TransAlta Corporation (TAC) Q1 2017 Earnings Report, Transcript and Summary

Good morning, my name is Dan and I will your conference operator today. At this time I would like welcome everyone to the TransAlta Corporation First Quarter 2017 Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speaker’s remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. 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 transcript will be posted to our website shortly thereafter. All information provided during this conference call is subject to the forward-looking qualifications, 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, 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 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 to everyone. Lots to talk about today and really a lot has happened in the last six 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 conversion 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’s in the detail. So while Donald’s details and comments will help you understand the quarter performance what I do want to be clear about is that I remain very confident that we are 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 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] [ph]. 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 North West 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 probably 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 strength that we’ve developed and you’re going to hear more about this today as Donald takes you through the detail. 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 two years. We do have $500 million of cash in the bank which will position us to pay off our 2017 maturity 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 renewable RFPs. So all of this is in my view excellent news for both TransAlta's shareholders and our debt holders. And before I turn the call to Donald, just a few comments on our strategic decision on Sundance Unit 1 and 2 along with our plans to go from coal-to-gas at Sundance Unit 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 am 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 acquired, 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 flow, 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 our key project that we have internally here called Greenlight that we introduced at our annual meeting and I’m going to provide you with a kind of insight that you need to asses where we are as these renewable RFPs come underway here in the [province] [ph]. So with that, I’ll call – I’m going to turn the call over to Donald, who will 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 discussions 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 a $20 million above our three 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 related to the period 2013 through 2016 on our Windsor and Ottawa facility. 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 provides both energy and capacity to the Ontario markets. The new contract allow the facility to provide capacity to Ontario for the next 15 years. Canadian coal EBTIDA was $91 million down $12 million over the first quarter of 2016. This result was another suprise and was expected given the replacement of higher price hedge with hedge at lower value, as well, we had expected increase fuel cost caused by planned maintenance towards [indiscernible] line and higher strip ratio at the mine. The development of new pit area at the mine during 2017 and 2018 will improve our strip ratio moving forward. In Q1, we started to accrue the Off-Coal Agreement payments 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. 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 reduces our margin on non contracted generation. The low price environment led us an early shutdown on Unit 2 for its plant maintenance in February. While Unit 1 was shut down in January due to untimed 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 contributed to improved performance. Energy marketing delivered performance that was below our expectation and the normal run rate for the first quarter. Usual weather condition in the Northeast, which had the third warmest winter on record in 120 years 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 role off 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 said 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 five year 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 $2 billion including cash of $500 million. The build up of cash was expected as we are preparing to pay of this 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 nine, our FFO to adjusted net debt ratio has improved two full points over the level of the first quarter in 2016, resulting from strong performance of the business and a focus on debt reduction. Period over period, the ruling 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 ratios, with the full year contribution to EBITDA 2018, we expect to achieve our goal of FFO to adjusted net debt in the region of 20%, 25% and adjusted net debt to EBITDA of 3 to 3.5 times. We are now focusing our attention to our 2018 debt maturity of $8000 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 are targeting $400 million annually in free cash flow for the period 2018 to 2020. I will take a few minute here to tell you how we will get there. I am starting with our 2016 free cash flow of $250 million. This free cash flow includes the non-recurring $25 million MSA settlement payment. Our South Hedland project will be sealed 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 non-controlling partner. However, as I mentioned earlier, our 2017 results will be negatively impacted by the ruling off of our hedge at Canadian coal and increased coal cost at the mine. Some of the higher coal cost will reverse in 2018 to 2020. Looking forward, Sundance 1 and Sundance 2 are contributing approximately $50 million each under the PPA after sustaining CapEx. The early retirement or mothballing will negatively impact our cash flow compared to 2016-17. However, their contribution as merchant unit was negative over the next two 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 plan, 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 contributed approximately $40 million a year in free cash flow after payment to our non-controlling partner. The paid 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 addition of $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 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 to $30 million to our free cash flow. Lastly, over the last two 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 and committed to this transformation and we believe Greenlight can deliver sustainable saving 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 initiaviest in our remarks. With that, I will now pass the call back to Dawn for the closing.

Thanks, Donald. And I think 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 three things. First, I will share the factors we considered in making our strategic decision to accelerate coal-to-gas conversion. Second, I am going to provide you – get more detail around project Greenlight that Donald just referred to, and third, I am 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 maybe 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 shifted [ph] through all the factors and did the analysis. And any end our analysis show 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 few packets. 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 consider the additional cash of cost which are onetime costs that would be required to run any cost with 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 till 2026 for some units and 2029 for others. We [Indiscernible] for others will acquire us to spend approximately $1.5 billion more in incremental capital cost in the plants and in the mine and as well in cash to costs. This capital would then have to be recovered over the 10 years 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 are seeing today adds obsolescence risk to our plant if we look at extending their asset lives too long. So we started chosen strategy which is to convert early. We’ve seen immediate reduction in our capital until 2021. Then over the course of two 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 the annual capital spend. So that was our first big bucket of considerations that we made these decisions. So, secondly, we considered the gas outlook and gas prices and gas volumes. Today we have an oversupply 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 are 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 involve 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 plan 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 what the cost of carbon and as you know its $30 here in Alberta and that will be there by next year. However as you all know the Federal Government has instituted 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 evolve especially for those of us that are in the power market. As I said in our call with our investors at our annual meetings, 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 carbon tax, 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 unit is approximately $18 to $20 a megawatt hour and that 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 run coal to the end of life then convert to natural gas, we not only increase our total capital expend 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 MPV analysis pointed to reducing risk and increasing returns to our shareholders by converting now taking advantage of the lower capital costs, 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 timeframe. 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 Green Light. 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 Green Light is not only about getting rid of the corporate Red Light that slowed down our progress. It's in a major corporate transformation effort which is really needed as we think about transforming our business from where it is today too a much simpler business in the future which will be centered around gas and renewable. I’d think 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 is 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 Green Light? Green Light is a focus and it’s a multiyear effort. It’s not a six-month effort. It’s a multiyear effort were in about month eight of it. To drive the 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 and how we intend to run the business. And it institute ongoing processes inside our company that identify, quantify and execute on opportunities right from the shop floor up. Green Light involved 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 as a 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 entered into a central project management solution that tracks both activities and impact and all of the initiative in the central system are tracked by a 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 generator – generation, through the business cases, through the implementation and finally to the evaluation of this -- what the performance was. So we can ultimately see when we get 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 these ones, but to make this an ongoing way that we operate the company. I think this program is different than other things which we try to at TransAlta. It’s different because of the rigor, the engagement and the structure and it 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 it is to needed instituted a new role [ph] call the Chief Transformation Officer and the President leads that transformation office, leads an office of young enthusiastic and bright TransAlta people, but more importantly she comes from 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 Qs [ph] that we can get out of this initiative. Now the benefits that we will generate, Donald talked about those are early numbers and as always we want to make sure that we can deliver what we promise, but we have big ambitions for where we can take this. However we inform you, and 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 TransAlta executive team a lot of credit for taking on Green Light at the same time that we are 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 and people want to know what’s in our development pipeline? How we think about Greenfield opportunities and our focus and our geographic focus. On this slide you see we’ve got 13,000 megawatts of Greenfield opportunities that in geographies that we operated in, and we do have shovel ready project. We will be successful in every option and we continue to be prudent and disciplined and I think we’ve shown you that over time and making investment proposals that will provide the right return for the appropriate risk profile. Growth at any cost does not in TransAlta’s plan. So let me walk you through the site where we believe we have some really good opportunities to win some RFPs as the kind of returns that we like. Between Saskatchewan and Alberta there will be more than 6000 megawatts of renewable generation built over the next 15 years. And we’ll win share of those project development opportunities. In this prairies we have three shovel ready projects; Garden Plains, Cowley Ridge and Coulee totalling about 350 megawatts. Beyond this we have additional sites in these provinces that we continue to work on and we are developing a resource data and making sure that we have the right stakeholder relationships, so that those projects will have the [Indiscernible] will be there over the long-term. These three projects are quite in the development phase and 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 installed capacity which equates to the total development costs of around 700 million, if we’re successful in the auction. Both governments are offering long-term contracts for the upcoming renewables projects and in Alberta they’re going to contract for different mechanism. In Alberta it will be Ws in a more simple 25-year PPA. As a result project financing will be available on this project which really reduces the actual cash contribution by us from an equity perspective. We are continuing to engage with the Alberta government on our Brazil project which we will – which has been absolute enabler to bringing on more renewable project into Alberta and keeping power in the Alberta market as affordable. And we see just tremendous support for this project, so it just a matter of now figuring out what the mechanism will be here in Alberta for calling on these kind of projects. We do expect our newest gas assets South Hedland should be commercial in the next few months. And you know, we told you several times that we’ll bring $80 million of EBITDA annually. In Australia, we do have a mature, 80 megawatt solar Greenfield development project which received development approval for the site in December last year. We’ve been working the Tier 1 EPC contract to handle the construction, operation and maintenance in this facility. It would take about 12 months to construct. I could be in service by as early as mid 2018 and the team is working on finding a suitable offtaker for it. there’s a huge demand in Australia for projects like this in their West market and it has – this project has the 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 short months a 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 in a very logical way that will benefit TransAlta shareholders. We have a focus plain here at the company for ensuring that we have the kind of company that will competitive and 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 candidate we can get in gas and renewables companies. So with that we’ll take your questions and look forward to that.

[Operator Instructions] Your first question comes from the line of Rob Hope. Please go ahead.

Yes. Good morning. Thank you for taking my call, maybe a question on green light too 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 those benefit and given that, that’s been in place for it looks like eight month so far has any been realized so far?

So we will probably start seeing some benefits like in 2017. Keep in mind we’re in the currently in 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 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 could 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 costs. The net benefit phase of the program starts from the 2018, 2019 period.

All right. That’s helpful and then just to clarify. So the $400 million of free cash flow in that 2018, 2019, 2020 timeframe would that include 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 there are 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 are innovative and they are looking to basically make their numbers, so we reduce their target but I still believe that he will deliver.

Okay. That’s helpful.

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

Thank you. I’ll hop back in the queue.

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

Okay. Thanks. Good morning. Just want to go back to Project GreenLight, and it seems like the 8 months you highlighted seems to kind of -- kind of be around the time the Alberta coal compensation was announced. So I'm just wondering, does this GreenLight Project that you've put out, I'm just wondering what was a 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're running a pretty big corporate reduction strategy a few years back in the corporate side. And so I'm just wondering, is there a certain segment that this is mostly targeted on, because I [indiscernible] contracted, there's probably not much you can do on the cost side?

You know, Ben, I’ll just 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 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, it’s no question it was coming because we were in 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 frontline back, because it's really the frontlines 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 the game. So we really began the project in earnest in October but it’s been designed with true frontline employee participations, 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 been doing both at 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 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, and companies have ways of getting things done and they are 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 Officer, Phase 4 is really, really getting after even more technology. You all know because 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 Phase 3 of what’s been a journey for us.

Okay. Thanks for that. 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 other parties or is there something you see in these projects that could give you a great edge?

Yes. Remember 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 renewable. So on a cost of capital basis I don't think we’re disadvantaged at all. And where we have the advantage though with these projects is these early calls are going to require you to be able to hook up to A, already have transmission access, and B, be operational by 2019, which means you already had to done all your work and you have to able to bid in the 2017 timeframe and build in the 2018 timeframe and come online. So, these first projects that we have here all shovel – when we say shovel ready they are ready to compete in that case. So I’m sure there’s others that have those. And you know, 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 projects – there’s 5,000 megawatts coming and rather get a good return at the right time and 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’ve build 500 megawatts in Windsor and 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 them.

Okay. All right. Thanks. Thanks everybody.

Thank you.

Your next question comes from the line of Andrew Kuske. Please go ahead.

Thank you. Good morning. Just wonder just when you think about the corporate structure of TransAlta, when you obviously got number of assets sitting at TransAlta at the top of the house legacy call and then you’ve got TransAlta renewable. 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 curve than a renewable curve, I mean, frankly as you probably picked up the sooner we do the transitions and the conversions we become TransAlta renewables, so its right now TransAlta renewables, its gas and renewables. But remember TransAlta renewables is an entity, it has the contracted stable cash flow, the cash flows that you feel pretty confident about paying a pretty high dividend out. So it is yield cure we pay a lot of the cash out of that vehicle. Now we own 64% of it and lot of that cash comes back into TransAlta and is available for distribution either to grow searches or to the balance sheet. So in the short term we’re making sure the balance sheet is strong and also having -- we have enough cash there to participate in some of the growth project. But as we look out over time I think really did two vehicles offer something a little bit differently to different kinds of shareholder. Renewables will tend to be for the shareholders that want a dividend and really stable our cash flow and even when we have the capacity market here and we’ve got our conversion done there’s still be volatility in the cash flows in TransAlta, so that’s more of a gross 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 capital allocation in the Alberta market in the front-end on unrelated conversions, the gas conversions, I think some of commentary echoed a little bit of this theme of the drilling activity in Alberta BC, predominantly chasing liquids. Bit wind up in a very advantages gas price environment which overall could be very interesting for someone like yourselves from a power more price deliverability at the end. Is that something you just see really is stability in power pricing and really good gas market from a developer standpoint?

Yes. I would say that, when we look it, as you know trends don't last forever. But there’s certainly currently an oversupply and potential to oversupply gas in almost every marketing in North America and in the North Eastern gas, you know when you look in the Northeast BC and you look in northern Alberta there is just tons and tons of gas and its not getting out of here by LNG, its getting blocked into the basin. So that's exactly we’re taking a bet that that we would rather take advantage of that gas being in the market early then hope that it's there in 2030, because frankly we can't see six months, nevermind 30, 2030, so that’s a big big big piece of the play. And also if you look at our plants, they'll run you know quite a bit better on gas than they run in half the capital. And if you just wanted to put in a really simple term, if you were making the bet and someone said you have to put $250 million of additional compliance costs and to coal plants to run them for another 10 years or you can put 300 million, 50 million more and converted them to gas at a timeframe when we think gas prices are going to be well and you’re going to be more competitive. How would you take that bet? And you spent half the capital after that. So, it was actually a pretty simple decision after we did 10,000 models and talk about it 10,000 time, but that's really what it came down to.

I won’t ask you same question 10,000 times. Thank you.

Thank you.

Your next question comes from the line Robert Kwan. Please go ahead.

Good morning. Just on the coal, the gas conversions, 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 following on that?

Well, I’m going to – just in terms of the engineering work we’ve done our kind of cost free estimate. Our teams have also spend quite a bit of time visiting other converters, so there is 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 it’s quite a moving frame here in terms of what Feds want. We know that overall the Feds are absolutely thrilled and ambitious about -- turns out to taking this action and taking it early, because truly I think they expected we’d to wait for a long time, but I think their 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 you’re conversion factors let’s say .6 5 or .7 you want to make sure the regulations holds you to that and that you don’t just like the equipment deteriorate and 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 always we can, because if they want to bring a lot of renewables into the market they don’t really want baseload gas conversions, they want to be more capacity plays. So John Kousinioris heads up our regulatory and he spent all his life doing this work. So he is going to give you some flavour on that.

Yes. All I can you – I think Dawn has actually covered it very well. We’re engage right now in discussions with the Federal Government and actually the Provincial Government as well on what the emission standards would be for converted units. I think those discussions have been multilateral in a sense of evolving umbrella groups from the industry and a number of companies, and also just bilateral in terms of having discussions between TransAlta and the government. But I can’t say, 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 reduction could be substantial, I mean, just even some of the preliminary modeling that we’ve done which are 40%, 40 plus percent emissions reductions, from the converted units as compared to the existing coal-fired generation on 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 the standard that is rigor and reasonably tight, yet also offers a flexibility to recognize kind of a full dynamic of how the units will be expected to run over a 10 or 15-year period probably moving is on from being more baseload oriented in the initial years to being units that all be more awkward in, I think in the later years as more renewables get in. So there’s still a process to go before the rules are actually develop but we wouldn't have preceded with the approach that we did – and the decisions that we did if we didn't think that the 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 in the coming weeks and months.

Yes. We just see that as regulatory risk when you're trying to making things.

Got it. To put it differently, you still need feds to move off of what they initially put out when they had the core release?

Yes. They do need to move off, but I think it was the .55 standard and I think they that restriction and that isn’t just TransAlta issue that an industry-wide issue. So the Federal Government wouldn’t have processed putting coal to gas conversions, our facilitating coal to gas conversions with the 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 at the right standard, .55.

Got it.

We don’t think it’s a right one.

And I think David get us to the right standard than have us stay on coal because they couldn’t get the right standard yet.

For sure. Okay. If I can finish just on Alberta wind, Dawn, last time you build a lot of capacity, you guys did a great job within Alberta, getting things done on time and actually 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?

Yep. Are you kidding? They are 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 wait for us to build another wind farm. So they had built in Alberta and then they went and built in Quebec and they build in New Brunswick. So yes, there’s a bunch of exciting guys down there that will have no problem re-engaging with.

Okay, great. And if I can finish on that topic. So, as you thinking about bidding these projects, and are you looking them on a standalone kind of project basis versus your hurdle rate or would you also assess the returns with potential upside to monetize those down into RNW?

You know, that’s probably competitive information. I’m going to talk about this one.

Okay. That’s fine. Thank you very much.

[Operator Instructions] Your next question comes from the line of Mitchell Moss [ph]. Please go ahead.

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

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

The other factor is also like carbon tax and will all the coal plant in Alberta we’ll convert to gas, so potentially there maybe 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 unit. So like there’s a lot of thing that happen between now and 2021 and clearly as go 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 liquid out of here, can do that. So it’s a real potential benefit here.

So, in terms of --’m not sure if I missed on some of the other call and some many other questions, but for the pipeline -- to get the pipelined sighting and pipeline access for the plant seem to be sort of the most long-term part of the conversion? And so, especially if you’re talking about sort of 2021 timeframe 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?

So the pipeline is kind of -- there are two options. If there’s a pipeline coming off the lines and there’s a pipeline coming off of TransCanada or there’s -- you see the one or the other or there is both that we’re in the process of having those discussions and you know we fit 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 build 165 kilometre gas pipeline in Australia from beginning to end in 16 months. So my view is our Canadian 50-kilometer pipeline should take 16 months if we are going to compete in international well, but unfortunately people tell us it takes about three years, so we are actually working to that timeframe 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 till 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 would be looking to see how to do that.

Okay, but so it sounds like you would need to start sort of – starting a project starting in 2018 I guess is in a year from now basically.

Yes as with everything in the world the discussions in the regulatory processes the long [ph] part, the actual building is not that hard. So, yes we did all our commercial arrangements have to be done within the next year.

And finally, just on the pipeline of 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 it at all, and we think that whole obligation would be for about eight years.

Okay. Great, thank you.

And the next question comes from the line of Jeremy Rosenfield [ph], please go ahead.

Yes, thanks, just a couple of questions. Just on the Australian solar project that was highlighted, Dawn you mentioned that you are I think far along in the process, it sounds like – can you talk about whether you are looking for a utility off-taker, mining off-taker some combination of one of 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 on your investment returns that you get on investing in solar renewal energy in Australia relative to sort of the in Alberta, experience under what’s coming in the RFPA?

Yes, I would say that so just in terms of the off-taker [ph] would be someone with a high credit rating, so it would be I don’t think we would have to put an additional risk metrics. If the off-taker happened to be somebody with a different credit profile we would put our return risk adjustment in there for that just like we have in other parts of Australian business, but right now what we are 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 direct 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 company pay in pounds rather than owning projects. So that’s our preferred off-taker. And in terms of the overall risk adjustments, 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 our risk perspective and a return perspective we would see those two 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 would see here.

So just to be curious you are 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 OESC settlement and how things were more booked in Q1 results the – what was the amount that was included in FFO was it the full amount flow through from EBTIDA 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 are 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.

Okay. Perfect. Thanks for clarifying, that’s it for me.

Thanks, Jeremy.

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

Thank everyone and that closes up the call. My team is available for questions after the call. Have a great day. Thank you.