful. Thank you.

This concludes the analyst question-and-answer portion of today's call. We will now take questions from members of the media. (Operator Instructions) Jeff Lewis, The Globe and Mail.

Hi. Thanks for taking my question. Dawn, can you just clarify what it is that you'd like to see from the Alberta government and perhaps the federal government in terms of assurances as you look to transition the coal fleet to perhaps gas peaking plants? And in terms of, I guess, just financial assurances, you mentioned a couple times, you need to see a return profile that make sense and allows you to get your capital back. And then, I have a follow-up. Thanks.

Okay. I'll start and then I'm going to ask John to--because he's been working on this pretty extensively. So first of all, in order to run our units on gas, we do need a regulatory framework over a longer period of time sort of in that 15-year type timeframe for our subcritical plants and 25 for our super critical plants. As you know, they are brand new. So we do need a performance standard.

So we need to know that we can--we have the right performance standard that we can operate those plants within and that's in the jurisdiction of the federal government. We also believe that to make those investments--to make investments in carbon based fuels just given the uncertainty about where carbon tax could go, that we need to be able to get some sort of assurances on what the carbon taxes will be over the timeframe of the investment.

As you can imagine, anybody investing in new thermal plants, electricity products, that have carbon in them in this environment really has to know whether or not in the future there would be an upset in their return because of a carbon tax and particularly people like ourselves would want some of those assurances. So we need that as well as part of what we're doing. And--is there anything else? I think it's really those two key things, but I will let John add some comments.

Yes. I don't--I think Dawn covered it well. I think the two things that she said would be one making sure that the emission standards that would be set by the federal government and provincial government would be appropriate to permit the conversion of the coals units to gas units. There are significant emissions reductions by doing that--the emissions actually go down by almost half in terms of greenhouse gas emissions so that's one.

And the other one as Dawn alluded to would be, it would be helpful to us to understand kind of the forward trajectory of what carbon pricing might be and what the performance standard would be. So we have a bit of a sense of what the economics would be for the units that we would be considering to do the conversion. So it's really the two elements are really oriented towards giving us elements of certainty to permit us to move forward.

Do you mean prices beyond that $$50 per ton that's been outlined in the federal government plan?

Yes. Because--yes, remember these are long--even though these are more like 15-year investments instead of 30-year on combined cycles, there's still 15 years to recover the capital for investors. So they need a pass in order to make that investment or they need some certainty on that. They can't--it's not--the risk is too big because the input cost is too high as a percentage of volume per cost.

So for example, if you do a conversion in 2020 or 2021 as Dawn alluded to and the carbon price is scheduled to go under the federal rules to $$50 in 2022, there's still 15 years or so that you would need to run. So having a bit of a sense of what the pricing would be as an input cost on a go forward basis is an important consideration for us.

Okay. And then, secondly, just on the renewable announcement that was made yesterday by the Alberta government, are those financial incentives enough for you to consider new capacity?

Yes.

Okay. So you're pleased with those?

I think we projected that was the way you'd have to go in order to get investors behind those kinds of projects. So I think to the extent that--I think that those kinds of instruments will create the most competition, the lowest cost of capital and potentially the lowest subsidy on renewables.

Okay. Thanks.

(Operator Instructions) Chris Varcoe, Calgary Herald.

Hi. Thanks for taking my call. Dawn, potentially how many of your existing coal plants are you looking at the potential for conversion to gas? And what would you expect the range of these capital costs to be?

Well, just to qualify, remember we need the right framework to do it, so the right regulatory framework and certainty and clarity in that to be able to do that. But we're running scenarios that would have all of them, some of them, one or two of them. So it really depends on what the market looks like here and what the incentives are for incenting us to provide capacity to the system. So at this point, we wouldn't have an answer to that. We just--we are just running different scenarios as we have--think about what's going on in this environment.

In terms of the cost, it's not a very expensive endeavor, it's about $$125 a kilowatt year for coal conversion compared to, let's say, a brand new combined-cycle plant can be somewhere between--anywhere between $$1,500 to $$2,000 in the Alberta market depending on when you're doing the construction. So it's a very--it's one-tenth of the cost.

And just to follow-up on the question about the renewables. Given that the government's going to be bringing in these new renewable contracts as contracts for differences, will you be seeking the same kind of subsidies, the same kind of contract for differences for the existing renewables that you have in the province?

Yes. We just got that information yesterday. For sure, the existing renewables cannot be disadvantaged by new renewables being brought into the province. So there'll be lots of discussions on how to do that. There's currently renewable credits that go to the existing projects. So I think to the extent that they continue that can service that, but there's a lot of work to do before we get any real certainty or clarity around that.

Thank you.

There are no more questions at this time and this concludes today's conference call. You may now disconnect your lines. I want to thank you everybody for participating and have a pleasant day.