TransAlta Corp (TAC) 2017 Q1 法說會逐字稿

Good morning. My name is Dan, and I will be your conference operator today. At this time, I would like to welcome everyone to the TransAlta Corporation First Quarter 2017 Results Conference Call. (Operator Instructions)

Jaeson Jaman, you may begin your conference.

Thank you, operator. Good morning, and welcome to the TransAlta First Quarter 2017 Conference Call. My name is Jaeson Jaman, Manager of Investor Relations. With me today are Dawn Farrell, President and Chief Executive Officer; Donald Tremblay, Chief Financial Officer; John Kousinioris, Chief Legal and Compliance Officer; Brent Ward, Managing Director and Treasurer.

The call today is webcast, and I invite those listening on the phone lines to view the supporting slides, which are available on our website. A replay of the call will be available later today, and the transcripts will be posted to our website shortly thereafter.

All information provided during this conference call is subject to the forward-looking qualifications which are 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, EBITDA, funds from operations, free cash flow and comparable earnings are reconciled in the MD&A.

On today's call, Dawn and Donald will review the first quarter results and discuss programs -- progress made against TransAlta's goals and priorities for 2017. After these prepared remarks, we will open the call for questions.

With that, let me turn the call over to Dawn.

Thanks, Jaeson, and welcome, everyone. Lots to talk about today. And really a lot has happened in the last 6 months, and we feel this is the right time to do a bit of what we call a reset call.

Today's call has many more details on our near-term growth opportunities, our accelerated plan for coal-to-gas conversions, and our bridge to the $400 million of free cash flow from where we are today.

I'd like to start just with a bit of my assessment of the quarter. And as you can see from the highlights on the slide, our EBITDA, FFO and free cash flow were either in line with last year or were exceeded. However, as with many things in life, the devil is in the details. So while Donald's detailed comments will help you understand the quarter's performance, what I do want to be clear about is that I remain very confident that we're well on track to achieving our 2017 guidance.

I do want to take a bit of a moment, though, to discuss one aspect of our operational performance, and that's our adjusted availability from our coal fleet, which fell to 84.5% from the 90.1% last year. Lower availability was due in part to a higher level of unplanned outages that we experienced in our Alberta coal fleet in January. And additionally, we did have an unplanned outage in January in Centralia on Unit 1 that was caused by the failure of an exciter. So when we came out of the gate, January was a bit of a tough month.

But as you all know, power prices in both Alberta and the Pacific Northwest are extremely low, and the financial impacts of this reduced availability was minimal. Now since January, availability has returned to normal levels, as we expected. And we do expect that the full year availability will come in publicly more towards the low end of our guided range. And in the coal fleet, that's 86% to 88%. But given the outlook for prices, we see the financial impact of that lower end availability in that coal fleet to be quite minimal.

Now I'd like to also highlight a few areas on our financial strengths that we've developed. And you're going to hear more about this today as Donald takes you through the details. But first, I'd like to point out that we have doubled our liquidity from March of 2015 by more than $1 billion in just 2 years. We do have $500 million of cash in the bank, which will position us to pay off our 2017 maturities, and Donald will talk about that.

We have made impressive strides on improving our key financial ratios. Our FFO to net debt is now 18.2 compared to 16.2 for the first quarter of 2016. And you're going to hear today about some more specifics around our greenfield development pipeline, which includes 350 megawatts of shovel-ready projects in Alberta and Saskatchewan that we'll be bidding into the upcoming renewables RFPs. So all of this is, in my view, excellent news for both TransAlta shareholders and our debtholders.

Before I turn the call to Donald, just a few comments on our strategic decision on Sundance Units 1 and 2, along with our plans to go from coal to gas at Sundance Units 3 to 6 and Keephills 1 and 2. These decisions show TransAlta's commitment to align and execute our strategy to be consistent with Alberta and Canada's environmental and power policies. And these strategic actions provide a clear line of sight for investors regarding future cash flows from the coal units that we intend to convert to natural gas. And just as importantly, our employees can now better prepare for the changes ahead and align their plans with our strategy.

At the end of the call, I'm going to share in detail the factors that we considered to make the decision to accelerate our coal-to-gas conversions. But simply here, just know that the strategy minimizes the capital required, reduces risk significantly and accelerates the return on and of our invested capital.

Now my goal today in this call is to provide you with more insight and remove some of the uncertainty that we believe still exists around TransAlta. Donald is going to run you through a bridge of the cash flows, which is moving our run rate of $250 million to $300 million to $400 million in the 2018 to '20 period.

I'm going to provide you a bit more detail on a key project that we have internally here called GreenLight that we introduced at our annual meeting. And I'm going to provide you with the kind of insight that you need to assess where we are as these renewable RFPs come underway here in the prairie.

So with that, I'll call -- I'm going to turn the call over to Donald. He'll go through the details of the quarter, and he's going to talk about our progress on strengthening our balance sheet.

Thank you, Dawn, and welcome to everyone on the call. As Dawn noted at the beginning of our discussion, our EBITDA, FFO and free cash flow were in line with 2016.

Slide 5 provide the segmented result for our generation asset for the quarter. EBITDA from operation was $302 million. This is an increase of $28 million over the first quarter of 2016 and is $20 million above our 3-year run rate for the first quarter of approximately $282 million. Canadian gas was up $23 million over the first quarter of 2016.

During the quarter, we progressed settlement discussion with the Ontario Energy Financial Corporation on an indexation dispute that relate to the period of 2013 through 2016 on our Windsor and Ottawa facilities. The total settlement, which is expected to be approximately $34 million, was booked in the first quarter. Offsetting this was mark-to-market losses related to gas hedge on future gas requirements that don't qualify for hedge accounting and lower revenue from our new contract at our Windsor facility.

For the last 20 years, the Windsor facility provided both energy and capacity to the Ontario market. The new contract allow the facility to provide capacity to Ontario for the next 15 years.

Canadian Coal EBITDA was $91 million, down $12 million over the first quarter of 2016. This result was not a surprise and was expected, given the replacement of higher price hedge with hedge at lower value. As well, we had expected increased fuel cost caused by planned maintenance to a dragline and higher strip ratio at the mine. The development of a new pit area at the mine during 2017 and 2018 will improve our strip ratio moving forward.

In Q1, we start to accrue the off-coal agreement payment of $39 million a year with the Alberta government. We will be accruing approximately $10 million per quarter. This accrual is booked in the net operating income -- net other operating -- sorry.

The U.S. Coal EBITDA was up $14 million from the first quarter in 2016. Even though this is a year-over-year improvement, this was below our expectation as power price in the Pacific Northwest were lower than expected, which significantly reduced our margin on non-contracted generation. The low price improvement led us to an early shutdown on Unit 2 for its planned maintenance in February, while Unit 1 was shut down in January due to unplanned maintenance that Dawn mentioned earlier.

Our wind and solar EBITDA was up $7 million over the same quarter in 2016, due to the sale of solar renewable energy credits on our solar farm in Massachusetts. Strong wind production in Eastern Canada at higher contracted price also contribute to improved performance. Energy Marketing delivered performance that was below our expectation and the normal run rate for the first quarter. Unusual weather condition in the Northeast, which had the third warmest winter on record in 120 years, which had -- sorry, and the West, which experienced extreme precipitation, caused our team to limit the size of position taken in the market compared to prior year.

Also impacting Energy Marketing year-over-year was the rolloff of some of the customer business that was in place during 2016.

As a result of the Q1 performance, we have adjusted our 2017 objective for Energy Marketing to $60 million to $70 million in gross margin for the year, down from $70 million to $90 million that we had set at the beginning of the year.

As you can see here on the slide, power price has been dropping since 2013, moving from approximately $65 per megawatt hour in Q1 of 2013 down to a low of $18 per megawatt hour last year in Q1. The chart demonstrates that, despite that dynamic, we have maintained strong EBITDA consistently above $250 million in each of the past 5 years' first quarter. Additionally, during the same period, our FFO has averaged roughly $200 million per year.

Now let's talk about like our balance sheet and our credit metric. As you can see from the slide, our liquidity is to build, including cash of $500 million. The build-up of cash was expected, as we are preparing to pay off the U.S. $400 million bond that matured in June 2017. The $200 million increase in cash during the quarter is due to strong cash generated by the business, decrease in our working capital and the sale of Wintering Hills.

Turning to Slide 9, our FFO to adjusted net debt ratio has improved 2 full points over the level at the first quarter in 2016, resulting from strong performance of the business and a focus on debt reduction. Period-over-period, the rolling 12-month FFO is up approximately $50 million to approximately $770 million, and the net debt has been reduced by approximately $230 million, mostly as our cash balance have increased.

The commissioning of South Hedland later this year is expected to further enhance these ratio. With a full year contribution to EBITDA in 2018, we expect to achieve our goal of FFO to adjusted net debt in the range of 20% to 25% and adjusted net debt to EBITDA of 3 to 3.5x.

We are now focusing our attention to our 2018 debt maturity of $800 million and raising the capital required to complete South Hedland construction in 2017, which is approximately $230 million. To do so, we are planning to raise approximately $700 million to $900 million through financing [contracted] cash flow and utilizing cash generated by the business in 2017 and 2018. Our goal is to improve our credit metrics so we are at the high end of our targeted 20% to 25% FFO to net debt by 2020.

During our call in March, we told you that we were targeting $400 million annually in free cash flow for the period 2018 to 2020. I will take a few minutes here to tell you how we will get there. I'm starting with our 2016 free cash flow of $250 million. This free cash flow include the nonrecurring $25 million MSA settlement payment. Our South Hedland project will be COD in the second half of the year and will contribute approximately $40 million to our free cash flow in 2017.

Our cash flow this year will also include the off-coal transition payment of $37 million from the Alberta government. This is net of the amount due to our noncontrolling partner. However, as I mentioned earlier, our 2017 results will be negatively impacted by the rolling off of our hedge at Canadian Coal and increased coal costs at the mine. Some of the higher coal costs will reverse in 2018 through 2020.

Looking forward, Sundance 1 and Sundance 2 are contributing approximately $50 million each under the PPA after sustaining CapEx. Their early retirement, or mothballing, will negatively impact our cash flow compared to 2016/'17. However, their contribution as merchant units was negative over the next 2 years. The decision to accelerate the coal-to-gas conversion will allow us to reduce our capital expenditure related to certain equipment at the mine and the plant, positively impacting cash flow by approximately $20 million on average over the 2018 to 2020 period. This impact will be more visible as we get closer to the coal-to-gas conversion.

As you all know, the contract at Mississauga will expire in 2018. The plant contribute approximately $40 million a year in free cash flow after payment to our noncontrolling partner. The Poplar Creek capacity payment will also be reduced by $35 million starting in 2018. This reduction will be offset by the full year contribution of the South Hedland post 2017, which will add an additional $40 million to our free cash flow as well as lower interest expense as we continue to reduce our debt between 2017 to 2020.

Our renewable asset in Alberta would -- should benefit from the full implementation of the carbon tax. We expect price to increase by $15 to $20 per megawatt hour over today's price starting at 2018. This increase is already visible in the forward curve. The impact of improved pricing on Alberta wind and hydro should add $20 million to $30 million to our free cash flow.

Lastly, over the last 2 years, we have made significant reduction in our cost structure, but we believe we can still deliver more and improve our free cash flow. All of our business and leaders are committed to this transformation, and we believe GreenLight can deliver sustainable savings of $50 million to $70 million annually, commencing in 2018. This represents a reduction of approximately 5% of our existing cost and sustaining capital.

Dawn will be providing further detail on this initiative in her remarks. With that, I will now pass the call back to Dawn for the closing.

Thanks, Donald. I think there's -- that was excellent. There's lots of information in there. So I think as people get the script they'll want to study that.

I'm going to spend the last few minutes of the call walking you through 3 things. First, I'll share the factors we considered in making our strategic decision to accelerate coal-to-gas conversions. Second, I'm going to provide you a bit more detail around Project GreenLight that Donald just referred to. And third, I'm going to walk you through some of the details on our growth prospects and how we think about opportunities in the greenfield space.

So let me start with accelerating our conversions. Now for many of you, it may be an intuitive conclusion that running the assets over the longest period of time that you can is the most valuable. So in our case, that would mean running the assets to the end of their lives on coal and then converting to gas. And I think the conclusion would be that, that would make the best economic decision. And to be honest, our team thought this way as well. And at least we did until we sifted through all the factors and did the analysis.

And in the end, our analysis showed that accelerating the conversions is actually the right thing to do. So let me walk you through some of the factors we considered and how we thought about the risk.

So first, we did consider the total capital cost, and we broke these capital costs into 2 buckets. First of all, we looked at our sustaining capital, which is really based on our run rate for our Canadian coal fleet, and it includes the capital that's required in the mine. And that capital, as you know, is in the order of about $200 million a year. We also considered the additional CASA costs, which are one-time costs that would be required to run any coal asset beyond 2021. And we estimated those costs to be in the range of $250 million to $300 million for our coal fleet.

Now putting this into perspective, a decision to continue running on coal until 2026 for some units and 2029 for others would require us to spend approximately $1.5 billion more in incremental capital costs in the plants and in the mines and as well in CASA costs. This capital would then have to be recovered over the 10 to 15 years of potential incremental asset life between that 2035 and 2045 period. We also believe that the pace of technological innovation that we're seeing today adds obsolescence risk to our plants if we look at extending their asset lives too long.

So with our chosen strategy, which is to convert early, we see an immediate reduction in our capital until 2021. Then, over the course of 2 years, we'll spend $300 million converting the units as planned, and we'll do that in $50 million chunks, as we do the outages, and these converted plants will run for up to 15 years with roughly half the annual capital spend. So that was our first big bucket of considerations as we made this decision.

So secondly, we considered the gas outlook and gas prices and gas volumes. Today, we have an oversupplied gas market here in the West due to a lack of demand here in the West and an inability to get the gas to markets in the East or the U.S., because there's an emerging supply of gas in those markets that is taking up the demand that is in those other markets.

The high value of liquids in the Alberta gas basin is inciting producers to drill, but we do believe that, that will evolve over the next 10 to 15 years. This high volume of drilling here in the West to get the liquids out does leave a lot of gas in the market here that can be burned. So converting our coal units to gas on our planned timeframe, which is an accelerated timeframe, allows us to utilize this low-cost resource when it's available.

Third, the third thing we looked at was the cost of carbon. And as you know, it's $30 here in Alberta, and it will be there by next year. However, as you all know, the federal government has instituted a compliance for the provinces to be at the level of $50 by 2022. It is our view that it's more likely than not that Alberta will migrate to the federal target. In fact, we believe that ultimately the cost of carbon is likely to rise rather than to fall, especially for those of us that are in the power market.

As I've said on our call with our investors at our annual meeting, consumers want affordable and clean electricity. So we concluded that there would always be pressure on the power sector to minimize the use of carbon, whether it's through a carbon tax or some other mechanism. So we concluded that the sooner that we convert, the sooner that we start to save on the cost of carbon, which, for the coal units, is approximately $18 to $20 a megawatt hour, and that's only if you have a $30 carbon price.

So in conclusion, we see our decision as an acceleration of cash flows. In the scenario where we ran coal to the end of life then convert to natural gas, we not only increase our total capital spend and our total capital investment, and that's investment in the near term, but we add risk that the strong cash flows from the coal-to-gas conversions will never be realized. All of our NPV analysis pointed to reducing risk and increasing returns to our shareholders by converting now, taking advantage of the lower capital cost, taking advantage of low gas prices, versus waiting for what could be an uncertain future as new technologies come into play in the 2030 to 2040 time frame.

So with that behind us, that decision behind us, I do want to take a minute to give you more insight on our major transformation effort that we recently kicked off, and we call it GreenLight. I introduced this project briefly at the AGM using the metaphor of driving from downtown Calgary to Okotoks without hitting a single red light, which I'm hoping the city will do something about at some point.

But GreenLight is not only about getting rid of the corporate red lights that slow down our progress. It's a major transfer -- corporate transformation effort which is really needed as we think about transforming our business from where it is today to a much simpler business in the future which will be centered around gas and renewables.

I'd like to stress that the effort is a top priority of our company, and I'm really pleased about how our team has mobilized to support it. So let me briefly say a little more about what it is, who's involved, how it works, and why we think it's different than other change programs and what benefits we expect to generate and how I intend to keep you updated about our progress as we go forward.

First of all, what is GreenLight? GreenLight is a focused and it's a multiyear effort, it's not a 6-month effort, it's a multiyear effort, we're in about month 8 of it, to drive ambitious improvements in every part of TransAlta. It is designed to improve revenue, reduce operating costs, and optimize our capital spend.

It's more than just a one-time effort. It amounts to a permanent change in how we intend to run the business, and it institutes ongoing processes inside our company that identify, quantify and execute on opportunities right from the shop floor up. GreenLight involves all of our people. From the beginning, it was created to draw the best improvement ideas out of all of our staff, from the shop floor to the executive level and everyone in between.

We know that this is the only way to unlock the full potential of the organization fundamentally. It boils down to engaging all our employees regardless of their level in the corporation and to bring their ideas and energy to the table.

Now how does it work? We have organized the company into a number of work streams, each headed by an experienced executive. That person's role is to engage all employees in the areas that generate concrete ideas, and we call them initiatives. All initiatives are entered into a central project management solution that tracks both activities and impact. And this -- and all of the initiatives in this central system are tracked by our senior management team on a weekly basis.

The system uses a very rigorous process. It structures and -- that are structured and highly automated so we can manage the ideas from their idea generation, through to business cases, through to implementation, and finally to the evaluation of what the performance was. So we can ultimately see, when we get to the delivery stage, the value that each of the initiatives has brought to the company.

Now we're training our people, not only to do this once, but to make this an ongoing way that we operate the company. I think this program is different than other things we've tried here at TransAlta. It's different because of the rigor, the engagement and the structure. And it is -- continues to be -- it will continue to be a top priority of the company. Now -- and I do believe the process we've designed is rigorous and better than anything we've used before. And it really does help us create that sort of innovation culture.

We have, as part of this, instituted a new role called the Chief Transformation Officer, and the person that leads that transformation office leads an office of young, enthusiastic and bright TransAlta people, but more importantly, she comes from the IT background. And her ability to bring innovation together with the kind of work that gets done in the IT space these days is what really gives us an ability to see the kind of juice that we can get out of this initiative.

Now the benefits that we'll generate Donald talked about, those are our early numbers. And as always, we want to make sure that we can deliver what we've promised. But we have big ambition for this -- for where we can take this.

How will we inform you? As we go forward, we'll give you updates on how it's going and what its meaning to us as we transform our company from where it is today to a much simpler company that is involved in gas and renewables.

And I want to conclude by saying that I just give the TransAlta executive team a lot of credit for taking on GreenLight at the same time that we were making decisions on gas and coal and running the business.

Now investors do continue to be quite interested in the growth prospects for the company. People want to know what's in our development pipeline, how we think about greenfield opportunities and our focus in -- our geographic focus.

On this slide you see we've got 13,000 megawatts of greenfield opportunities that -- in geographies that we operate in and we do have shovel-ready projects. We won't be successful in every auction, and we continue to be prudent and disciplined, and I think we've shown you that over time, in making investment proposals that will provide the right returns for the appropriate risk profile. Growth at any cost is not in TransAlta's plan.

So let me walk you through the sites where we believe we have some really good opportunities to win some RFPs at the kind of returns that we like. Between Saskatchewan and Alberta, there will be more than 6,000 megawatts of renewable generation built over the next 15 years. And we'll win our share of those project development opportunities.

In the prairies, we have 3 shovel-ready projects -- Garden Plains, Cowley Ridge, and Antelope Coulee -- totaling about 350 megawatts. Beyond this, we have additional sites in these provinces that we continue to work on, and we are developing the resource data and making sure that we have the right stakeholder relationships so that those projects will have the longevity -- will be there over the long term.

These 3 projects are quite similar in their development phase in that we have strong wind resource data, excellent landowner relationships, and each can be in service by 2019. Additionally, the development costs are quite similar at approximately $2 million per megawatt of installed capacity, which equates to the total development cost of around $700 million, if we're successful in the auctions.

Both governments are offering long-term contracts for the upcoming renewable projects. And in Alberta -- they're going to use a contract for different mechanisms. In Alberta it will be -- they'll be using a more simple 25-year PPA. And as a result, project financing will be available on these projects, which really reduces the actual cash contribution by us from an equity perspective.

We are continuing to engage with the Alberta government on our Brazeau project, which we will -- which is an absolute enabler to bringing on more renewable projects into Alberta and keeping power in the Alberta market affordable. And we've seen just tremendous support for this project. So it's just a matter of now figuring out what the mechanism will be here in Alberta for calling on these kinds of projects.

We do expect our newest gas asset, South Hedland, to be commercial in the next few months. And you know from -- we've told you several times that will bring $80 million of EBITDA annually. In Australia, we do have a mature 80-megawatt solar greenfield development project, which we've received development approval for the site in December last year. We've been working with a Tier 1 EPC contractor to handle the construction, operation and maintenance of this facility. It would take about 12 months to construct. It could be in service by as early as mid-'18. And it's -- the team is working on finding a suitable offtaker for it. There's a huge demand in Australia for projects like this in their REC market, and it has -- this project has a cost structure which we think is very competitive.

So in closing, when we stand back or when I stand back and think about where we are today compared to where we were 12 short months ago, I think we've made a lot of progress. We've talked about the progress on the financial side. We've accelerated our coal-to-gas decision I think in a very logical way that will benefit TransAlta shareholders. We have a focused plan here at the company for ensuring that we have the kind of company that will be competitive as we transition from coal to gas. And I think we're doing all the work that we need to do to accelerate our goal of becoming Canada's leading gas and power company -- or gas and renewables company.

So with that, we'll take your questions and look forward to them.

(Operator Instructions) Your first question comes from the line of Rob Hope.

Maybe a question on GreenLight to start off. Just seeing that it looks like that could be $50 million to $80 million of benefit there. I'm just wondering, when do you expect to realize this benefit? And given that it's been in place for, it looks like, 8 months so far, has any been realized so far?

So we will probably start seeing some benefit like in 2017. Keep in mind, like we're in the -- currently in the execution phase. So the first part of the project was basically a lot of due diligence to make sure that we were coming with the right structure and the right goal. We are expecting to see some benefit this year and the full benefit for sure in 2018.

Yes, I would just say, Rob, just to add to that, if you think about the kind of transformation we're making here, for sure there are costs to this. This is not cost-free. We couldn't simply just do this without engaging in some real significant change, in training and all of that. So the benefits that are coming in 2017 are mostly offsetting the cost. The net benefit phase of the program is -- starts in the 2018, 2019 period.

All right. That's helpful. And then just to clarify. So the $400 million of free cash flow in that '18, '19, '20 time frame, would that -- that includes the full, I guess, run rate of $50 million to $80 million in there?

Yes, exactly.

All right. That's helpful. And then just one quick question on energy trading. So Q1 was soft. You did revise down your guidance a little bit for the year. Is that -- but the revision downward was rather small. Does that imply that you did see good opportunities so far in Q2? Or is this more back-end loaded?

No, no, we're seeing what we expected to see in Q2. So I'm -- I think there's been some -- I think the markets are a little bit more normalized now and we're back at doing what we normally do here.

And what I would say is the trader generally are good to recover. They're imaginative people, they're innovative and they're looking to basically make their numbers. So we reduced our target, but I still like -- believe that it will deliver.

We don't like to put a high target on trading for 3 quarters because we don't want excessive risk-taking. So we're back to the normal level of risk that we take, and we're seeing good things here in the quarter.

And your next question comes from the line of Ben Pham.

Just want to go back to Project GreenLight. And it seems like the 8 months you highlighted seems to kind of be around the time the Alberta coal compensation was announced. So I'm just wondering, does this GreenLight project you've put out, I'm just wondering, what was the big impetus of this? Was it just this huge change in business that you're moving towards over the next few years? Just wondering why you haven't looked at it in the past. And I know you went on a pretty big corporate reduction strategy a few years back on the corporate side. And so I'm just wondering, is there a certain segment that this is mostly targeted on? Because I would think contracted, there's probably not much you can do on the cost side?

You know what, Ben, just to answer that question, a couple things. So really, you're right, in the last couple years we've done some typical downsizing initiatives. We did a downsizing of our corporate function in 2012, 2013. And we did a delayering initiative in kind of the 2014, 2015 period. But by the time we got to last summer, it was really last summer that I started to really think about it. And then, by October, the team started to really figure out how to get this done. And what we couldn't -- what we were worried about was, in order for us to make the transformation that we knew was coming, there was no question it was coming because we were in the -- some pretty heavy discussions there with the Alberta government, but as we were thinking about that, we knew that the only way through this was to have engagement from the front lines back. Because it's really the front lines that know how everything works here. Big companies have lots of processes, they have lots of systems and they have lots of bureaucracy. And we knew that to get to the other side we couldn't have that. We had to sort of change the game. So we really began the project in earnest in October, but it's been designed with true front-line employee participation all the way through the organization. So just kind of in terms of whether or not it will have any impact, so when you look at those benefits that we're talking about, yes, for sure the biggest -- one of the bigger businesses is in Canadian Coal. So there's a lot of work, and they've been tremendous at the work that they've been doing, both at the plants and at the mine. But just remember, as they start to downsize that mine as they go forward, because we're going to be bringing on more gas, they need this kind of boost, and you really need to know that you can engage everybody in what you're doing to get things done well. But we do see that, as we look across our corporate organization, as we look in our businesses that have contracted assets, companies have ways of getting things done and they're taking advantage of finding better ways to get things done as well. So this is really Phase 3. If I was thinking -- as I've said to our chief transformation officers, Phase 4 is really, really getting after even more technology. You all know, because you all see what's going on in the technology space, there's just enormous opportunities there. So this really conditions us now to start to think ahead about technology. That's not built into our numbers. That's kind of a next phase. But this is really Phase 3 of what's been a journey for us.

I'm just wondering, on Slide 14, some more detail on some of the projects you're planning to bid into RFP processes. And I'm just curious about the positioning of those projects, how you think about them. Is it mostly going to be a cost of capital differential between better parties? Or is there something you see in these projects that could give you a great edge?

Yes, remember -- so from a cost of capital perspective, we have cash flow coming through TransAlta because of the work that the team has done, and we also have a pretty good currency there in TransAlta Renewables. So on a cost of capital basis, I don't think we're disadvantaged at all. Where we have the advantages, though, with these projects is these early calls are going to require you to be able to hook up to -- to, a, already have transmission access; and b, be operational by 2019, which means you already had to have done all your work, and you have to be able to bid in the 2017 time frame and build in the 2018 timeframe, then come online. So these first projects that we have here are all shovel -- when we say shovel-ready, they're ready to compete in that case. Now I'm sure there's others that have those. And as you know, there's always investors that will take a nosedive to get into the market. If they do, we're not going to bite. We're going to -- our project -- there's 5,000 megawatts coming. I'd rather get a good return at the right time than be the first one out of the gate and get a crappy return because people are willing to throw money away. So -- but net-net, when we do our -- when we look across the range of things you need to do to do these projects, remember, we built 500 megawatts of wind here in Alberta. We know how long it takes to get a foundation built, how many days it takes to get your towers up. We have all that expertise in the company, so we'll be utilizing that.

Your next question comes from the line of Andrew Kuske.

Just wondering, just when you think about the corporate structure of TransAlta, and you've obviously got a number of assets sitting at TransAlta, at the top that has the legacy coal, and then you've got TransAlta Renewables, how do you think about the longer term balance or bias of value between the two entities and really the interplay between the two?

Yes, I mean, I continue to see TransAlta Renewables more as a yield co than a renewables co. I mean, frankly, as you've probably picked up, the sooner we do the transitions and the conversions we become TransAlta Renewables, because right now TransAlta Renewables is coal -- is gas and renewables. But remember, TransAlta Renewables as an entity has the contracted stable cash flows, the cash flows that you feel pretty confident about paying a pretty high dividend out. So it is a yield co. We pay a lot of the cash out of that vehicle. Now we own 64% of it and a lot of that cash comes back into TransAlta and is available for distribution, either to growth or to the balance sheet. So in the short term, we're making sure the balance sheet is strong and also have -- we have enough cash there to participate in some of these growth projects. But as we look out over time, I think really the 2 vehicles offer something a little bit different to different kinds of shareholders. Renewables will tend to be for the shareholders that want a dividend and a really stable cash flow. And even when we have a capacity market here and we've got our conversions done, they'll still be some volatility in the cash flows in TransAlta. So that's more of a growth vehicle. So that's how we're thinking about it today. Things can change, but that's kind of our current view of it, Andrew.

Okay. That's helpful. And then as you think about just the capital allocation in the Alberta market on the front end, on really the conversions, the gas conversions, and I think some of your commentary echoed a little bit of this theme of a bit of drilling activity in Alberta B.C., predominately chasing liquids could wind up in a very advantageous gas price environment, which overall could be very interesting for someone like yourself from a power price deliverability at the end. Is that something you just see really as stability in power pricing and a really good gas market from a developer standpoint?

Yes, I would say that, when we looked at it, as you know, trends don't last forever, but there is certainly currently an oversupply and a potential to oversupply gas in almost every market in North America. And the Northeastern gas -- when you look in the Northeast of B.C. and you look in Northern Alberta, there's just tons and tons of gas. And it's not getting out of here right now by LNG. It's getting blocked into the -- to the basin. So that's exactly -- we're taking -- we would rather take advantage of that gas being in the market early than hope that it's there in 2030. Because, frankly, we can't see 6 months, never mind '30, 2030. So that's a big, big, big piece of the play. And also, if you look at our plants, they'll run quite a bit better on gas and they run at half the capital. And if you just wanted to put it in really simple terms, if you were making the bet and someone said you have to put $250 million of additional compliance cost into coal plants to run them for another 10 years, or you can put $300 million, $50 million more, and convert them to gas at a time frame when you think gas prices are going to be low and you're going to be more competitive, how would you take that bet? And you spend half the capital after that. So it was actually a pretty simple decision after we did 10,000 models and talked about it 10,000 times. But that's really what it came down to.

Okay. Well, I won't ask you the same question 10,000 times.

Your next question comes from the line of Robert Kwan.

Just on the coal-to-gas conversions, I was just wondering, with the engineering work that you've done, what your expected emissions intensity of those units would be and how does that square up against where the Feds are falling on that?

Well, I'm going to -- just in terms of the engineering work, we've done our kind of cost re-estimates. Our teams have also spent quite a bit of time visiting other converters. So there's a number of these going on in the U.S., and we've been able to engage with other parties. So we've got quite a bit of confidence in terms of the -- just getting the work done. It doesn't look that difficult. But there's quite a moving frame here in terms of what the Feds want. We know that overall the Feds are absolutely thrilled and ambitious about TransAlta taking this action and taking it early. Because, truly, I think they expected we'd wait for a long time. But I think the greenhouse gas reductions are really worth a lot to them. So in terms of actually how to do that and make sure that we get the right -- because what you want to do is make sure that, if your conversion factor is, let's say, 0.65 or 0.7, you want to make sure the regulations hold you to that and that you don't just let the equipment deteriorate and then net more when you don't have to. But on the other side of it, you also want to make sure that we can cycle these things down as well as we can, because if they want to bring a lot of renewables into the market, they don't really want base load gas conversions. They want them to be more capacity plays. So John Kousinioris heads up our regulatory, and he spends all his life doing this work. So he's going to give you some flavor that.

Yes. All I can say -- I think Dawn has actually covered it very well. We're engaged right now in discussions with the federal government, and actually the provincial government as well, on what the emissions standards would be for converted units. I think those discussions have been multilateral in the sense of involving umbrella groups from the industry and a number of companies, and also just bilateral in terms of having discussions between TransAlta and the government. What I can say is the engagement has been great. I think the government, at least from our perspective, very much is focused on trying to permit this to occur. As Dawn said, the emissions reductions can be substantial. I mean, just even some of the preliminary modeling that we have done would show 40%, 40-plus-percent emissions reductions from the units, from the converted units, as compared to the existing coal-fired generation on the CO2 side. But the devil is in the details, and what we're trying to do is make sure that the government ends up with a standard that is rigorous and reasonably tight yet also offers the flexibility to recognize kind of the full dynamic of how the units will be expected to run over a 10- or a 15-year period, probably moving, as Dawn said, from being more base load oriented in the initial years to being units that will be more operating like peakers, I think, in the later years as more renewables get in. So there's still a process to go before the rules are actually developed. But we wouldn't have proceeded with the approach that we did and the decisions that we did if we didn't think that our company would be able to meet the rules that will be developed eventually by the government. So discussions are good, and we'll have a lot more clarity on the actual rules, I think, in the coming weeks and months.

Yes. We just see that as regular regulatory risk when you're trying to make a decision.

Yes. (inaudible)

To put it differently, though, you still need the Feds to move off of what they initially put out when they had the quarterlies?

Yes, we do. They do need to move up. I think it was the 0.55 standard. And I think they understand that restriction. And that isn't just a TransAlta issue. That's an industry-wide issue. So the federal government wouldn't have proposed putting coal-to-gas conversions, or facilitating coal-to-gas conversions with a standard that would preclude them from actually happening, is the way to kind of look at it. So we're working on trying to develop what the right standard is. And 0.55 we don't think is the right one.

And I think they would rather get us to the right standard than have us stay on coal because they couldn't get the right standard here, on balance.

That's right.

For sure. Okay. If I can finish just on Alberta wind. Dawn, the last time you guys built out a lot of capacity, you guys did a great job within Alberta getting things done on time and actually at costs that were quite a bit below industry standard. I'm just wondering, are those people still around, given you haven't built quite as much since then?

Yes. Are you kidding? They're so excited that -- remember, what we do is we take those construction guys who love that and we put them in operations, and then they just wait for us to build another wind farm. So they had built in Alberta, and then they went and built in Québec and they built in New Brunswick. So yes, there's a bunch of excited guys down there that we'll have no problem re-engaging with.

Okay. Great. If I can continue just on that topic, though. As you're thinking about bidding these projects in, are you looking at them on a standalone project basis versus your hurdle rate? Or would you also assess the returns with potential upside to monetize those down into RNW?

That's probably competitive information that I'm not going to talk about on the phone.

(Operator Instructions) Your next question comes from the line of Mitchell Moss.

Just want to get a little more insight into the coal-to-gas conversion. You mentioned about a lot of the sort of gas that's trapped in Alberta. Should we take that to mean that you think that the converted plants could potentially earn energy margin as well as capacity margin? I mean, and significant energy margin? I mean, because, I guess, these are still sort of peaking type -- peaking heat rates?

Yes. Well, let me start, and then everybody who wants to jump in here. So I would say, first of all, when we run the models, these are not just peaking plants. There's quite a need for energy in the marketplace. So you're right to point out that if we get in a situation where there's really low gas prices, for sure there's additional margins that will come from the energy market. So we're not looking at these as only capacity plants. We believe there'll be energy margin. Now Mitchell, we're looking at 2022, 2023. That's a long ways off. So I wouldn't want to speculate at all about how that works. I mean, for sure when we run our models, the capacity is the lowest cost capacity that you can bring into the marketplace and under a variety of gas prices. Sometimes you're making margin in the energy and sometimes you're not. But for sure we're recovering a return of our capital through the capacity payments. So maybe Donald?

The other factor is also like the carbon tax and will all the coal plant in Alberta will convert to gas. So potentially there may be some coal plant that remain on coal, and they will pay higher carbon tax. So that will also have an impact on pricing and could create more margin for the converted units. So there's a lot of things that will happen between now and 2021. And clearly, as we go, we'll better understand like how much margin is coming from those assets.

But the basic trend that we see is -- this liquid-rich gas needs a place for the methane to go, and our converted units are nice units for burning that methane so that the guys that want to get more liquids out of here can do that. So there's a real potential benefit here.

So the -- in terms of -- I'm not sure if I missed it on some of the other calls, on some of the other questions, but for the pipeline -- to get the pipeline siting and pipeline access for the plant seems to be sort of the most long-term part of the conversion. And so especially if you're talking about sort of a 2021 time frame for some of these plants to be converted, when should we start to -- when do you guys need to start to build the pipeline access for the pipeline?

Yes, for the pipeline, it's kind of -- there's 2 options. There's a pipeline coming off Alliance and there's a pipeline coming off of TransCanada or there's -- there's either one or the other or there's both. So we're in the process of having those discussions. And we've been in those discussions for a while now. The pipeline, you're 100% right, it is the gating item for sure. We built, and I'm going to put a plug in here for what we expect from the regulatory agencies in Canada, but we built a 165-kilometer gas pipeline in Australia from beginning to end in 16 months. So my view is a Canadian 50-kilometer pipeline should take 16 months if we're going to compete in the international world. But unfortunately, people tell us it takes about 3 years. So we're actually working to that time frame, but we'll be pushing hard to make sure Canada can start to figure out what it needs to do to compete on these things. The PPAs are on these plants, remember, until the end of 2020. So we don't really have an ability to go earlier. Under the current PPAs we have to stay on coal. So we've accounted for that in our plans, which is why 2021 is our earliest year. So 2021 gives us '18, '19 and '20 to build the pipeline, which is about an average time, and it also gets us to run our PPAs out. Now if things changed and we felt we could find a way to accelerate, we'd be looking to see how to do that.

Okay. But so it sounds like you would need to start sort of starting the projects starting in 2018, I guess is -- in a year from now basically.

Yes. As with everything in the world, the discussions and the regulatory process is the long part. The actual building is not that hard. So yes, we're -- all our commercial arrangements have to be done within the next year.

And finally, just on the pipeline CapEx, do you expect to need project financing for any of that?

No, the pipeline CapEx would be covered by the pipeline companies and we would have a toll. And we think that total obligation would be for about 8 years.

And the next question comes from the line of Jeremy Rosenfield.

Just a couple of follow-up questions. Just on the Australian solar project that was highlighted, Dawn, you mentioned that you're, I think, far along in the process, it sounds like. Can you talk about whether you're looking for a utility offtaker, a mining offtaker, some combination of one or the other, and then how that would factor into the financing decision to make on that investment? And then maybe just as a final follow-on on that, how you think about the sort of overall investment returns that you get on investing in solar or renewable energy in Australia relative to sort of the Alberta experience under what's coming in the RFP?

Yes, I would say that -- so just in terms of the offtaker would be someone with a high credit rating. So it would be -- I don't think we would have to put on additional risk metrics. If the offtaker happened to be somebody with a different credit profile, we would put a return risk adjustment in there for that, just like we have in other parts of Australian business. But right know what we're seeing is it's mostly the utilities that are looking for these. I haven't checked lately, and I apologize if I give you the wrong information, but the REC market in Australia was trading in that sort of $85 range. So effectively, people have quite a bit of motivation to buy assets rather than pay the penalties. And that traded up significantly over the last period of time. So that's really -- our competitor here is utility companies paying penalties rather than owning projects. So that's our preferred offtaker. In terms of the overall risk adjustment, we do tend to see Australia at almost the same risk as Canada. We try to finance and hedge so that we can use the Australian dollar and not get currency risk in there. But net-net, from a risk perspective and a return perspective, we would see those 2 jurisdictions as being pretty equivalent. We don't see country risk for Australia. We know the country well. We know the politicians well. We know the regulatory situation well. So we tend to have the same kind of return expectations as you'd see here.

So just to be clear, so you're kind of agnostic in terms of investing capital either to renewable opportunities in Australia versus renewable opportunities in Alberta in terms of the financial implications from those investments?

Yes, that would be correct.

Okay. Good. And maybe if I could just clarify something with Donald. In terms of the OEFC settlement and how things were booked in Q1 results, the -- what was the amount that was included in FFO? Was it the full amount flowed through from EBITDA or was it only $11 million in FFO? And then is there anything that we should expect in Q2?

So the whole amount is included in FFO. And we're expecting to receive the actual cash, it's a receivable, like in Q2 or early Q3.

Okay. So -- but from an accounting perspective everything is in Q1, essentially?

Everything is in Q1, yes.

And we have no further questions in the queue at this time. I will turn the call back over to the presenters.

Thank you, everyone, and that closes out the call. My team is available for questions after the call. So have a great day. Thank you.

Thank you to everyone for attending. This will conclude today's conference call. You may now disconnect.