TransAlta Corporation (TAC) Q3 2016 Earnings Report, Transcript and Summary

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. As a reminder, all participants are in listen-only mode and the conference is being recorded. After the presentation, there will be an opportunity to ask questions. [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 are in Canadian currency, unless otherwise stated. The non-IFRS terminology used, including comparable gross margin, comparable EBITDA, comparable funds from operations, comparable free cash flow, and comparable earnings are reconciled in the MD&A. On today's call, Dawn and Donald will review the 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 it usually mean I’m going to lose my voice in about the next half-and-a-half. So I apologize, if a bit hard to understand and we do have backup in the room. So lots to today you on today. Today, I’m going to provide you some thoughts on our quarter and take away 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 are meeting – we – the progress that we are making as we meet our 2016 goals. Now just to remind you, our 2016 goals were to achieve our operational and financial and safety targets and I think we’re doing a great job there. To reposition our capital structure, we grow our portfolio, contracted GAAP and renewalable assets and then finally secure unusually beneficial core transition arrangement 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 goal 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 5, which is on the screen now, you can see that we 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 results of positive contributions from the renewable assets that we acquired in the second half of 2015, solid performance from our gas and renewals portfolios and cost reduction initiatives across the fleet that we implemented in 2015. The last metric adjusted availability measures operational performance across our fleet and it’s particularly important in our Alberta coal fleet for units that are under long-term PPA contracts. Thus far in 2016 our adjusted availability is up to 89.3%, which is also an improvement over 2015. As of for me, all of these metrics together clearly demonstrates that we’re continuing to build our execution advantage here at TransAlta, which was one of our strategic themes that we introduce 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 6 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 fleet. This is important because I want you to see how our performance is increasingly less impacted by the returns in our coal fleet. As our Chairman noted on our AGM, our transition to becoming a clean energy company is well underway. Slide 6 shows that our free EBITDA for the year is $608 million and here you can see that renewable and gas-fired assets accounts for roughly $415 million or 68% of our free EBITDA. And you can also see that our free EBITDA for renewables and gas-fired assets on a year-over-year basis and that increased from $347 million last year to $450 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 financing during the quarter and you know that we did complete $155 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 will meet our goal this year closing $4,600 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 renewable assets is the completion and the re-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 us. We’ve also been working this year in 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 that we successfully extended our contract with our Akolkolex facility with BC Hydro 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 [indiscernible] hurdles and maybe some more certain. 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 business delivered better or similar results to last year. Our liquidity position continue to improve. The construction of South Hedland is on track and we’re advancing our project financing initiative. Slide 8, provide 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 cost for coal resulting from heavy rains and unplanned orders at the mine. These condition negatively impact 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 asset we acquired in the second half of 2015. The wind resource in eastern Canada were also better than the prior year partially offsetting 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 have 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 orders 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 remain oversupplied and PPA buyers are not bidding to maximize the value of their portfolio. Consistent with prior quarter, our edging 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 9 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 important as we enter a significant transitory period for the company. We also need to complete construction of South Hedland and repay U.S. [indiscernible] 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 exclude 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. 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 we’ve said a lot of it, you know, announcements since the last call. Since we’ve last talked to you, there has been lots of ongoing announcements about the federal government's approach to climate policy. This is including 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 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 renewable. So that's an option. Another option we have is we can convert the coal plant to gas earlier as we ended their PPA period roughly in a 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 cost from the ISO. So converting the coal plants to gas either now, now being sort of that 2020 timeframe or in 2030 will depend on our – very much fully 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 emission standards and covered pricing as we go forward. That framework has to protect new investments and maintain the economic viability of our current plan. 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% renewable 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 cover 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 and such we believe that governments have joined hands to work with us to ensure that a transition away from coal in its 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 converted unit is only 10 years to 20 years. This is far shorter than a 30-year to 40-year required to a cover investment in new combined cycle gas plant. Carbon based electricity will grow increasingly uncompetitive moving our shorter timeframe is the prudent choice to make for our investments. We will continue to work towards the goal of achieving fair compensation for our stranded Alberta assets. But now we have to add a second [indiscernible]. We must work with the provincial and the federal government to create a certain regulatory framework that supports investments in carbon fuel plant 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 founded in our team of balanced win, the decisions we make must talk about to 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 arrival and affordable powers, our investments want to be assured that their capital is safe and they will earn fair competitive trends on any investments led us to the end renewable or they be in gas and oil future investments in our coal plants. And of course, as soon as the government wants clean and cleaner energy and a strong sustainable economy. Now we believe that these views were echoed by [indiscernible] comments made during her state of the province addressed a few weeks ago. And in particular, her statements on the climate leadership plan was as follows. She said that we will be selling on a framework for a conversion later this fall, and then she also went on to say that it’s 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 who invest in clean power production, of course, they done in Alberta. They also said that they will set out our performance will be able to get in Alberta’s market on how to place that coal fired generation, and I think that news came earlier this week as people talked about the seven new roles that are emerging for the renewable 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 and thermal, which of course includes gas and hydro power, especially 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 funds 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, till 2000 when the Alberta’s system would transition from a regulated to a market based on a [indiscernible] system, we did learn an important lesson there as well and that balance always been. So in closing, the key takeaways from the call today are this. First, for 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 an 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 price revenue we have to change where we won’t deliver at all. And then finally, transitioning the Alberta system off coals will require us to complete a fair compensation agreement, I’m sorry, a fair coal compensation agreement with the provincial government. We will also require much greater certainty on the future pass of carbon taxes and emission standard for carbon-based plant 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 rate to cover that capital within returns. 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. Ladies and gentlemen, we will now begin the analysts question-and-answer session. [Operator Instructions] Thank you. Our first question comes from Rob Hope from Scotia Bank. Please go ahead.

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 will 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 [indiscernible], it’s a very, 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 we’d be very, 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 calls. Donald, can you just explain what you’re thinking about in terms of capital allocation?

Maybe I'll just frame it this way. Just maybe do 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 sight on a return of capital. 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.

Our next question comes from Linda Ezergailis from TD Securities. Please go ahead.

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 about 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 enough 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. So I think, as you know and I know as we go forward as more renewable transits system, they have to be backed up with capacity for thermal in the short to medium-term and maybe over the longer-term, you might see that resource and things like that or even resource from our hydro facilities. And in the short-term it's going to be backed up by thermal in order for us to make investment in those thermal plants, we have to be able to get our capital back out. So I do think as we move forward here in Alberta, I do know we got time to market it’s fine here and then couple of years but as we move forward we have to some way of ensuring that investments that we make to backup this one and recover capital 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 the wind side?

Well, I think the government have the stated objective of to 30% renewable. To do that I mean it’s a combination on new and old dolerite. Alberta already has 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 I feel and a government on how to make sure that incoming assets are not disadvantaged in this transition and that includes our wind assets.

Great. Thank you.

The next question comes from Jeremy Rosenfield from Industrial Alliance Securities. Please go ahead.

Thanks. I have got few questions here. Just to be clear and let’s go back on the core compensation issue. The government had not indicated to you at this point, in which direction exactly you would like to do and you’re 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 selective of look at efficiency been but I can’t give you I’m 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 I’m trying to understand. Do you still believe that the market structure itself will not change even thought inherently and inherently obviously the contracts for renewable 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 – that I think they have to change as we go through this transition I do not see a way through dignity market structure the same, same slide I believe the market structure will change. I think the market structure has to figure out how bring in renewable with versus the region out of subsidy. And how to account for all those incumbent assets that are here today, and how to assure that any of the assets that backup the system from renewable are profitable. So I don’t expect the market structure stay the same.

Okay. And then maybe just cover by one other point in terms of how TransAlta and TransAlta renewables renewable 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 due to development the developer of the assets, but ultimately once an asset it reaches sort of a due risk state so potentially how TransAlta renewable become the owner of that asset or become as a holder of the economic interest in that asset?

Yes, that’s correct we haven’t changed any of our views on that.

And keep in mind, live the like really like building wind project in Alberta in the market that we know on site that we know very well is like it’s probably not as risky as other form of development.

Okay. Perfect, great. That’s it for moment. Thanks.

The next question comes from David Castagna from Raymond James. Please go ahead.

Thanks, hi everyone. I just have one question just kind of a high level strategic one, how do you think about the potential I was sure I would certainly agree that you are well positioned to go ahead with renewable in Alberta. But I guess depending on how heavy their competition and then 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 could consider expanding?

Yes, it’s a great advise it’s sort of consent of capital allocation. The any of the asset that we look back we look at in Alberta would be how up against projects that we’re looking in our portfolio. So we don’t – we’re not going to just build in Alberta so we think of building in Alberta. We do now have some pretty significant competitive advantages in Alberta just given wind power that we already have. The expansion capabilities we have acknowledging the regulatory market and our ability to understand what pricing will look like in the future, because we have such a big future. 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 in other markets we would be going there.

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

That’s a really good question strategic question. I mean, it really depends on what the market structure looks like and sort of what the price signals are for different fronts of capacity and services. We’re open to either keeping those untapped contract, it is frankly more valuable today uncontracted than they are under the current PPA, but to the extent that there is a good contract extension, we’ll be certainly – we’d certainly talk to the ISO [ph] about extending that.

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

The next question comes from Andrew Kuske from Credit Suisse. Please go ahead.

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

Well, Andrew, you know that my background is economics, so this is like one of the finest thing we’ve ever done at TransAlta for me and my team currently. So we model the market in 20 different ways. We have modeled in the current market structure, we model as if there could be a capacity market, we’re modeling CFD markets, we’re making up all sorts of ways that you could do think the market here, all would see – all looking at how do you ensure that you get the right invest return to attract capital and then how do you ensure that customers at the end of the day pay the lowest price. Since we are really committed to Alberta market that deliver the lowest price in a future where carbon is going to 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 ones that 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?

Yeah, I always – 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 and coal, but over time as you – as you said, there are more renewable 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 structure 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.

The next question comes from Robert Kwan from RBC Capital Markets. Please go ahead.

Good morning. Dawn, I guess, as you are 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 didn’t actually talk about for any governments to put forward a final framework that would give a lot of certainty. But I do think that they would give good signals in terms of the kind of framework 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 really make 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 said this before, he's got to take a lot of time here, if you want to have a really good marketplace. We – 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 the transition towards renewable. So I think the framework will be there. But the kind of discussion that will make to framework for us 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. Just wondering what’s behind that we've seen a lot of units kind of coming on and off line and if you can just have some color as to what the driver is and whether that's ongoing?

Yes, I think, while we had a big fight in the mine in the [indiscernible]. So they've been struggling on two fronts. One is struggling with getting that mine, so we can get a 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 under the pile – the coal in the pile was what it’s been in the pile for long time. So ending up with quite a bit of a capacity issue. So I think it's really just trying to get through that get back to more of a normal period. And of course, as you know, our met units one and two, 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 really expect to see a different kind of availability going forward with some of the 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 in 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 at all?

Well, Donald said in his – the coal team is working on a production plant 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 a some, not for sure, if they go to the Q4.

But, Don, 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 year, 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, is 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, I – the reality is that, it just would make $0.00 to put any capital investments into coal mine. 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 – put them into the plant.

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

Yes, that's what I’m saying, that 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 how to spend that money.

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

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

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.

The next question comes from Robert Catellier from CIBC World Markets. Please go ahead.

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

Actually we've been surprised. When you do the actually detailed modeling, there are a number of different structure 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 sees, but the other incumbents as well here at the province are to get returns and then also the 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 the thermal backup has to earn a return to provide the capital for [indiscernible] and it also recognizes that over time – I do believe that over time, carbon-based fuels are going to less and less and there’ll be more in addition. As long as the framework has those attribute centers, I think there’s a number of frameworks that were – so I don't have anyone 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 day is not going to work.

Okay. So just to get a loud here, there's obviously a conflict between wanting to keep prices low and reducing the exposure that government has under contracts for differences. Do you think they have to change the rules on how renewables convert into the market under a revised market structure? In other words, you can create incentive, where they push the stack down and the government ends up with a huge bill for the contract for differences like we see in Ontario?

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

Can you give me any sense that that's a major part of the dialogue that will actually get to a position, where the renewable [indiscernible] disadvantage in a way that is – measures the existing fleet, whether it’s coal or r 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, it’s a good recognition of all the stakeholders here in the provinces, including ISO [ph] and the government of what all the factors are that need to be considered. So going back to my comment on the announcement, all of it has to be balanced as we go forward.

Okay. I'll try just one last time and then that will be it. How can a contract for differences market work without changing the way renewable. But is it possible to do objections without changing the way renewable has been in the market in your opinion?

I think two, the market structure is, look, I think the market is where contact for differences either changes the bidding behavior or dozens. So I think there’s – I think it can work all the way.

Okay. Thank you.

The next question comes from Mitchell Moss from Lord Abbett. Please go ahead.

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 refinancing. We also had a little bit of like a step up in our financing costs because of the Moody's downgraded 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 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 is it 2020 timeframe will move 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 you’re taking now to potentially have some plants be converted to gas in the 2020, 2021 one-time frame?

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 who is getting some clarity – some more clarity we have the more likely, we can make positions 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 done if that was to be one of the similar that we push forward?

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 bigger deal. That can be done on an extended outage.

Okay.

And engineering on that is not comfort.

Great. Thank you very much.

The next question comes from Ben Pham from BMO Capital Markets. Please go ahead.

Thanks. Good morning. On [indiscernible] I was just wondering does the recent run up in the stock to that perhaps, how far your decision would crop downs or perhaps sound on a portion of your interest?

Nope. Like it’s a 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 strategy.

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 drive dropdown, because we need to pull many from [indiscernible] 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 dropdown 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 then we can like draw better plan. But for now it's very challenging to value that assets to drop it down into our integral use. So that's why like it kind of like on hold for now.

Okay. And on the core transition, can you comment on the potential outcomes on compensation a proposal that you’re – others may have put in front of Boston and even leading up to 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 spot there, 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 buyer taking the unit offline or, it’s like, part of the unit offline. The balancing currently is dispatching the unit at basically marginal cost and the unit are running more than quite 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 [indiscernible], 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 you have fleets running forever, is there some reconfiguration or is that some other assets that’s driving that?

I mean, they’re running riverbed, but we also have surge in [indiscernible] that surge all the time and in fact that’s why we have good capacity out of those facilities.

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

Okay. All right thanks. Tanks for taking my questions.

The next question comes from Rob Hope from Scotia Bank. Please go ahead.

Yes, thanks for taking another follow-up. May be moving over to Washington, do you have any comments on the state developed initiative that could see additional carbon costs be put on Centralia?

No, we just – we’ll just – 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, [indiscernible] 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] First media question comes from Jeff Lewis from The Globe and Mail. Please go ahead.

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 sub-critical 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 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 investment 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 carbon tax and particular people like ourself 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.

Yes, because – yeah, remember these are long – even though these are more like 15-year investments instead 30-year on combined cycle, there’s still 15 years to recover the capital for investors. So they need a pact in order to make an investment or they need some certainty on that as they can’t – it’s not – the risk is too big because the input costs 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 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 that was the way you’d have to go in order get investors behind those kinds of project. So I think to the extent that, I think, that those kinds of instruments will create the most competition [audio dip] capital and potentially the lowest subsidy on renewable.

Okay. Thanks.

[Operator Instructions] The next question comes from Chris Varcoe from the Calgary Herald. Please go ahead.

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 cost 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 them, one or two of them. So it really depends on what the market looks like here and what the incentives are for 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 a 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?

Yeah, we just got that information yesterday. For sure the existing renewables cannot be disadvantage 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 serve that, but there’s a lots 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.