FINAL TRANSCRIPT - TransAlta · FINAL TRANSCRIPT May 8, 2018 — 11:00 a.m. E.T. TransAlta...

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FINAL TRANSCRIPT

TransAlta Corporation

First Quarter Results Conference Call

Event Date/Time: May 8, 2018 — 11:00 a.m. E.T.

Length: 64 minutes

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TransAlta Corporation First Quarter Results Conference Call

CORPORATE PARTICIPANTS Sally Taylor TransAlta Corporation — Manager, Investor Relations Dawn Farrell TransAlta Corporation — President and Chief Executive Officer Donald Tremblay TransAlta Corporation — Chief Financial Officer John Kousinioris TransAlta Corporation — Chief Legal and Compliance Officer CONFERENCE CALL PARTICIPANTS David Galison Canaccord Genuity — Analyst Rob Hope Scotiabank — Analyst Mark Jarvi CIBC Capital Markets — Analyst Ben Pham BMO — Analyst Robert Kwan RBC Capital — Analyst Charles Fishman Morningstar Research — Analyst Mitchell Moss Lord Abbott — Analyst

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Patrick Kenny National Bank Financial — Analyst Jeremy Rosenfield Industrial Alliance — Analyst

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PRESENTATION

Operator

Good morning. My name is Chris, and I will be your conference Operator today. At this time,

I would like to welcome everyone to the TransAlta Corporation First Quarter Results Conference Call.

All lines have been placed on mute to prevent any background noise.

After the speakers’ remarks, there will be a question-and-answer session. If you would like

to ask a question during this time, simply press *, then the number 1 on your telephone keypad. If

you would like to withdraw your question, press the # key. Thank you.

Sally Taylor, Manager, Investor Relations, you may begin your conference.

Sally Taylor — Manager, Investor Relations, TransAlta Corporation

Thank you, Chris. Good morning, everyone, and welcome to TransAlta’s first quarter 2018

conference call. With me today are Dawn Farrell, President and Chief Executive Officer; Donald

Tremblay, Chief Financial Officer; John Kousinioris, Chief Legal and Compliance Officer; and Brent

Ward, Managing Director and Treasurer.

Today’s call is webcast, and I invite those listening on the phone lines to view the supporting

slides which are available on our website. A replay of the call will be available later today, and the

transcript will be posted on our website shortly thereafter.

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As usual, all information provided during this conference call is subjected to the forward-

looking statement qualification, which is set out on Slide 2, detailed in our MD&A, and incorporated

in full for the purposes of today’s call.

All amounts referenced during the call are in Canadian currency, unless otherwise stated.

The non-IFRS terminology used, including gross margin, comparable EBITDA, funds from

operations, and free cash flow, are reconciled in the MD&A for your reference.

On today’s call, Dawn and Donald will review the quarterly results and the outlook for the

remainder of the year. After these prepared remarks, we will open the call for questions.

So with that, let me turn the call over to Dawn.

Dawn Farrell — President and Chief Executive Officer, TransAlta Corporation

Thanks, Sally, and welcome, everyone. Today I’m going to start with some colour on how I

saw the quarter and how it’s affecting our view of the year, which is positive. And after that, Donald

will take you through the financials, and I’ll just come back at the end and give you a few brief

comments on our progress against our 2018 goals.

Now as you can see in our highlights, we reduced our net debt by close to $300 million, and

we delivered results for the quarter in line or slightly better than last year. After adjusting for onetime

positive cash flows in 2017 and 2018, our year-over-year comparable run rate to EBITDA for the

business increased by 8 percent and our free cash flow increased by 3 percent.

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These financial results are primarily due to strong performance from our US coal and our

Canadian gas segments, which more than offset the impact from the exploration of the Sundance A

PPAs at the end of 2017.

The first quarter performance and our progress on debt reduction are exactly in line with

the plans we laid out for you when we met with you early in December at our Investor Day.

Now some of you may be a bit surprised by the great Q1 performance from our US coal

team. As you know, we’ve always optimized the value of those assets in the market, so that’s not

really a surprise. But that team has done some excellent work, they’re highly competitive, and they’ve

been working hard to get a strong coal transportation agreement in place that adds value.

So that, along with the work they’ve done on their cost structure, allows them to … is

allowing them to make money on those assets, even when there’s lots of water in the Pacific

Northwest and even when gas prices are fairly low. So excellent work by that team.

Now as well if you look across the fleet, you’ll see that availability during the quarter was

93.9 percent compared to 88.5 percent during the first quarter of 2017. And I’m really pleased to

report that the Canadian coal segment led the improvement on availability. Their availability during

the quarter was 90.5 percent compared to 83.7 in the first quarter of last year.

Now their increase in availability was primarily driven by improvements in maintenance and

operating performance across their fleet. That team has really embraced many of the practices that

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we’ve all learned through our Greenlight program, and they’ve made a number of changes to a

number of processes and the way they do things.

Now they’re not finished all that work yet, but we are optimistic that their work is laying the

foundation for a new level of performance expectation for that fleet.

Now the Canadian team, coal team also been very busy laying out the Sundance Units 2, 3,

and 5 so they can be ready to bid as new capacity as that capacity market emerges. It was absolutely

the right decision to consolidate energy into Sundance Units 4 and 6, and to make sure that we can

deliver those megawatt hours at lower cost.

We were disappointed that a dispute has emerged between the MSA and the ISO over the

mothballing rules in what we’re calling the stub period of the energy-only market, which is really just

this small period now before the capacity market comes into play in 2021. However, we’re cautiously

optimistic that those two regulators will come to some sort of agreement on those rules to ensure a

strong functioning of the existing market. And we’re also confident that our current mothballed units

will be grandfathered under the old rules, as they did meet the test of those rules, including reliability

at the time.

Now while we are observing relatively modest spot power prices here in the second quarter

in Alberta, this is not unusual or uncommon, given the seasonal demand that we always see in April

and May. Demand will increase as we move into the summer, and we are expecting strengthening in

prices due to that growth.

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And things are, as you’re reading, things are getting a little more optimistic here in Alberta

with some of the oil price recovery.

We are also, however, seeing incredibly low natural gas prices in the market here. We have

some coal-firing capability, which is allowing us to utilize that gas and reduce fuel costs and our carbon

bill. And we also have strong water resource in our hydro assets.

So by optimizing natural gas and coal as fuel, with hydro and merchant generation we are

able to positively offset some of the capacity payments that we would’ve received in the past from

the Sundance PPAs. And it’s this capability that is helping us deliver cash flows in line or potentially

better than 2017.

Our progress on our Greenlight program has been significant. You saw that in our availability

outcome.

During the first quarter, we are in the last phase of our investment part of the program. So

that cost us approximately $11 million in the quarter. And those costs are finished as we go forward.

So as we go into the rest of the year, these costs are … the investment costs are behind us,

and the value that we’ve created by making these changes will start to be realized in a number of our

run rates.

We do continue to forecast 50 million to 70 million in cash savings from the program as we

go forward.

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So in my view, the quarter has us out of the gate well, and we’re positioned across the fleet

to deliver both contracted and uncontracted cash flows from our diverse assets, which are located in

a diverse number of markets.

So with that, Donald is going to take the time now to give you more detail on the financial

results.

Donald Tremblay — Chief Financial Officer, TransAlta Corporation

Thank you, Dawn, and welcome to everyone on the call. As Dawn noted at the beginning of

our discussion, our EBITDA, funds from operations, and free cash flow for the quarter were similar to

last year after adjusting for the early termination payment of the Sundance B and C PPAs in 2018 and

the settlement for the indexation dispute with OEFC in 2017.

As you can see from Slide 5, EBITDA of 259 million was 19 million higher than last year, an

increase of 8 percent. Free cash flow increased 2 million to 81 million, and funds from operations

totalled 161 million, a slight reduction to last year.

As you can see from the chart on the bottom left of Slide 6, segmented cash flow from our

power-generating asset, which excludes Energy Marketing and Corporate segments totalled 241

million during the first quarter, an increase of 26 million, or 12 percent year over year.

We successfully fully offset the impact of the scheduled expiration of the Sundance A PPA

at the end of last year, the higher fuel cost at Canadian Coal, and the termination of the Solomon

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contract in Australia, with strong result from US Coal, the contribution from South Hedland, and lower

capital expenditures.

The impact of a stronger price in Alberta was mostly offset by increased environmental

compliance cost in the province during the quarter.

There was no planned major maintenance during the first quarter of 2018, resulting in a

decrease of 22 million in sustaining CapEx relative to the first quarter of 2017. However, spillover

spending during the first quarter does not change our outlook for 2018, and we still expect to spend

between 195 million to 205 million in sustaining capital during the year.

Energy Marketing gross margin and EBITDA during the first quarter were much higher than

last year and totalled 17 million and 9 million, respectively, compared to 1 million and a loss of 4

million last year. Some of these gains in the first quarter will be realized in future quarters and are

not included in free cash flow.

Free cash flow was also impacted by certain mark-to-market losses that occurred at the end

of last year, but were realized in the first quarter of 2018.

Finally, cash flow from the Energy Marketing business is also impacted by the acquisition of

financial instruments to cover future positions.

Let’s move to our balance sheet and credit metrics. As you can see from Slide 7, we have 1.1

billion of available credit on our credit facility, a reduction of approximately 300 million since year-

end, as we drew on our credit facility to repay a portion of the 500 million US bond.

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In addition to our available credit, we had 329 million of cash on hand at the end of the

quarter, which includes 157 million received from the balancing pool on March 29th for the total

liquidity of 1.4 billion.

Turning to Slide 8. Our adjusted FFO to net debt has shown consistent improvement over

the past two years and is within our 20 to 25 percent target range at 20.9 percent.

Our net debt at the end of the quarter totalled 3.1 billion, a reduction of approximately 300

million during the quarter using the proceeds from the early termination of the PPA in Alberta, our

free cash flow, and a reduction in our working capital.

We are making great progress to strengthen our capital structure, and are ahead of our plan

to deliver FFO to debt at the end of our 20—at the end of our 25 to 30 percent range in 2021. We

expect to maintain our current debt level over the course of the year, even with more than 200 million

of capital allocated to coal-to-gas conversion and the construction of our two wind projects in the US.

Our capital allocation plan for the next three years will continue to strengthen our balance

sheet, improve our credit rating, and position the Company for growth.

With our results during the first quarter and the outlook for the year, we remain confident

in our ability to deliver at least 1.2 billion of free cash flow over the next three years, including the

157 million received this quarter and the further 56 million we are seeking from the balancing pool

for the early termination of the Sundance PPA.

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Given the performance of the business during the first quarter, we delivered more than 80

million of free cash flow. Our historical performance, the high level of contracted revenue, and the

contributions from uncontracted capacity in Alberta, assuming current forward price, we believe we

will achieve results at the upper end of our free cash flow guidance for the year. And we have

increased the lower end of our free cash flow outlook for 2018 from 275 million to 300 million.

Further, as discussed on our year-end earnings call, we initiated a normal course issuer bid

with the intention of using incremental cash flow generated by the business to reduce the number of

shares outstanding when we believe our shares are undervalued.

During the quarter, we acquired and cancelled almost 374,000 shares at the price below $7

per share under our NCIB for a total amount of 3 million.

Our capital allocation plan for TransAlta over the next three years is prudent, and we are

still evaluating whether to invest in the gas pipeline being developed by Tidewater to supply our coal

facility with natural gas. And we are advancing the preliminary engineering work on the conversion

of our coal facility to gas.

With the early termination of Sundance PPA effective March 31st, we have more exposure

to merchant power price. This deferred from our previous highly contracted position in the province,

and it impacts the way we manage these units.

In December, we announced our decision to mothball two of the four units at Sundance, as

it was uneconomic to run multiple units at lower capacity cycles. The other two units at Sundance, as

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well as our share of the output of K3 and G3 will be economically dispatched in the market. As you

can see on the graph update on Page 9, the expectation for pricing for the next three years is in the

range of 50 to $65 per megawatt hour, which is the strongest pricing we’ve seen in Alberta since 2014.

As prices have moved up during the quarter, we enter into some fixed price contract to

reduce our exposure and lock in margins. As we progress through the year and see power price—

sorry. As we progress through the year and see where power price lands, we expect to strategically

layer in additional hedge to further reduce our open exposure and lock in value for our shareholders.

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

Dawn Farrell

Thanks, Donald. So I’m going to take a couple of minutes here to comment on our progress

against our 2018 goals. They’re all outlined on the slide that you see on Slide 10.

And when you look at Slide 10, you see that our first goal for 2018 was really about

supporting the development of a fair and equitable capacity market. And everybody here is working

hard on that.

The second draft, as many of you know, of the comprehensive market design was recently

issued by the ISO. And while the design is still a work-in-progress, we are pleased that progress

remains on track, and that feedback is being incorporated by the ISO as players work with them. One

of the key issues for us is the Government of Alberta’s commitment to treat new and existing assets

equitably, and we remain very confident that they will honour that commitment.

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So when we look at the specific changes proposed in Draft 2, there were changes to the

demand curve which we viewed very positively, and we do believe that that reduces price volatility,

which is important for customers. Additionally, we were very, very supportive of the changes that

were made to the penalty regime because companies like us that have larger fleets will be very much

able to manage our fleet well within that.

Now there’s always a number of areas that need agreement before we’ll be really confident

that the market will attract capital. And that’s both capital—we see the capital that you need to

maintain existing generation and the capital that you need to build new generation as the same kind

of capital. So I want to talk about what we see are the two most important aspects of the new capacity

market, and then we’ll leave most of the details, if you want to talk about it in the Q&A.

So if I was to rank the top two issues that I think are important, the first one that we have

to get right to have a good functioning capacity market here in Alberta is the concept of CONEs. And

CONEs stands for cost of new entry. And it’s the number one building block of a strong capacity

market, and it is a calculated metric that goes into how you think about how you bid in that market.

Now in Alberta, we know that the new entrant will be a simple cycle gas-fired peaker. And

the development of the cost of that new entrant needs to reflect the actual financing conditions of

building a new peaker in a merchant market such as what will be here in Alberta.

In our view, that’s a generator that will have a much thicker equity component to it, and it

must have the right returns to reflect the risk that comes along with having to win a new contract

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every single year for 25 years to make a return on that equity and to service the debt that will need

to be raised to support that capital investment.

Power generation continues to be a highly capital-intensive industry, and capacity will need

to earn returns if investors are going to show up to the market. So we are gaining confidence that the

discussion of this has been recognized by many of the market participants here, and I think a number

would agree with us that it’s critical to getting—if we get the net—if we get the CONE calculation

correct, it will create a more vibrant capacity market.

Now the second feature of a very strong capacity market is preventing subsidized generation

from impacting prices in both the energy and the capacity portions of the market. So for example, if

the existing 1,300 megawatts of REP contracts reduce capacity in energy pricing, it will absolutely

create an unlevel playing field.

So for Alberta to function properly and for investors to make decisions that will last over 15,

20, 25 years, we absolutely must know how these subsidized resources will be treated in the Alberta

capacity market. We are hopeful that the next iteration of the comprehensive market design will

address this important issue.

Now there are many other issues that are being discussed, including how costs will be

allocated between both the capacity and the energy market; whether or not shadow bidding or

economic withholding will be allowed in the energy market; the shape of the demand curve; the

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amount of procurement; and the allowable capacity that will be able to bid by each unit here in

Alberta, all important aspects of the market all making progress, and in my view, all very manageable.

So our view would be that getting the cost of new entry right as we come out of the gate,

and ensuring that investors are absolutely confident that prices will not be impacted by changes in

government policy over time for subsidized resources, are absolutely key to the success of a future

capacity market.

Our second goal was all about advancing coal-to-gas. Donald did talk about that in his

comments. I think the only thing I would like to add there is, first of all, the recent reduction in gas

prices to almost free in some days has given us a lot of confidence that converting our plants to gas

is really the way to go. And we’re seeing some impressive optimization value coming out of that.

Now the Tidewater team is a very impressive group, and their work on the regulatory, siting,

and stakeholder aspect of the project is very strong. We are hoping that they’ll have a way to get gas

to the plants faster than their current plan.

The co-firing opportunity is substantial for us, as we could use up to 30 percent of the fuel

in the existing plants before we’ve converted. So if they can just get the gas there, we can absolutely

start to use it. So hopefully they’ll find ways to speed up that pipeline.

On safety, our goal is a very tough one: a 20 percent improvement over last year, which

we’ve already got a pretty strong safety record. We did make it through the first quarter, and as of

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the end of April we are on track towards that goal. As many of you know, though, this will just take

daily relentless work and will take a lot of attention from our team.

I did speak about Greenlight earlier, so I am just going to take a minute to update you on

the two US wind projects that TransAlta Renewables agreed to acquire during the first quarter. Those

projects are expected to reach commercial operation sometime during the second half of 2019. They

do demonstrate our commitment to grow and diversify TransAlta Renewables’ portfolio with long-

term contracted assets, and that’s one of our primary goals this year.

The larger of the two projects is 90-megawatt wind development in Pennsylvania with a

strong 15-year PPA. Construction has started on this site. Still in the early stages; we’re clearing trees

and starting roads to prepare for the turbine pads.

The second project is the smaller of the two, 29 megawatts, and it’s in New Hampshire. It

has two 20-year PPAs, which are both strong. We are waiting for the results of the environmental

permitting approval appeal, and once that comes in, if it’s positive, then we would start construction

on that project sometime in August.

TransAlta Renewables will be funding these growth projects, creating long-term value for

their shareholders, and of course value for our shareholders, as we own 64 percent of that vehicle

and we have a large dividend coming from TransAlta Renewables that supports our financing plans.

Now when I put all of the actions together in the first quarter performance with progress on

the goals and I look at sort of the great week that I’m seeking week by week here on the operational

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performance, as well as the great week on—people are doing all of the work on Greenlight, I do think

that that is giving us more optimism in terms of our ability to hit our free cash flow goal, which is to

improve over last year.

Last year we achieved 328 million of free cash flow, right in the middle of our range. And as

we think about beating that goal, we’re looking at a number of factors, including the percentage of

free cash flow that is generated from contracted assets across a diverse fleet, our success in reducing

cash cost and increasing performance as we execute new practices throughout our operations, and

finally our ability to optimize around the volatility in the Alberta market with our uncontracted

merchant coal and our hydro assets.

So our assessment so far is that our free cash flow goal is becoming achievable.

Now that ends my formal comments. Before I conclude, I would personally like to thank Mr.

Donald Tremblay, who’s sitting across from me smiling, who announced just before our AGM that he

needs to return to Eastern Canada to get closer to his family.

I really do want investors to know that the four years that Donald has invested in TransAlta

have been pivotal to our financial strength. His leadership has been key in repositioning and reducing

our debt. And we’re all going to miss his energy, optimism, and sense of humour. And we’re sure that

he’ll occasionally come back to Calgary to visit, or we’ll just come and see him in Montreal.

We do have an executive search underway to find a new CFO. Luckily, the CFO that we had

in place before Donald joined us, Brett Gellner, is still here and he’s agreed to act as CFO in the interim.

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So many thanks to Brett who will continue to execute the financial plan that Donald has put in place

and that we put forward to you on Investor Day.

So with that, I’m going to turn the call back over to Sally for questions. Thank you.

Sally Taylor

Thank you, Dawn. Chris, could you please open the call up for questions from the analysts

and media?

Q&A

Operator

Certainly. As a reminder, if you would like to ask a question, press *, followed by the number

1 on your telephone keypad. Again, that’s *, followed by the number 1 on your telephone keypad.

Your first question comes David Galison from Canaccord Genuity. Please go ahead.

David Galison — Canaccord Genuity

Good morning, everyone. So my first question is on the hedging. And so you’ve talked about

layering in hedging throughout the year, depending on how the market evolves. Just wondering, what

portion of exposure are you comfortable with or are you targeting throughout the year? And maybe

as you see the market evolve, how would you look at hedging post-2018?

Dawn Farrell

Go ahead.

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Donald Tremblay

So we need to be very flexible, and depending at—like we have generations. That generation

has a certain variable cost. And depending on what is the price forward, like that’s what we’re

basically looking to hedge.

So currently I would say like a significant portion of our baseload is hedged for this year.

What we’re price optimized now is basically it’s the excess over the baseload, and we are managing

the unit accordingly. So for example, in May you will see lower generation from our plant, and we’re

basically almost fully hedged for the month of May.

David Galison

Okay.

Donald Tremblay

But during the summer, probably the price will be higher, so we’ll probably have a bit more

length. So that’s the way we look at this. So it’s very similar to what we are doing in Centralia in terms

of dynamic hedging and basically managing what we call a delta position.

Dawn Farrell

Yeah. And we do have the authority to hedge into 2019, so if we see prices in 2019 that we

think are good to take off the table, we can do that. And then when we get there in real time, we may

or may not have to run the plant, so we really are treating it more as a dynamic hedging strategy

rather than what you would have seen in the past.

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David Galison

Okay. And my second question is just on the Tidewater pipeline. You had mentioned that

you’re looking at making that investment or potentially an investment. So I’m just wondering how

you’re viewing that and what it would actually take for you to make the—to exercise the option and

make the investment in the pipeline?

Dawn Farrell

So the way Tidewater’s set up today is right now we’re working with that team and they’re

making the investment in the pipeline. And they’re doing all of the work to get all the regulatory, the

siting, the stakeholder work, get it built. We would have an option, if we wanted to, to actually come

in for a portion of that investment up to 50 percent. We haven’t made that decision yet.

Key for us is just to get the damn pipeline built because once it’s built, we can then start to

utilize that gas in our plants and we can actually displace some of the coal, which really reduces cost,

especially in today’s gas price environment, and also reduces the carbon bill. So it’s kind of two—first

of all, the pipeline is on its way to going ahead, and as long as everything goes well with them and

they get the regulatory approvals, it will be built.

The second decision is whether or not we want to own a piece of it. And then we’re kind of

pushing hard now to say, okay, is there any way you can go faster, which is always hard to do because

there are pretty—they have to go through the regulatory process. But clearly I think gas producers

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here in Alberta should be cheering and helping us along here because they need to get some of their

gas utilized here in the province.

David Galison

And so my question was actually on the second option, which was you taking a piece in it,

so what your thoughts were around making the decision to take the investment?

Dawn Farrell

Yeah. Well, I mean, once we get clear that we’ve got all the regulatory approvals and the

pipeline is in place, we’ll make that decision then—

David Galison

Okay.

Dawn Farrell

—whether or not we do that.

David Galison

And then just my last question was around the carbon tax in Alberta. Can you give a little bit

of colour about what the impact was for the quarter?

Donald Tremblay

Well, I would say it’s pretty neutral in the sense that basically higher compliance costs, but

higher revenue and one offset the other in Q1. We believe Q2 will probably be a bit better—or actually

Q3 during the summer. But I would say during Q1, it’s basically neutral.

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From our perspective because most of our carbon tax during Q1 was under … like units that

are under PPA and it’s a pass-through, if you ask the question to the PPA owner, they’d have a

different answer. But from our perspective, it’s either pass-through and the merchant, we have been

able to basically price that increase to offset the carbon tax.

So I would say neutral.

Dawn Farrell

Yeah. Just remember, you have to look at it—you almost have to think about the carbon tax

as being in two buckets. Under the existing PPAs, the PPA buyers pay the carbon tax. They dispatch

the units, and depending on how much they dispatch the units is what their bill is.

For our merchant plants, only if we see prices that recover the carbon tax and give us some

profit will we dispatch those units. So we’ve got to be able to pay for the carbon tax, pay for the fuel,

pay for all the variable costs, and make a bit of a return for us to dispatch the units.

So we’re in control of how much we pay there, depending on what prices look like.

David Galison

Thank you very much.

Operator

Your next question comes from the line of Rob Hope from Scotiabank. Please go ahead.

Rob Hope — Scotiabank

Good morning, everyone, and all the best in your future endeavours, Donald.

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Donald Tremblay

Thank you.

Rob Hope

Maybe a broader question. Just in terms of capital allocation, how do you view your

potential opportunity set, whether that be the Tidewater pipeline, solar at Centralia, or US Northeast

wind versus the returns you’d be afforded through your NCIB? And then secondly on that, have you

been using your NCIB in Q2 so far?

Donald Tremblay

We haven’t used it in Q2 because we’re currently in blackout, so we will be able to restart

using it at the end of this week I suspect.

On capital allocation, priority’s still debt repayment, so that’s number one, and that’s

basically the priority of our capital allocation. The coal-to-gas conversion is important. We’re investing

for the future of that business, so that goes second. And the excess cash is basically share buyback.

So that’s what we said in January when we announced that program, and that’s the direction

we’re taking.

Dawn Farrell

Yeah. So just remember, the US Northeast wind farms are going to be funded and financed

out of TransAlta Renewables, not out of TransAlta, so that’s not taking away from the financial

capability of TransAlta.

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The solar would be the same. It would require a long-term contract, and it would be a

TransAlta Renewables resource.

The pipeline we’d have to think about that. It depends on what the returns would be. And

as you know, we’ve been very clear that we think the returns on buying back TransAlta shares are

very high. So that might be a project that could end up in TransAlta Renewables, and we have to

decide if we’re even going to do that because we really have to think about our capital allocation.

As Donald said, the highest-returning project for sure in the portfolio is extending the life of

the coal plants on gas. As many of you—probably everybody’s forgotten, but those coal plants were

slated to start shutting off by 2025 in any event. So the fact that we’ve now been able to get the

legislation federally and provincially to convert them to gas takes them well into the 2035 time frame.

And it’s a small amount of capital for a long set of cash flows.

So that’s by far our best investment in the fleet, and definitely it’s a better investment than

buying back our own shares.

Rob Hope

Very true. All right. A Q1 question. Just taking a look at the Energy Marketing, your

comparable EBITDA versus the Energy Marketing cash flow which was an outflow during the quarter,

can you give some colour on the unrealized gains of 27 million that are sitting on your book right now

when those could be realized? And then secondly, how much realized losses was in comparable

EBITDA in Q1?

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Donald Tremblay

So what I would say, when I’m looking at the 25 million, 27 million that we have in free cash

flow for the Energy Marketing, I basically have three buckets. And it’s probably a third, a third, a third

between mark-to-market gains that will be realized in the future between losses that we incurred at

the end of last year that realized during the quarter and acquisitions of financial instruments for the

future that we enter into in Q1.

So that’s the way I characterize the outflow there.

Rob Hope

All right. Thank you for the colour.

Dawn Farrell

So going to that—to answer the question of which period, I’d say it’s probably two-thirds

2018 and a third 2019 for the realization—

Donald Tremblay

Yeah. I’m not sure where they are exactly—

Dawn Farrell

—yeah.

Donald Tremblay

—those positions, but it’s ‘18 and ’19—

Dawn Farrell

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It’s ‘18 and ‘19. More weighted to 2018.

Rob Hope

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

Operator

Your next question comes from Mark Jarvi of CIBC Capital Markets. Your line is open.

Mark Jarvi — CIBC Capital Markets

Good morning. I just wanted to go to the Canadian Coal segment. There was some

commentary that by Sun 1 and 2 coming offline that was a $12 million decline in EBITDA. But I think

it’s 26 million year over year. So in your comment just a minute ago saying that you’re kind of neutral

on the carbon taxes, so where is it in the cost profile that you’re seeing that drop on EBITDA? And

then as you take more units offline, where’s the cost profile heading as you spread fixed costs across

lower generation?

Dawn Farrell

Well, remember there’s a lot of work being done at the Company to reduce fixed costs so

that we effect—we’re not holding the same fixed costs as we had with six units and then trying to pay

for them with two units. So we’ve had a massive amount of readjustment of that business to get it

down to two units that can kind of stand on their own. So that’s number one.

And then number two, the same with the mine. So the mine is being resized as we speak to

a much lower volume of coal, and then of course as we get a pipeline in there that’s even a lower

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amount of coal. So it’s making sure that we have that sort of dual fuel flexibility until we actually do

the conversions.

So it’s really how we’ve resized the cost structure to the number of plants out there that’s

allowing us to then make sure that we can be at the same level of free cash flows last year or slightly

better, which is our goal.

Mark Jarvi

And maybe you can comment in terms of the timing on the resizing of the mine versus fixed

operating costs? And sort of how those compare in size? And when those sort of will be realized in

terms of the cost-savings initiative through ’18?

Dawn Farrell

Yeah. So they’ve—it’s not an easy thing to do to just turn a mine from 12 million tonnes to

6 or 7 million tonnes. It’s not an overnight thing. So it’s going to … we think it’ll take about 12 months

to get to the exact size that we need it to be with the right costs. So they’re scaling it down as we go

through the year, and of course we’ve got to manage that. And at the same, it’s an uncertain time for

our people, so we’ve got to do it in a way that we keep people working and keep training people and

all the rest of it. Because all else being equal, people would rather go up north and work on one of

the mines at Fort Hills or something like that.

So we think by the middle of next year we’ll have that appropriately sized, and if the guys

can go faster, you’ll see that in our results sooner as we go towards the end of this year.

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Mark Jarvi

Okay. Good. And then—

Dawn Farrell

But I think cash flow estimates that we’ve given you account for that, account for that scaling

issue. So we’ve built in the costs as we go forward here.

Mark Jarvi

Right. Okay. And then just looking at the results of the US Coal, which again were quite

strong this quarter—you talked about it in your prepared remarks—where do you think that business

could deliver in terms of EBITDA or free cash flow on a full year basis?

Dawn Farrell

We don’t normally give that guidance.

Donald Tremblay

We don’t give guidance, but the way I’m looking at US Coal is basically like 30 million to 50

million. If you look at historically what it performed, it should continue to perform and improving over

time because of the significant improvement they’re doing on their fuel supply. So those guys are very

creative.

Dawn Farrell

Yeah.

Donald Tremblay

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The way that they basically set up contracts with the BNSF and the coal supplier to make

most of their—some of their costs link to natural gas and make the unit more flexible, and running a

bit more often, so creating a bit of more margin.

Mark Jarvi

Okay. And then my last question, in the MD&A it talks about potentially securing about 300

million to 400 million of debt. Is that related to coal or off-coal monetization? Or is that some project-

level debt at some of the assets at RNW?

Donald Tremblay

Could you repeat the question? Sorry, I missed the question.

Mark Jarvi

I think in the MD&A it talks about to cover the maturities in 2019 you’re looking at raising

about 300 million to 400 million of debt. I’m just wondering if that’s—

Donald Tremblay

Yeah.

Mark Jarvi

—from off-coal monetization? Or is that project-level debt on some of the RNW assets?

Donald Tremblay

It’s the off-coal monetization.

Mark Jarvi

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Okay. Thanks. And all the best as you transition there, Donald.

Donald Tremblay

Thank you.

Operator

Your next question comes from Ben Pham of BMO. Your line is open.

Ben Pham — BMO

Okay. Thanks. Good morning. I also wanted to wish you the best as well, Donald. First

question on guidance revision there and wondering on it’s quite early in a year; it looks like the

commentary was Q1 was in line with expectations of a positive tone. And I may have missed this in

your earlier remarks, but was there some layering of hedges that you were putting on for the rest of

the year that probably reduced a lot of the variability in the remaining portions of your business on

the—

Dawn Farrell

Yeah.

Ben Pham

—Alberta coal side?

Dawn Farrell

Yeah. I would—

Ben Pham

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Yeah.

Dawn Farrell

I would say, Ben, that just in terms of how we’ve looked at the year and how it’s going to

play out, first quarter was a little bit better than we expected from a free cash flow perspective. And

we’re seeing that strength continue as we go forward here. And as well as we look at—remember,

we’re kind of gaining experience with optimizing our assets as we go through April here, and turning

plants on and off and bidding them into the market and looking at our ancillary services and hydro

and all that sort of stuff. And basically getting the cost structure right and being able to optimize is

what allows us to continue to have a run rate of free cash flow that in prior years which would have

been effectively guaranteed by capacity payments.

So as we’ve looked at that and looked at the forward market, that’s where we think that our

bottom end could’ve come up and kind of puts you in … now puts you in line with where we were last

year, and then our goal is to see if we can get a little bit above that.

Ben Pham

Okay. And then on Rob’s question about buying back stock with the blackout commentary,

I wasn’t clear, is the expectation that you would be buying more stock then?

Donald Tremblay

The expectation is that we will buy stock over the course of the year when we believe that

there’s value in the stock.

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Dawn Farrell

Yeah. And—

Donald Tremblay

And that’s not the first priority with our capital. The first thing is we are focusing on our

debt, we’re focusing on our growth, we need to allocate capital to our conversions, and residual cash

will go to basically share buyback. So we’re not changing course on this.

But clearly as prices are below our threshold, we’ll acquire probably some share in Q2.

Dawn Farrell

Yeah. And I think we were pretty clear when we announced that program that as we see

cash flows being at the more positive end of our guidance at the higher end, then we can allocate a

little more capital to that.

Ben Pham

Okay.

Dawn Farrell

And we haven’t changed our view on that. You saw us do a little bit of purchasing in the first

quarter, but it was moderate, right? But as we go through the year as we gain confidence in where

the cash flows are at, then I think we’ve got a little more flexibility.

Ben Pham

Okay. Sounds good. Thanks for everything.

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Dawn Farrell

Thanks, Ben.

Operator

Your next question comes from Robert Kwan of RBC Capital. Your line is open.

Robert Kwan — RBC Capital

Morning. Just wanted to come back to the capacity market framework design. And I know,

Dawn, I think you touched on penalties. I don’t think you touched on this—and I apologize if you did—

but just with respect to market power mitigation on the supply side just your thoughts on what’s

there, and I guess more specifically, do you expect to be mitigated?

Dawn Farrell

Well, I think the way that the design currently works, almost everybody is mitigated. So I

think there’s a bit of a—in the discussions that are going on in the current CMD, if you do all the

calculations—and it’s the most complex thing I’ve ever seen. I mean, I’m going to—as you know, I’m

a hack economist, and even as a hack economist I can barely understand what they’re talking about.

But I think at the end of the day it mitigates 70 percent of the market the way that it’s being calculated,

which isn’t going to be an effective market for creating a capacity price.

So I would expect that as we go from CMD 2 to CMD 3, there’ll be a lot of discussions about

what that looks like because I think if you mitigate everybody, I mean what are we doing here?

Robert Kwan

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Right.

Dawn Farrell

It’s not really a market, right? So I do think there’ll have to be some movement on that.

Robert Kwan

Okay. Would you, just given the amount of capacity you’ve got, though, even if there is a

change and it’s a lower percentage, do you think that it’s reasonable that it’ll end up in a spot where

you won’t be mitigated?

Dawn Farrell

No. I think TransAlta will definitely be mitigated because of just our total sheer volume of

capacity that we have in the market. I think it’s just whether or not the rest of the market—if we’re

the only ones that are mitigated, then effectively the price will probably be set at the right level, right?

Robert Kwan

Right.

Dawn Farrell

Because it won’t be us that’ll set the price; it’ll be the other 70 percent or 75 percent of the

market that will set the price. But if they come up with a formula where they actually mitigate 70

percent of the players and the 30 percent that are left are trying to set price and there’s only a couple

of them, that won’t work either.

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So I think definitely it will be mitigated, but it doesn’t mean—remember, everybody

misinterprets that and they think because we’re mitigated, that’s the price we get. Not true.

Robert Kwan

Right.

Dawn Farrell

So let’s say we were mitigated at—I would be surprised if it stayed at the 0.5 and this current

RSI thing that they talk about that doesn’t make any sense to me. John Kousinioris maybe understands

it; he’s sitting here. But I think when they get those calculations correct, at the end of the day they

really need 70 to 80 percent of the market to be setting price, and then of course we get that price,

whatever that turns out to be, as it crosses the supply and demand.

Robert Kwan

For sure. And I guess as it relates to mitigation, do you have issues with the asymmetry and

the lack of buyer-side mitigation?

Dawn Farrell

The lack of buyer side. John, do you want to talk—I …

John Kousinioris — Chief Legal and Compliance Officer, TransAlta Corporation

Yeah. We haven’t … I mean, we haven’t really been focusing much on that, to be honest,

Robert. It hasn’t been a major focus for us. Our focus has been primarily on the supply side, and

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Dawn’s been articulating that. And our focus has definitely been on the 0.5 of net CONE that people

that would be offering supply would be mitigated to to be honest.

Dawn Farrell

Are you thinking about buyer’s bidding capacity into the market as solid capacity, that kind

of a thing?

Robert Kwan

No.

John Kousinioris

No.

Robert Kwan

Just when you’ve got a net buyer of power who might have some incentive—

John Kousinioris

Yeah.

Robert Kwan

—to do something else with the capacity price, and we’ve seen in other markets an

introduction of buyer-side mitigation to prevent that activity.

John Kousinioris

Yeah.

Dawn Farrell

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Oh, okay.

John Kousinioris

Our sense right now as it relates—at least on the work that we’ve done here in Alberta; not

to discount that issue—but it hasn’t been sort of the principal focus that we’ve had. It’s definitely

been on the supply side.

Dawn Farrell

And it’s pretty small.

John Kousinioris

Yeah. It is relatively small.

Robert Kwan

Got it. And maybe I can just finish. You’ve given some thoughts on power pricing. Just

wondering if I can get a little bit more colour here? Obviously we’re in a shoulder period, so that

certainly is a piece. Do you think that really as you look at your power price outlook that we might be

seeing or you expect to see more volatility than you might have thought as we get through the year,

just given we come into April we’ve seen a little bit of actually quite high amount of volatility for a

short period of time. But then since then it’s been pretty low vol, and in fact, putting up a bunch of

zeroes like this morning.

Dawn Farrell

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Yeah. Yeah. So I mean, honestly, in the shoulder period you’re going to get low prices and

volatility in the negative direction, right? And I would expect as we go into the summer you’ll—I mean,

there’s no question that the Alberta market should have more volatility in it, period, going forward.

It’s just the way that the market works, so that’s how as we’re doing our dynamic hedging here that’s

mostly what worked.

What we’re looking at is how to position around that volatility, but we do expect more as

we go into the summer.

Robert Kwan

I guess just have you been surprised with the amount of capacity that you’ve got back, the

demand growth, and then the mothballed units that the price has been as low as it’s been?

Dawn Farrell

No. No, I haven’t been surprised at all.

Donald Tremblay

Like April and May are never solid months in terms of pricing. July, August, September will

be the true test.

Dawn Farrell

Yeah.

Robert Kwan

Perfect. Thank you. And, Donald—

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Dawn Farrell

So with the markets behaving as we would have—yeah.

Robert Kwan

Okay. Donald, best wishes with the move back home.

Donald Tremblay

Thank you.

Operator

Your next question comes from Charles Fishman of Morningstar Research. Your line is open.

Charles Fishman — Morningstar Research

Thank you. Dawn, I only had one question. Does the disputes with Fortescue have any

impact on your thinking with respect to the amount and timing of the share buyback? And do you

need to have those resolved before you go in the heavier amounts of buyback?

Dawn Farrell

No. No, that doesn’t impact our thinking on the share buyback at all.

Charles Fishman

Okay. Thank you. That’s all I had.

Operator

Your next question comes from Mitchell Moss of Lord Abbott. Your line is open.

Mitchell Moss — Lord Abbott

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Hi. Just a couple questions. Looking at the Sundance Unit 2, what type of prices would you

want to see either in the forward markets or I suppose in a capacity market that would cause you to

bring the plant back online?

Dawn Farrell

Well, it’s a combination of price and volume, right? So you’ve got to see—the big challenge

in the Alberta market is it’s fundamentally got a lot of capacity supply in the market, and there’s no

capacity value for these units. Like no one will pay you—the ISO is not going to phone us tomorrow

afternoon and say, here’s a capacity contract to bring that plant back for a couple of years because

we need the capacity. So it really has to make it on the energy sales.

So it’s really if we were running 4 and 6 at 80, 85 percent capacity utilization and we could

see another 50 percent capacity utilization to start that unit back up, we would think about it then.

But right now we actually make our money by dispatching up the unit to a higher capacity utilization

versus starting another unit. You got to remember with these units, the heat rate is the best, so the

efficiency of burning fuel is the best, and the carbon tax is the lowest when the heat rate is in its best

position, which is at a higher capacity utilization.

So our whole strategy is fill those units up first, and then only if you can see a pretty good

amount of gigawatt hours needed in the next unit, add a good heat rate, which you start to say, okay,

it’s time to bring that unit back.

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So it’s a combination of price and volume. And right now we aren’t seeing the need for these

two units, and they’re not running at 85 percent capacity utilization.

Mitchell Moss

Okay. But I guess under a capacity … with a capacity market set up, does that thinking change

in terms of—

Dawn Farrell

Yeah.

Donald Tremblay

Totally.

Dawn Farrell

Yeah. Absolutely. So remember, these are mothballed under the energy-only market rule,

which that’s what we set them up under. And they’re absolutely being set up to be competitive

capacity supply into the capacity market.

So those bids, I think, will go in sometime in 2020. And all of these units will be bid in to the

capacity market. That makes a huge difference.

Mitchell Moss

Okay. And just following up on the last set of questions, when you talk about volatility, how

are you guys thinking about volatility in the Alberta market, I guess, currently versus post-capacity?

Because looking in other power markets in the United States, having a capacity market can at times

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reduce energy price volatility, just because there’s sort of a floor of excess available or available

standby capacity.

Dawn Farrell

That’s right. Yeah. So for sure in an energy-only market, if you don’t have volatility and you

don’t have extremely high-priced hours, you can’t make a capacity payment for the units, right? So

there is a lot more volatility in an energy-only market that’s designed properly. When you go to a

capacity market, if you get the market set up correctly and you bid your capacity contracts, you make

your returns effectively on the capacity side of the market, and on average you make a variable cost

or a slight margin to that, depending on which unit you’ve got in the energy market.

So for our units, for example you talked about Sundance Unit 2, that’s a great capacity

resource. It’s not really going to be all that necessary to run, but it’s a great standby capacity resource,

especially as you bring 5,000 megawatts of wind into the province because all that wind has to be

backed up.

So you do absolutely expect less volatility in a capacity market, which is the promise to the

consumers because all else being equal, consumers like less volatility. But the way we make our

money is how we get it out of the capacity market. So we don’t mind that there isn’t that volatility.

Mitchell Moss

Okay. And just on a housekeeping item, the capital allocation slide. I didn’t see it from Q4

that it sort of shows 1.4 billion of bond repayment uses and dividend of 100 million and so on, and

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sources and uses. I didn’t see that in this presentation. I’m not sure if it was discussed because for

some reason my call got disconnected. But are you guys still seeing the capital allocation plans in

terms of 1.2 billion of free cash flow, using 400 million of liquidity, and so forth, kind of matching that

allocation plan that you put out a couple months ago?

Dawn Farrell

Yes. The slide is exactly the same as a couple months ago, and Donald did make comments

about that and said exactly that. So it’s exactly where we were.

Mitchell Moss

Okay.

Donald Tremblay

There’s no change to our capital allocation.

Dawn Farrell

No change. Yeah.

Donald Tremblay

No change at all. And in fact, we’re advancing because out of the 1.4 of bond repayment,

we repaid 500 million US, 600 million in Canadian in March of this year.

Mitchell Moss

Okay. Okay. Great. And so you already used some of that. I guess it kind of looks like you’ve

used some of the liquidity, so to speak. So, I mean, is that more of a seasonal volatility because given

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that your liquidity’s come down in terms of capital allocation? In other words, should I expect the

liquidity to come back up over the next year or two? Or is this sort of you’ve kind of taken that 400

million of liquidity that’s been used and then the remaining sources, call it 1.7 billion, those are still

going to be to be realized, I guess, over the next year and a half?

Donald Tremblay

So what you will see us doing over the course of the year, we will do some financing activity

that will replenish our liquidity and—

Mitchell Moss

Okay.

Donald Tremblay

—we basically—our next scheduled repayment is 400 million Canadian in November of

2019, so now we have roughly 18 months to rebuild our liquidity to repay that maturity. And we’ll do

this through financing of some contracted cash flow and free cash flow from the business over the

next like 18 months.

Mitchell Moss

Okay. Great. Great. Thanks so much. Good luck, Donald.

Donald Tremblay

Thank you.

Operator

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Your next question comes from Patrick Kenny of National Bank Financial. Your line is open.

Patrick Kenny — National Bank Financial

Yeah. Good morning. Just with Battle River 5 coming off PPA in the fall, does that accelerate

your plans at all to bring in a second pipe into Sundance? Or perhaps go ahead and support Tidewater

building its pipeline to the full capacity?

Dawn Farrell

Yes. I mean, both of those … the teams are working on both of those outcomes for sure. As

you know, just watching the gas prices here, there’s a lot more upside potential. So the team is

working on a second pipeline. There’s two potential opportunities there—well, actually three because

we could do another one with Tidewater, and then there’s the adding compression to Tidewater. So

all of that is in discussion and underway right now.

Patrick Kenny

Okay. And then just on the fuel mix as well without full CTG conversion. I know you’ve talked

about in the past one-third gas, two-thirds coal ratio as kind of a good ballpark for Sundance and

Keephills, but recently we’ve seen some higher ratios at some other coal plants. So just wondering

given how low gas prices are if you’re finding new ways to increase the amount of gas that you can

put into the boilers?

Dawn Farrell

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Well, the engineering teams are always looking at that. We use the 30 percent as just a

broad ratio that we think about as we look ahead and do planning. But for sure if there’s ways to

increase the capability, and remember, these plants are all designed individually one by one and built

one by one, so they do have different set points for that.

But the engineers will, if there’s a way we can use more gas in a boiler if we’ve got it, they’ll

be doing that as well.

Patrick Kenny

Okay. That’s great. And lastly, all the best, Donald, back east. Just maybe one last question

before you go, and that’s with the transition to a capacity market likely being viewed as a net positive

from the credit rating agencies, just wondering what your view is on the optimal credit ratios heading

into next decade?

Donald Tremblay

Yeah. So I think we’re sticking with our plan. Like we really want to be in 2021 at 25 to 30

percent and at the upper end of that range. Capacity market is great, but there will still be some

volatility, and some years will be better than others. The good thing is you know that a year in

advance, so from a rating perspective that’s a positive because it gave you time to basically set your

balance sheet in accordance.

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But we are sticking with our plans at 25 to 30 percent FFO to that. The good thing, however,

is most of the corporate obligations of TransAlta will have been repaid, and the balance sheet will be

very strong in 2020 after we repay the 400 million due in 2019 and the 400 million due in 2020.

Dawn Farrell

Yeah. And I would just add, I mean the view of the management team here is that as we go

into 2020 with the capacity market, and of course we’ll have the hydro as well here in Alberta and

some wind and all the rest of it, that if you think about the recourse debt that will be left that’s in that

kind of 1.1 billion, $1.2 billion range, we think that’s about the right amount of debt for those assets

going forward.

It is a very counter strategy to the industry. The industry tends to over-lever merchant

assets. They’ll lever them up to 60, 70 percent. We are under-levering merchant assets because we

think that’s what you’re supposed to if they’re merchant even though they are, like you say, they’re

a little more stable because of the capacity market.

So I think the balance sheet for those assets will be very strong, and will carry the Company

through to 2020 very well.

Patrick Kenny

All right. That’s perfect. Thank you very much.

Operator

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Again, if you would like to ask a question, press *, then the number 1 on your telephone

keypad.

Your next question comes from Jeremy Rosenfield of Industrial Alliance. Your line is open.

Jeremy Rosenfield — Industrial Alliance

Yeah. Thanks. Just two questions. First on the transition into the capacity market and some

of the changes in CMD 2 allowing for smaller-sized units, I’m just wondering if you’ve looked at or if

you expect to start to look at the opportunity to put some storage solutions in with some of the

existing wind assets or on some other sites that you have in the province?

Dawn Farrell

We’re always kind of looking at that, but what we’re finding is our storage is actually the

cheapest storage you can have. It’s the storage that we have in our hydro, right, so that really works

well with our wind assets. And we continue to work hard on seeing if we can get going on a big storage

project with Brazeau because we’ve done a tonne of work on storage, solid-state storage, full

batteries, all that stuff.

Still quite a ways off. I mean, you can—if you want to subsidize storage in a massive way to

bring it into the system, you can do that. But if you want economic storage, it’s still projects like

Brazeau. So that is the best, lowest-cost way to bring storage into the province, and it would be our

first … it’s our main focus. And we’ve tried a million different ways to think about how to put a solid-

state battery in.

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But if you look at the economics of those, you’re getting a couple of—even if you get two

hours a day at a differential of $10 or even $20, you’re talking about $40 a day for millions of dollars’

worth of investments; you’re talking about like 20-year paybacks. We’re not interested in that. So our

current hydro is great storage, and then seeing if we can get Brazeau is more important.

Jeremy Rosenfield

Okay. So just looking at Brazeau, since you brought it up, where is the project in terms of

the development? I think in the MD&A it mentions that you’re spending a little bit of cash to advance

the development. And it looks like maybe some of the sizing or the cost numbers have moved around,

so what is the latest update maybe?

Dawn Farrell

Yeah. The latest—I mean, it still isn’t exact. We’re working here with the province and the

ISO and, well, really waiting to see if the province wants to support the development of a large hydro

project as part of their renewables goal. They’ve stated 5,000 megawatts; they’ve done calls now for

about 1,300 megawatts of wind. I think it’s really more of a policy decision if they want some of that

dispatchable renewables to come from projects like hydro, and we’re waiting to see them make that

decision and then determine some sort of competitive process for us to bring that project forward in.

We’re very much working hard with them to see if we can get that done before the end of

this year, but we’ll have to wait and see.

Jeremy Rosenfield

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Mm-hmm. Okay.

Dawn Farrell

And we’re just limiting our spending because, as you know, in the Canadian market if you

get too far where you keep spending money and you don’t get regulatory approval, or it takes four or

five years to get it, it’s not very economic.

So we’re just really sizing our spending to the regulatory environment.

Jeremy Rosenfield

No, I always want to stay on the middle of my skis. Just turning to the new wind investments,

do the assets right now—or sorry, there’s one that’s under construction—does that carry construction

debt already? And I assume the other one which is not under construction doesn’t have any debt?

Dawn Farrell

No. Right now, that’s just on—we have a credit line for RNW, and we’re just funding it

through there until we decide how to more permanently finance it.

Jeremy Rosenfield

I meant the construction, the asset that’s under construction, if it had debt already that you

were acquiring as part of the transaction?

Donald Tremblay

No.

Dawn Farrell

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No, no, no. No. No. No.

Donald Tremblay

No debt.

Dawn Farrell

No. No.

Jeremy Rosenfield

Okay. Perfect. So—

Donald Tremblay

—a second development.

Jeremy Rosenfield

Okay. Perfect. And then in terms of financing options, do you assume a tax equity

component for the permanent financing?

Donald Tremblay

That’s our plan.

Jeremy Rosenfield

Okay. And would RNW be the owner of 100 percent of the cash equity?

Donald Tremblay

RNW will hold an economic interest in the two projects—

Jeremy Rosenfield

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Right.

Donald Tremblay

—similar to what we did in the past. Yes.

Jeremy Rosenfield

Right. Okay. Okay. That’s it for me. Thank you.

Donald Tremblay

Thank you.

Operator

There are no further questions at this time. I’ll now return the call to our presenters.

Sally Taylor

Thank you, everyone. That concludes our call for today. If you have any other questions,

please don’t hesitate to reach out to myself or Alex at Investor Relations.

Thank you.

Operator

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

*****

FINAL TRANSCRIPT - TransAlta · FINAL TRANSCRIPT May 8, 2018 — 11:00 a.m. E.T. TransAlta...

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