TransAlta Corp (TAC) 2016 Q2 法說會逐字稿

Welcome to the TransAlta Corporation 2016 second quarter results conference call and webcast.

(Operator Instructions)

At this time, I would like to turn the conference over to Mr. Jaeson Jaman, Manager of Investor Relations. Please go ahead.

Thank you, Anastasia. Good afternoon and welcome to the TransAlta second quarter 2016 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; and Todd Stack, Managing Director and Treasurer.

The call today is webcast and I invite those listening on the phone lines to use the supporting slides which are available on our website. A replay of the call will be available later today and the transcript will be posted to our website shortly thereafter. All information provided during this conference call is subject to the forward-looking statement qualifications which is set out on the slide deck and detailed in our MD&A and incorporated in full for the purposes of today's call.

The amounts referenced are in Canadian currency unless otherwise stated. The non-IFRS terminology used, including comparable gross margin, comparable EBITDA, comparable funds from operations, comparable free cash flow, and comparable earnings are reconciled in the MD&A.

On today's call, Dawn and I will review the quarterly results made against TransAlta's goals and priorities for 2016. After these prepared remarks, we will open the call for questions. I will now turn the call over to Dawn.

Thanks, Jaeson, and welcome to everyone that has joined our call today. Today I am going to begin with some brief comments on another solid quarter and then I will highlight some of our recent accomplishments in the business and how all of this progress aligns with our goals that we set for 2016.

Now, just to remind you, our 2016 goals are to first achieve our operational, financial, and safety targets. We also have a big goal around repositioning our capital structure and growing our portfolio of contracted gas and renewable assets. Finally, all of you know that a big part of 2016 is about securing a mutually beneficial coal transition arrangement here in Alberta.

At the close of the call I'm going to discuss some of the extensive work that we have done since our last call. And it's work that has provided me with some greater confidence that our Company is well positioned to continue as a leading power generator here in our home market. So, let me begin with the quarter and how we're doing against our operational, financial, and safety targets that we said earlier this year.

Earlier today we reported our second-quarter 2016 results, and you can see from slide 5 and all the work that some of you have already done, that we delivered another solid quarter both operationally and financially. Now, this continues on from our solid performance in the second half of last year and the first quarter of 2016, and it's setting us up well to deliver on our 2016 financial outlook, which you can also see on the slide.

Our comparable EBITDA of CAD248 million is in line with our expectations and it is well above the results in the second quarter 2015 which came in at CAD183 million. We did deliver adjusted fleet availability of about 87%, and it was a significant improvement over the second quarter of 2015 which was 81%. Availability is higher at Canadian Coal due to fewer planned and unplanned outages and lower [D] rates than last year. We have strengthened the leadership team at Canadian Coal and they are delivering.

Our employees also need to be thanked for the work that they've done to not only deliver on our operational and financial goals but at the same time to deliver on a strong safety results for the first half of the year. Our IFR so far this year is 0.68%, and this is our lowest IFR for the first six months of the year since 2012, so congratulations to all of our staff that have accomplished that.

Our strong safety performance and our improved operational performance is not due to chance. Our five-year target safety journey -- target zero safety journey, the implementation of an operational integrity performance program to improve equipment safety, and our sheer determination to drive more reliable and predictable performance across all our assets is paying off.

On slide 6 we provided a breakdown of the cash generated this year by each business segment after accounting for sustaining capital expenditures. Now, we refer to this at TransAlta as free EBITDA and each business leader in the Company is fully accountable to deliver their free EBITDA or to pay their dividend to the corporate.

You can see from the chart that TransAlta's gas and renewable fleet has provided approximately CAD300 million of free EBITDA in the first six months of the year as compared to CAD253 million in the same period last year. Gas and renewables now generate approximately one-half of our revenue yet consumes far less sustaining capital than our coal fleet.

Our greater share of gas and renewables should be such changing the way you look at us. It is important to understand that a greater percentage of free EBITDA from gas and renewable assets in both TransAlta and in TransAlta renewables leads to more free cash flow for reinvestment.

Now, I wanted to point this out because all too often when I'm meeting with investors they tend to think about TransAlta as an exclusively coal-fired generation company. Our coal fleet does generate significant positive cash flow and we expect that to continue right until the end of 2030, but -- and we expect that to continue even as we are transforming the fleet.

However, many people forget all the work we've done over the past five years to build our gas and renewables portfolio which now represents approximately 65% of our overall cash flow. As Canada's largest wind generator and Alberta's largest Hydro operator, we have a big head start on the transition to gas and renewables.

Our second goal this year was repositioning our capital structure and it's really about repositioning our balance sheet with more project level debt. I'm satisfied with our performance thus far in 2016, including the CAD159 million project level financing secured against the New Richmond facility and the progress that's being made on the extension of our credit facility. The team is tracking to a plan which will close between CAD400 million and CAD600 million of project-level debt financing this year. Their work is well underway and I am pretty confident that we will achieve all of our 2016 goals.

With respect to our goal of growing our portfolio and contracted gas and renewable assets our construction team is tracking well to deliver our South Hedland project by the middle of 2017. We are in the last year of this project and if you go to our website you can see for yourself how far it's advanced. Again, my review of the progress shows strong execution by the TransAlta team.

Now, overall we are looking at some potential reinvestment of free cash flow generated by TransAlta renewables. With a target payout ratio of 80% to 85%, there is roughly CAD40 million to CAD50 million per year that is not paid to shareholders and that could be reinvested in growth opportunities.

Alongside this, the cost of capital for TransAlta renewables have become very competitive. In addition, even after we complete our financing plan in 2016, there is still contracted assets at renewables that will remain unlevered and could provide borrowing capability to fund future growth initiatives over the next three to five years.

We also have free cash flow from renewables and gas assets that are still inside TransAlta that could be made available for reinvestment once we achieve a mutually beneficial coal transition arrangement here in Alberta. So, that's the investment side of the equation.

In terms of the opportunity, we are seeing a number of developments and M&A opportunities. We mostly like what we see on the Greenfield side where our capabilities can generate better margins. However, there are some small opportunities on the acquisition side, what I would call tuck-ins, and will continue to pursue those where profitable.

Now, as many of you know, the acquisition market for renewables is extremely competitive and everybody wants to be in renewables. It doesn't matter if they are a power Company or an oil and gas Company. There are project returns that are not acceptable at any cost of capital, so you can be sure that if you see us announce or win additional businesses in the renewable space over the next year or so that first we do have the cash to allocate to that investment and, second, the returns are solid.

Before I pass the call to Donald, I want to comment on some additional actions that we've taken in 2016 that are strengthening our ability to achieve solid financial and operational results as we move forward. You can see from slide 8 we've been pretty busy in the first half of this year.

During the first half we've added approximately CAD12.5 million of new EBITDA from projects that we bought during last year and I have to say all of the projects that we have acquired are achieving the expectations that we set out in the pro formas when we approved those investments.

We closed a 30-year deal with BC Hydro to extend the PPA on Akolkolex which is owned in TransAlta renewables and this brings our re-contracting record in gas and renewables to approximately 700 megawatts over the past five years. We also closed a small five-year water management services arrangement with the Alberta government on the Bow River. We completed the decommissioning of the Cowley Ridge Farm. We continue to drive cost improvements of the mine in Alberta. We signed an amended coal delivery agreement with 2016 with BNSF to improve conditions further at Centralia, and we went live with the new training platform.

So pretty busy first half of the year. Taken together, many of these activities and our execution against our goal has contributed to the bottom line result you see to date in our financials.

I will pass the call over to Donald for his comments on the quarter and on our second 2016 priority repositioning our capital structure. When I return, I'm going to talk briefly about our work here in Alberta on our top priority, which is reaching that mutually beneficial coal transition agreement. We are also doing some very strong work to ensure that we are competitive in the future with the cost of carbon is the largest input cost for our coal operation.

Thank you, Dawn. As Dawn mentioned in her opening remarks, the second quarter was solid both financially and operationally. Slide 9 provides the segmented operational results for the quarter and year to date. All businesses delivered better or similar results to last year during the quarter.

For the year, our EBITDA is up 15% or CAD70 million, mostly due to significant improvement in Canadian Coal and energy marketing. Canadian Coal had a solid second quarter with CAD93 million of EBITDA, 31% better than the same period in 2015. The focus on cost reduction, efficiency gain in our mining operation, much higher availability, and our effective edging strategy have offset lower price on contracted generation.

Canadian Coal's availability reached 86% in the quarter as compared to 75% in the same period in 2015. The improved availability is due to fewer planned and unplanned outage and lowered the rate of our capacity due to preventive maintenance done on our condensers. Last year availability as well was impacted by a (inaudible) event at (inaudible) One.

Our wind and solar segments generated improved EBITDA over the second quarter 2015 due to a CAD7 million contribution from assets that we acquired in the second half of 2015. The wind resource in Western Canada was also significantly better than the prior year, partially offsetting lower price. Our price in Alberta settled at an average price of CAD15 for the quarter compared to CAD57 in the second quarter of 2015.

Our [hedging] program effectively mitigating the impact of low price on Canadian Coal; however, Wind in Alberta was impacted by a low price. I should note that the gas and Hydro performed as expected given they are largely contracted.

Building on the team of execution again our goals. Slide 10 is an overview of the progress we've made in 2016 to solidify our balance sheet.

As Dawn alluded to earlier, we have received commitments from all of the banks in our CAD1.5 billion syndicated credit facility and our CAD240 million bilateral credit facility to extend each facility by one year. This was accomplished during a challenging period in Alberta and the team demonstrates the solid relationship and trust we have built with our banking partner over time. Once finalized, the extension will provide us with greater flexibility and financial strength as we transition to Canada's leading clean energy company.

With respect to key financial ratio, the closing of the drop-down for the Canadian asset in early January, the solid performance thus far in 2016 and the strengthening of the Canadian dollar have contributed to significant improvements in our FFO to debt and to debt to EBITDA metric which came in at 16.5% and 4.3 times respectively this quarter. Our goal is to be a 20% FFO to debt and 3.5 times debt to EBITDA in 2018 when South Hedland is online and contributing financially for a full year.

Lastly, our liquidity remains high at CAD1.5 billion at the end of the quarter. This level of liquidity is critical in time of uncertainty like what we are facing currently in Alberta.

Slide 11 is a summary of our capital plan up to 2018. As we discussed during our last call, we are planning to repay debt maturity and fund the construction of South Hedland by raising project level debt in utilizing cash generated by the business over the next two years. A significant portion of the free cash flow available to reduce debt results from the decision to significantly reduce dividend in January.

During the second quarter, our dividend payment was CAD10 million down from CAD50 million from last year. Since the beginning of the year we have generated there CAD0.52 per share of free cash flow. For the year, we expect to generate between CAD0.87 to CAD1.04 of comparable free cash flow per share while our declared dividend is now set at CAD0.04 per share per quarter or CAD[0.16] per share annually.

As we stated during our last call, our plan is to raise project level debt using contracted asset over the next two years. Our goal in 2016 continue to be to raise between CAD400 million to CAD600 million. We execute against this plan in the second quarter by closing CAD159 million financing secured by our New Richmond wind facility. This debt will amortize over the next 15 years with matched (inaudible) of the contract with Hydro-Quebec at a rate of less than 4%, which speaks to the quality of asset and the counterpart to this contract facility.

There are a number of high-quality contracted assets at TransAlta and TransAlta Renewables that can be used to (inaudible) further project level financing this year. We have no further debt maturity until June 2017 and the cash required to build South Hedland for the remainder of 2016 is less than CAD50 million. Comparable free cash flow for the second half of the year is expected to be in the range of CAD100 million to CAD150 million, in line with our guidance at the beginning of the year. As a result, our liquidity should remain high for the rest of the year.

Finally, I just want to note that we are expecting a decision on the 2013 Keephills 1 force measure during the third quarter. We set aside a provision of approximately 50% of the potential exposure from the arbitration. On this, I will now pass the call back to Dawn for our closing remarks.

Great. Thanks, Donald. Listen, before we take your questions I would like you to recall the three strategic things we described at our AGM in April this year, execution advantage, history repeats, and balance (technical difficulty). You've heard many examples today of how we have demonstrated our execution advantage during the first six months of 2016 and how well we're tracking towards achieving our annual targets. So I want to end the call by commenting on how our balance wind speeds is impacting our planning on our transition from coal to gas and renewables.

Because our discussions with government are confidential, I cannot talk about them on this call. However, there is a common interest which is in the public domain. That common interest is that the transition from coal to gas and renewables must be implemented consistent with the objectives of fairness and affordability for all Albertans.

Along with this, the transition must insure reliability and minimize (inaudible) capital which the government has identified as imperative in a successful plan. I personally continue to support taking as long as we collectively need in our discussions with government to arrive at a plan that satisfies and balances the important needs of all stakeholders. Our collective work is critically important. The strength and resilience of the Alberta economy depends on maintaining competitive and transparent power prices.

There are many jurisdictions worldwide that have got the balance wrong and that are backing up to reassess their options. The recent news of price spikes in the southern Australian market and the reversal of renewables policy in Germany are good examples of why we support taking time to get this right.

Now remember that investing in electric infrastructure is complex and lumpy. Large amounts of upfront capital are needed to build assets whether it's a wind farm, a hydro plant, a dam, a coal generation, or gas-fired generating plant. These plants aren't built overnight and investors are normally paid back for their capital over many years. This is why investor confidence is at the heart of low prices for customers. We all pay less for electricity infrastructure when investors bring low-cost sources of capital to the transition.

This formula is unchanged when considering investments that now must carbon pricing as a predominant input cost. Customers will continue to need low-price electricity infrastructure and investors will need to be convinced that our investment strategies have the right risk profile for them to want to bring the necessary low-cost capital.

Remember that today TransAlta owns approximately 5000 megawatts of generation in Alberta, approximately a third of the generation here. This includes 3500 megawatts of coal, 1000 megawatts of hydro, and 500 megawatts of wind. With carbon priced at CAD30 a tonne, the cost of producing electricity from coal is significantly more expensive. It will be uncompetitive if we simply take no action. So we are focused on turning this price advantage to an advantage for consumers and for our investors.

Slide 13 shows the elements of the carbon climate leadership plan here in Alberta. This aggressive plan is designed to attract new investment in cogeneration, renewables, energy efficiency, and distributed generation, and plans like this are being implemented and proposed in markets around the world, and they make sense in a world that is trying to quickly curb emissions of greenhouse gases.

So to ensure our assets can reliably serve Alberta customers as the price of carbon is added to electricity bills, we are doing a lot of internal modeling. We study and run simulations of different scenarios that can be implemented to balance customer and investor needs. Achieving this balance will also support a vibrant Alberta economy.

We have also conducted our own internal market analysis of Alberta's future electricity supply and demand. This analysis uses assumptions about the future based on what we know today. To vet this work, we've asked experience power market consultants to review our assumptions and findings. Our conclusions, which are provided on slide 14, are from our in-depth reviews and they are clear.

First, Alberta's electricity supply demand fundamentals remain relatively balanced until the mid-2020s. After this point, we expect future load growth to be met by investments in behind defense cogeneration as well as renewables, energy efficiency, and distributed generation. Investment is set incentives and the climate leadership plan will drive capital in those directions, and we have definitely seen this trend were worldwide in the market that we are in.

I am confident today that when we combine our fleet with these new future investments there will be sufficient generation to serve the province of current and growing needs. Part of this balance will be maintaining the affordability of TransAlta's coal fleet which currently serves approximately a fifth of Alberta's market. Through this historic transition, we expect that post 2020 some of our coal plants could operate as intermediate or peaking resources, they will be no longer needed as (inaudible) plants. As such, our capital plan could be adjusted downward accordingly to reflect this reality.

Now, we do have experience in this kind of operation. Our Centralia facility today operates as an intermediate plan and currently spends only about 25% of the capital of a typical base load coal plant of the same vintage and with similar operating characteristics.

Second, our analysis also shows that many of our existing plants will be more competitive than investments in new gas-fired plants. Combined cycle plants may not pay a tax on carbon emissions, but new expensive capital will be needed to build them. Many of our depreciated coal plants have cost structure and operating characteristics that are more competitive than newer plants, even with the carbon tax disadvantage.

The carbon tax may also potentially incent us to convert some of our existing units to gas. It's doing its job by getting us to think more clearly about how to compete to win customer business here in Alberta in the future.

Now it's too early at this point to make final decisions on our future direction and how we will change our investment plans here at TransAlta, but our modeling tells us that our current fleet of plants will have a significant role to play in Alberta's historic transition. We will continue to work to develop optimal capital plans for our Alberta fleet and we will determine how we can both repay our obligations to our debt and equity investors and continue to provide our customers with affordable and competitively priced power.

Third, minimizing carbon costs are innovation is critical. Albertans are enjoying today some of the lowest electricity prices seen in the past 20 years. As we transition into a world where carbon is priced, we must find ways to offset the pricing pressure and maintain this low-cost environment.

Our customers share this goal. They have told us that they want us to find innovative ways to reduce our input carbon cost soon as possible. They want us to minimize capital spending on coal and deliver power at the most competitive price, and investors are equally clear. There's little point investing in the past and we are better suited to invest in the future. Every dollar of reinvestment must balance three forces, a world where carbon is priced, a world where natural gas prices will continue to be volatile and difficult to forecast, and a world where customers demand reliability at a competitive price.

So, finally, we must identify investments in Alberta and also utilize our current competitive advantage. As I said earlier, we are a third of the market for generation here in Alberta. What we do, how we do it, and how quickly we execute our plans will significantly impact electricity prices and reliability.

The last piece of the balanced equation requires us to develop or find new investment opportunities. To date, we have identified over 2500 megawatts of low-cost solar, hydro, and wind options that can compete with upcoming renewable (inaudible) from the [iso]. We believe that securing a mutually benefit coal transition arrangement will boost investor confidence and position us to bring these assets to market. We remain confident that a coal transition plan will be reached that wins approval from both customers and investors.

Now, remember, too, finally that TransAlta Renewable to date is as or is more competitive than many other global renewable companies. We intend to keep this advantage. Under the right contracting regimen we use our competitive cost of capital to invest in significant growth opportunities right here in our own backyard.

In closing, the key takeaways from today's call are this. First, we are continuing our solid financial and operational performance and growing our execution advantage. Second, we are progressing on all our goals. Third, our financing and operating plans are solidly backed by teams of experienced and dedicated employees and, forth, we are focused on our customers who expect us to be responsive, responsible, and innovative. We will build their businesses together and support a vibrant future here in Alberta. With that, I'm going to turn the call over to Jaeson.

Thank you, Donna. The question and answer format will be the same as always. We will answer questions from the investment community first, and then open the call to media. Lastly, I would also remind you that my team and I will be available after the call for any followup questions you may have. Operator, we will now take questions.

(Operator Instructions)

Rob Hope of Scotiabank.

Thank you for taking my questions and congrats on the quarter. Want to get a sense of how you are looking at weighing the pros and cons of reinvesting free cash flow's back into the balance sheet versus potential new renewable opportunities?

Hi, Rob. It's Dawn Farrell here. Well, I think I tried to lay it out in my script and maybe I wasn't as clear as I needed to be. When we look at TransAlta Renewables today, we see about CAD50 million of free cash flow that comes just off of that business, so that's good money for reinvestment. When we look at our recontracting or raising money through our project debt, some of that project debt money can stay in TransAlta renewables for future investment. Some of it comes back to TransAlta for paying down debt. When we look at our gas and renewables assets that are inside TransAlta, if we get a good -- if we have a good transition agreement here in Alberta, we can start to reinvest that into gas and renewables here in Alberta or we can use that to pay down debt on the balance sheet.

So what we've done is we've really looked at each of our assets. We looked at our ability to raise project debt, and we basically are moving some of that towards the balance sheet and some of that towards renewables. Now, I just want to say it's got to be renewables at the right returns. We are involved in a number of auctions. Everything we've seen to date the returns are too low and we wouldn't participate in that. So if we can't find the right returns, we will improve the balance sheet.

That's helpful. And then just a followup on that. The 2500 megawatts of potential renewable opportunities that you mentioned, I'm assuming that's largely held at TransAlta Corp. Just wondering if you would look to have a co-investor in those opportunities or potentially sell then to RNW?

Well, we can do those as corp investments, we can do those RNW investments, or we can do them as corp investments and sell them into renewables, but we would not look at a co-investor outside of TransAlta or TransAlta Renewable. So it's stuff that we would do on our own.

That's helpful. Thank you.

Linda Ezergailis of TD Securities.

I'm wondering if you could maybe elaborate on sort of the tuck-in opportunities that you have been seeing and intend to continue to look at and how they might stack or compare or contrast to some of the Greenfield and Brownfield opportunities that you're looking at outside of Alberta?

I would say, Linda, around all of our facilities there tends to be a few smaller facilities that we can probably -- we can tuck in and get the right returns on and I think they're small enough that the broader market of people that are looking for renewables opportunities won't chase them because the big money chases the big portfolios, right. They might be an extension to an existing facility or they might be a facility that is close to a facility we already have and our operating team can manage both facilities.

How they compare to the Greenfield, I would say generally Greenfield has a little bit higher returns in it but mostly because we take more risk, as you know. When we look at our Greenfield opportunities we have to take the development risk, we have to take the construction risk, permitting risk, and then we have to make sure that the cash flow is there. So I would say that all of the Greenfield opportunities that we're looking at are --first of all, it's a pretty competitive market for Greenfield as well and we've got to be sharp on all of our capabilities there. But they tend to have over the long-term for investors much higher returns, so we would tend to want to push capital more in that direction, all else being equal.

We're pretty careful about how we're allocating money to acquisitions because we don't want low-priced acquisitions to take away from what we might be able to do on a future Greenfield project. It's the big acquisition set where we're seeing pretty dismal returns. There's a lot of discussion about how this is the new world of what equity returns are going to be. I think we'd rather save our capital for a future where maybe the equity returns are higher or we would just put more money into Greenfield.

That's helpful. And any solar you're looking at in Australia would be on existing land or contiguous to your presence there or can you describe --?

No. Solar is a little bit different in Australia. Some of that is because we know the local jurisdiction really well. We know the regulatory, we know the political, we know the landowners, we built that pipeline there so we know a lot of the land issues and the regulations. It doesn't necessarily have to be contiguous but, as always, we tend to like to step out from a place where we've got a lot of insight. What's unique about Australia is their market is growing so quickly and there are a lot of opportunities because of the way they do their renewable credits. So they are a pretty good jurisdiction for us.

That's helpful. And just a follow-up question. I was surprised to see in your outlook, and I know you're militant on cost, but can you describe I would assume it's somewhat incremental but what other further cost reductions are even possible in your organization?

You shouldn't say it that way because imagine the team will say, look, even Linda says we can't get any more out of this organization. Listen, I think there's not further cost reductions in terms of you can just cut costs here and there in terms of the kind of -- because you need quite an expertise to run this business, whether it's in your communications group or your government group or your operating group. Where I see potential value creation is in us really figuring out how to change the pace of decision-making. The more decisions that can get made the more work that can get done, that gets stuff done type of thing, the more energy you can put into new things. So that's really where we are focused right now and we'll continue to focus. I would continue to count on us for additional cost reductions as we go forward.

That's helpful. Final question. Can you give us a sense of the timing of your remaining two planned outages for the balance of the year, Q3 or Q4?

I don't have that. Don't we get that out of the -- we will get Jaeson to send you that after. It's in the iso report. I just don't have it top of mind here.

Okay. Thank you.

Andrew Kuske of Credit Suisse.

Thank you. Good afternoon. I guess if we look at any market one of the key underpinnings of any market is confidence in the market. So when you look at the government actions just recently, how do you look at market confidence and really having parties willing to put capital in a long-dated business to invest for the future and the future repowering of Alberta? How do you think about that and maybe draw some comparisons to what we've seen other markets around the world?

The specific issue that's going on between the government and the PPA buyers is an isolated incident between them. It doesn't really impact us because I still have a lot of confidence that the current system as it's set up will pay our capacity payments and that gives me more confidence as we go forward to continue to -- because I have to invest sustaining capital in this market, so knowing that the balancing pool will pay those capacity payments is important for how we look at it really short term. I would say that kind of generally, and I have to be careful here, but just to expose a little bit of our thinking, generally what I'm seeing is in power markets around the world is trying to bring together power and environmental policy into one kind of sweeping policy that then incents investors to bring money is difficult to do because it's brand new. It's really just emerging.

Now, in the past couple of years it's emerged because people did renewable standards and they did it through regulated businesses and there's lots of different mechanisms that people have used. Maybe contracting, and our studies globally is that we have not seen a market ever yet where the combination of environmental policy and pricing environmental attributes, such as carbon or NOx or SOx and what you need to keep power prices low has been done well. So I think you have to be cautious in every single jurisdiction worldwide because it's just part of what you've got to learn how to do in the business. I think generally if you look at our portfolio we've done a good job. If you look at all of our contracted assets, if you look at the provisions in them, if you look at the way we price environmental attributes I think we've done a good job overall.

So as I think about Alberta, I think Alberta is in kind of a unique position because it can look at all of the mechanisms that have been tried and potentially have failed and it can decide going from here how to blend together the energy market and the environmental market to come up with what could be the lowest cost type -- lowest cost power for consumers going forward. I do personally believe that pricing environmental attributes is here to stay. It's going to be everywhere over the next 10 years, so I don't think jurisdictions are going to get out of that. So I think it's just really can we bring the best thinking to the discussion here so that Alberta can come out of this with a better mousetrap than really what's been invented so far from what we've seen.

Okay. That's very helpful color. Maybe the next question more to Donald on the bonds on New Richmond, the [3-9 and 6-3], where could you price this today and what kind of size limitations do you have in that market?

I think the market is very receptive and very robust. A lot of appetite and basically the sizing is based on the cash flow of the business and the duration of those contracts and that's what [lenders] are looking at. How long is the contract and what are the cash flows and when they're looking at wind project, take a discount to reflect the variability of the wind. That's the way that they are sizing. The market is very robust and our financing -- in New Richmond it was a like a widely marketed transaction. We went to a few selected investors. It was widely oversubscribed. And we believe that basically we will be successful with our plans for the rest of the year because all the other assets that we are looking at have similar attributes that New Richmond had.

That's great. Thank you.

Steven Paget of FirstEnergy Capital.

Good afternoon. You signed a water management agreement with the government on the Bow River. Are you looking a similar watershed agreements on your other Alberta Hydro systems and what might the impact be?

No, we're not. This is kind of a one-time agreement for the Bow and really this is kind of a neutral agreement. The way that it works is it basically allows the government to instead of us getting paid for power revenues we do more storage or more work if there's a drought. So it's kind of a neutral agreement that allows a little bit more operating control by the government based on other things that people need. It's not necessary. We don't see it as necessary on the Fort Saskatchewan system.

Thank you. When you measure cost control, how do you measure in benchmark your cost against other organizations?

Benchmarking comes from a lot of different areas. We do subscribe to a number of benchmarking services. The benchmark coal plants that are the same size as ours and the same number of years old as well as gas plants, hydro facilities, wind farms. We also work with our -- some of our providers of accounting services and things like that to benchmark our business cost, the cost of running finance, the cost of running our GR department, whatever. We would get benchmarks from all over the place annually. We review them. We look at where we are relative to those benchmarks and we tend to set our plans relative to try to achieve that the quartile that we think will make us the most competitive.

Thank you. What about utilization and in particular what is your target utilization for wind?

Target utilization for wind tends to be in that -- if you're talking availability across the year, not just availability when -- because we have two ways of looking at that. We look at it as an annual availability and we also look at it as a commercial availability, so you want to be able to run when the wind blows. We don't actually care if you're working on the plants when the wind isn't blowing. We're just developing that metric right now but our annual availability is in the 95% to 96% range.

Thank you. Those were my questions.

Robert Kwan of RBC Capital Markets.

Good afternoon. If I can just ask first about the repositioning the capital structure slide. Donald, I apologize if I didn't understand how you were setting it out, but it looks like the project level financing is down a couple hundred million in that range. Is that just the New Richmond financing or have you changed your assumptions on how much you can do?

I don't have quarter-over-quarter comparison, but I think we're always quoting same range. Jaeson is telling me we are looking forward only, sorry.

Okay. So that is inclusive of the New Richmond financing then? Is that why the range is down?

Exactly

We've got 157 or [9] behind us and that's what we have left to do. So the target is [4] to 600.

Got it. Okay. And just so I understand the cash flow from the business 450 to 600, if you look at your free cash flow guidance for this year and take off just under CAD50 million for dividends, effectively the low end of this year's range times three years is the high-end of the cash flow from the business range. I'm just wondering, do you have any color or comments on that?

It's 2-1/2 to 3 years and we also take into account some cash that we earmark for growth.

So basically it's a bit of a mismatch -- well, not a mismatch, you said 2-1/2 years forward. And then maybe if I can just ask one last question. Can you talk about some of the work that you've done on the optionality of your sites, coal to gas conversions, what you might be able to do there? Dawn, you mentioned one of the things is keeping the existing units and maybe turning them as intermediates to peakers. Is that -- when you look at the Centralia capital that you got, it looks like you could almost spend under 50% of what you're spending right now on the coal units from a routine maintenance, sustaining maintenance basis?

Yes, so we haven't completed our work yet in terms of really understanding exact capital that we would spend as they become intermediate units. And what we're planning to do, Robert, is we're hoping to get organized to do an Investor Day here at the end of November and that's where we can bring some of that thinking forward. But really you've got a range of options.

You can keep the coal plants on coal and make them into your into intermediate or peaking plants. You can slate some of them for combined cycle plants where if you effectively reuse a lot of the equipment and then put a combined cycle plant right there and utilize, reduce the overall capital cost of that, and then you can also convert the boilers to gas. We're looking at the optionality of all of that.

We'd expect, it sounds like, Dawn, end of November Investor Day we'll get a little bit more clarity maybe around numbers and potentially where you --?

Right.

Thank you.

Paul Lechem of CIBC.

Thank you. Good afternoon. Maybe just following on from Robert's question there. Your [clients] around existing plants are expected to be more competitive than investments in new gas-fired plants. Is that essentially -- take Sundance 7 off the table is that project essentially dead for the time being?

No because Sundance 7 really has got to compete against -- so if you think about Sundance 7, there has to be more incremental load growth in the province for it to go. So what I've done is -- what we've done is we've said what is the existing load in Alberta? Let's say the highest load we get is 11,000 megawatts and the current fleet in Alberta is around 15,000 but you actually need that size of fleet to be able to meet that demand because of just outages that go on in the marketplace. So if you look at our existing coal plants, I see them as serving the existing demand and that's where our comments are that if you wanted to build a combined cycle plant to replace a coal plant, we've got plants that actually if you convert the capital and they're fairly depreciated, you've got to spend a lot of money to compete with us, so that's really that comment.

If you look at the growth though, my comments were that you can see policy will push cogeneration ahead of Sun 7. It will push energy efficiency, it will push distributed generation so you could expect a lower growing demand even if we get a real pickup here in GDP. I would expect the electricity growth as a percentage of GDP growth to drop or moderate. So that does step us back in terms of Sun 7. So where we thought Sun 7 was maybe at 2020-2021 plant, we would think it's more further into the mid-2020s and it has to be more competitive than other forms of generation. So there may be other things that are more competitive than Sun 7 now and that's the work that we have to do before we would execute on that plant.

That's helpful. Thanks. The other point you had, the first point on the slide 14 about you expect Alberta supply/demand to remain balanced through mid-2020. What are other such assumptions other than low growth and what assumptions have you made about the market? How much new renewables do you see coming in over the balance of this decade? What do you expect around Sun A after it comes off it's PPA? Can you give us any assumptions underlying that statement?

I can give you some general assumptions. Basically, we are assuming that the federal plan for coal -- so we have coal staying open until the end of its federal life. We have slowed down load growth because we see more off grid generation coming into the market. And we've seen that everywhere, Paul. If you go to Australia, my gosh -- now they have a better solar regime than we have in Canada, but there is the cost of solar are coming down dramatically so you see a lot of that on new build apartment buildings and new build houses, so we've moderated for that.

Cogeneration absolutely has an advantage under the carbon tax regime, in fact they probably get a credit as opposed to pay a carbon tax so they start to really dispatch ahead of regular combined cycle plants. We try to build in as -- we've taken the carbon leadership plan and the incentives that are in there, we've taken them at exactly face value. We then made some of our own assumptions about things we're seeing in other markets. Taking the federal plan and then taking some of our optionality and used that to make our assessment.

Okay. And Sun A, do you expect that to continue to operate in some form or fashion post 2017?

Currently, Sun A can go right until the end of 2019. So as long as it's cash positive it will run.

Okay. Thanks. One last quick question for Donald. You mentioned, Donald, I think that there was a decision upcoming in Q3 on Keephills 1 Force Majeure provision [half]. Can you remind me again how much it was provisioned?

We haven't disclosed the provision, Paul. It's like 50% of the potential claim has been provided for but we are not disclosing the specifics for each of the claims, but back in 2013 and the unit was up for nine months, so I guess you can run your own math on your side.

Okay. Thank you.

Sorry about that.

Mitchell Moss of Lord Abbett.

I just wanted to follow up on some earlier questions regarding the sources and uses which I guess repositioning the capital structure on slide 11. I didn't quite understand that answer because from Q1 presentation and from the analyst day presentation you showed about CAD200 million more project-level financing and now that's not there. So could you just clarify a little bit more about how you want to make up the shortfall or if it sounded like maybe that financing had already been accomplished?

The source is looking forward. So the CAD650 to CAD900 is after we complete the recent financing of New Richmond which raised CAD160 million. So you have to add that to the analysis here. Sorry about that.

So the New Richmond financing that's already -- that you've already completed is excluded from that project level.

Exactly.

And so should I think that obviously there's some variability around that range and even with the financing that you completed there's still some potential that you might not achieve the CAD1.5 billion of cash to meet your upcoming uses, your [billion and a half uses]. How should I think about that?

We also have our credit facility. We have CAD2 billion of liquidity of which CAD500 million to CAD600 million we're using for [LC] but we have like CAD1.5 billion and potentially building up that number a little bit but to basically pick up the slack on the source in use there.

So it's a credit facility for any funding shortfall.

Yes.

Thank you very much.

(Operator Instructions)

Charles Fishman of Morningstar Investment Research.

Dawn, I just had one quick one left. If I look at slide 13, bullet point 2, based on the comment you made answering another question about Sun 7, the replacement of the retiring coal fleet one-third with gas then you envision that as a repowering of existing coal-fired plants at least in the next maybe middle of the next decade rather than a new gas plant. Did I understand that correctly?

Yes, that's a very real possibility. Depending on how we -- what our coal transition looks like here, but that's a very big possibility here in Alberta.

Obviously that's a lot less capital than building a new plant.

Right.

Thank you. That's all I had.

Jeremy Rosenfield of Industrial Alliance Securities.

Thanks. Really just one question here to clean up. Dawn, I think you mentioned off the top something about RNW's valuation and the free cash flow being spun out at the RNW entity. When you think about growing RNW, do you think that it could become more profitable or the returns could be better if you would pursue more third-party acquisitions rather than sort of waiting to grow the entity solely by drop-down acquisitions? What's the perspective there?

Yes, I think it's kind of -- well, there's three things, right. You can do acquisitions. You can do Greenfield. Greenfield you have to wait, so the two immediate things you can do are acquisitions and dropdowns, and the thing that you can wait on is getting better returns by being more patient on Greenfield. We look at all of those. But if you look at the drop down strategy that we had before was really to take some capital out of TransAlta Renewables and play down debt at TransAlta. We don't need to do that anymore.

For us, any capital that is freed up in TransAlta Renewables should be invested in new projects going forward. Those should either be acquisitions or Greenfield. And I guess my comments were that the acquisition market is pretty thin, so if you do acquisitions you've got to be pretty careful because you're using up your powder and getting a pretty low return. Where I'd rather be a little more patient and get a higher return because you guys are all going to benefit more if we get higher returns over a longer period of time. So that's really what the thinking was there.

And the sources of cash out of renewables are both the cash that gets thrown off in there. There will be some assets that will be under leveraged, so if we can put some leverage against them that's additional cash, but most importantly it's got a great currency, renewables, and so its currency itself could help grow the entity.

So just following on that. Do you think it might be appropriate then to sort of increase, let's say, dedicated development CapEx within TransAlta renewables to try to source additional Greenfield opportunities?

No. We still continue to do the Greenfield opportunities in TransAlta rather than TransAlta Renewables. TransAlta Renewable is the financing vehicle and really you want to think about it is having attributes of very stable long-term contracted cash flows from both of gas and renewables. So it's a very clear set of projects that end up being built up in there. We don't see that entity as doing its own development. That will be in TransAlta and then once we do it we can transfer into renewables.

So no sort of changes in terms of defined roles for the different structures. Okay. I got it. Thanks.

This concludes the analyst question and answer session for today's call. We will now take questions from members of the media.

(Operator Instructions)

Alesia Fieldberg of CTV News.

Dawn, I just want to know how it would effect TransAlta consumers if the government of Alberta wins its lawsuit preventing electricity companies from offloading market losses onto the public through the balancing pool?

Maybe I'm going to get John Kousinioris to take that.

I think from our perspective based on our understanding right now, if the government were to win its lawsuit, I think the outcome of that would be that the PPAs would probably end up going back to the buyers and, as a result, we would expect that our capacity payments do continue to be paid by those particular entities as they are currently being paid presently. In terms of the impacts that would happen to consumers in the Province of Alberta, it's hard for us to speculate on what happened from a pricing perspective in terms of what those buyers would do, but I would imagine they would alter their behavior to factor in, in their bidding behavior, elements of the carbon pricing that the government has put into place to recoup some of those costs. So I think invariably, at least from a TransAlta perspective, some of those power prices would likely increase from where they are today.

Any indication of an amount? I know it's just ballpark right now.

No, I wouldn't want to speculate. I know there's been a lot of speculation in the media about what those amounts would be. I think as you may know we actually haven't been named as part of the legal dispute which is going on, so I would not want to speculate on what that dollar amount would be.

Just to put a fine point on it. Our customers really aren't affected. They buy power from us and we supply it through the power that we have here in the province, so it would not affect them.

Thanks for weighing in.

This concludes the question and answer session of today's call. This also concludes today's conference call. You may now disconnect your lines. Thank you for participating and have a pleasant day.