TransAlta Corporation (TAC) Q2 2016 Earnings Report, Transcript and Summary

This is the Chorus Call conference operator. Welcome to the TransAlta Corporation 2016 Second Quarter Results Conference Call and Webcast. As a reminder, all participants are in listen-only mode and the conference is being recorded. After the presentation, there will be an opportunity to ask questions. [Operator Instructions] At this time, I would now 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 qualification, which is set out in the slide deck and detailed in our MD&A and incorporated in full for the purposes of today's call. The amounts referenced are in Canadian currency, unless otherwise stated. The non-IFRS terminology used, including comparable gross margin, comparable EBITDA, comparable funds from operations, comparable free cash flow, and comparable earnings, are reconciled in the MD&A. On today's call, Dawn and Donald will review the quarterly results and progress made against TransAlta's goals and priorities for 2016. After these prepared remarks, we will open the call for questions. I will now turn the call to Dawn.

Thanks Jaeson, and welcome to everyone that’s joined our call today. Today, I’m going to begin with some brief comments on another solid quarter and then, I’ll highlight some of our recent accomplishments in the business and how that -- 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; and then, finally, all of you know that a big part of 2016 is about securing a mutually beneficial coal transition arrangement here in Alberta. Now, at the close of the call, I am going to discuss some of the extensive works that we’ve done since our last call. And it’s worth it providing you with some greater confidence that our Company is well-positioned to continued 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 set earlier this year. Earlier today, we reported our second quarter 2016 results and you can see from slide five and all the work that some of you’ve 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 this slide. Our comparable EBITDA of $248 million is in line with our expectations and it’s well-above the result of the second quarter of 2015, which came in at a $183 million. We did deliver adjusted fleet availability of approximately 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 planned outages and lower due [ph] rates than last year. We’ve strengthened our leadership team at Canadian Coal and they are delivering. Our employees also need to be thanked for their work that they have 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 has accomplished that. Our strong safety performance and our improved operational performance is not due to chance. Our five-year target safety journey targets 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 six, we provided 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 EBIDTA and each business leader in on 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 renewables fleet has provided approximately $300 million of free EBITDA in the first six months of the year, as compared to $253 million in the same period last year. Gas and renewables now generate approximately one-half of our revenue yet consume far less sustaining capital than our coal fleet. Our greatest share of gas and renewables should be changing the way you look at us. It's important to understand that a greater percentage of free EBITDA from gas and renewable assets in both TransAlta and 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. And our coal fleet does generate significant positive cash flow, and we can -- 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 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 am satisfied with our performance this far in 2016, including the $159 million project level financing secured against the New Richmond facility and the progress that’s being made on the extension of our credit facilities. The team is tracking to our plan which will close between $400 million and $600 million of project level debt financing this year. The work is well-underway, and I am pretty confident that we will achieve all of our 2016 goal. With respect to our goal of growing our portfolio of contracted gas and renewable assets, our construction team is tracking well to deliver our South Hedland project by the middle of 2017. When the last year [ph] of this project and if you go to our website, you can see for yourself how far it advanced. And 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 $40 million to $50 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 has 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 in 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 opportunities, we are seeing a number of development and M&A opportunities. We mostly like what we see on the greenfield side where our capabilities can generate better margins. However, there're some small opportunities on the acquisition side, what I would call tuck-ins, and we'll continue to pursue those where they're 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're 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 assured that if you see us announce or win additional business in the renewables 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. So, 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. And if you see from slide eight, we've been pretty busy in the first half of this year. During the first half, we've added approximately $12.5 million of new EBITDA from projects that we bought during last year. And I have to say, all of the projects that we've acquired are achieving the expectations that we set out in the pro formas when we approved those investments. We closed the 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 renewable 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 wind farm. We continue to drive cost improvements at the mine in Alberta. We signed an amended coal delivery agreement for 2016 with BNSF to improve conditions further at Centralia. And we went live with the new trading platform. So, a pretty busy first half of the year. Taken together, many of these activities and our execution against our goal, have contributed to the bottom line results you see to-date in our financials. I'll 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 a mutually beneficial coal transition agreement. We're also doing some very strong work to ensure that we're competitive in the future where the cost of carbon is the largest input cost for our coal operations.

Thank you, Dawn. As Dawn mentioned in her opening remarks, the second quarter was solid both financially and operationally. Slide nine provides the segmented operational result 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 $70 million, mostly due to significant improvement in Canadian Coal and Energy Marketing. Canadian Coal had a solid second quarter with $93 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 hedging strategy have offset lower price or on uncontracted 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 lower due [ph] rate of our capacity due to preventive maintenance done on our condensers. Last year, availability as well was impacted by a force majeure event at Keephills 1. Our Wind and Solar segments generated improved EBITDA over the second quarter 2015 due to a $7 million contribution from asset that we acquired in the second half of 2015. The wind results in western Canada were also significantly better than the prior year, partially offsetting lower price. Power price in Alberta settled at an average price of $15 [ph] for the quarter compared to $57 in the second quarter of 2015. Our hedging program effectively mitigated 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 theme of execution against our goals, slide 10 is an overview of the progress we made in 2016 to solidify our balance sheet. As Dawn alluded to earlier, we have received commitments from all of the banks in our $1.5 billion syndicate credit facility and our $240 million bilateral credit facility to extend each facility by one year. This was accomplish during a challenging period in Alberta and the team success demonstrates the solid relationship and trust we have built with our banking partners over time. Once finalized, the extension would 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 dropdown for the Canadian assets in early January, the solid performance thus far in 2016 and the strengthening of the Canadian dollar have contributed to significant improvement in our FFO to debt, and debt to EBITDA metrics, which came in at 16.5% and 4.3 time respectively this quarter. Our goal is to be a 20% FFO to debt and 3.5 times debt to EBITDA between 2018 when South Hedland on line and contributing financially for full year. Lastly, our liquidity remained high at $1.5 billion at the end of the quarter; this level of liquidity is critical in time of uncertainty like what we’re 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 and 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 our dividend in January. During the second quarter, our dividend payment was $10 million, down from $50 million last year. Since the beginning of the year, we have generated $0.52 per share of free cash flow. For the year, we expect to generate between $0.87 to $1.04 of comparable free cash flow per share, while our dividend -- our declared dividend is now set at $0.04 per share per quarter or $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 continues to be to raise between $400 million to $600 million. We executed against this plan in the second quarter by closing $159 million financing secured by our New Richmond wind facility. This debt will amortize over the next 15 years which matches [ph] the duration of the contract with Hydro-Québec, at the rate of less than 4%, which speaks to the quality of the asset and the counterpart to this contracted facility. There are a number of high quality contracted assets at TransAlta and TransAlta Renewables that can be used to secure 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 $50 million. Comparable free cash flow for the second half of the year is expected to be in the range of $100 million to $150 million in line with our guidance set out 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’re expecting a decision on the 2013 Keephills 1force majeure dispute during the third quarter. We set aside the 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.

Thanks Donald. So, listen, before we take your questions, I’d like you to recall the three strategic things we described at our AGM in April this year. Execution advantage, history repeats and balanced wins. 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 balanced wins theme is impacting our planning on our transition from coal to gas and renewables. Because our discussions with government are confidential, I cannot talk about the 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 objective of fairness and affordability for all Albertans. Along with this, the transition must ensure reliability and minimize stranded capital, which the government has identified as an 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 policies 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 co-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 the low prices for customers. We all pay less for electricity infrastructure when investors bring low cost sources of the capital to the transition. This formula is unchanged when considering investments that now much consider 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 who want to bring the necessary low cost capital. Remember that today TransAlta owns approximately 5,000 megawatts of generation in Alberta. Approximately a third of the generation here. This includes 3,500 megawatts of coal, a 1,000 megawatts of hydro and 500 megawatts of wind. With carbon priced at $30 a ton, the cost of producing electricity from coal is significantly more expensive. It will be uncompetitive if we simply take no action. So, we’re focused on turning this price disadvantage 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 investments in cogeneration, renewables, energy efficiency and distributed generation. And plans like this are being implement 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 stimulations 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 [ph] this work, we have asked experienced 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’re clear. First, Alberta's electricity supply demand fundamentals remain relatively balanced until the mid-2020. After this point, we expect future load growth to be met by investments in behind the scenes [ph] coal generation as well as renewables, energy efficiency and distributed generation. Investment incentives in the climate leadership plan will drive capital in those direction, and we are definitely seeing this trend worldwide in the markets 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’s current and growing need. Part of this balcony will be maintaining the affordability of TransAlta’s coal fleet which currently serves approximately fifth of Alberta's market. Through this historic transition, we expect that post-2020, the number of coal plants could operate as intermediate or peaking resources; they will be no longer needed as base-load plant. As such, our capital plans could be adjusted downward accordingly to reflect this reality. Now, we do have experienced this kind of operation. Our Centralia facility today operates as an intermediate plant and currently spends only about 25% of the capital of a typical base load coal plant of the same vintage and with some 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 plant may not pay a carbon -- a tax on carbon emissions but new extensive capital will be needed to develop them. Many of our depreciated coal plants have cost structures 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 your future direction and how we will change our investment plans here at TransAlta. But our modeling tells us that our current biggest 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 carbons cost through 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 way to reduce our input carbon cost as soon as possible. They want us to minimize capital spending on coal and deliver power at a most competitive price, and investors are equally clear. There's little point to 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're a third of the market for generation here in Alberta. What we do, how we do it and how quickly we execute our plan 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've identified over 2,500 megawatts of low cost solar, hydro and wind options that can compete for upcoming renewables from cost from ISO. [Ph] We believe that securing a mutually beneficial 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 from investors. Now, remember too finally that TransAlta Renewables today is as or is more competitive than many other global renewables companies. We intend to keep this advantage. Under the right contracting regime, we'll use our competitive cost to capital to invest in significant growth opportunities right here in our own backyard. So, in closing, the key takeaways from today's call are these: First, we're continuing our solid financial and operational performance and growing our execution advantage; Second, we're progressing on all our goals; Third, our financing and operating plans are solidly backed by teams of experienced and dedicated employees; And fourth, we're focused on our customers who expect us to be responsive, responsible and innovative. We will build our businesses together and support a vibrant future here in Alberta. So, with that, I'm going to turn the call over to Jaeson.

Thank you, Dawn. 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’d also remind you that my team and I will be available after the call for any follow-up questions you may have. Operator, we will now take questions please.

Thank you. Ladies and gentlemen, we will now begin the analyst question-and-answer session. [Operator Instructions] Our first question is from Rob Hope of Scotia Bank. Please go ahead.

Just I want to get a sense of how you're looking at weighing the pros and cons of reinvesting free cash flows back into the balance sheet versus potential new renewable opportunities?

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 $50 million of free cash flow that comes just off of that business. So, that's good money for reinvestment. When we look at our re-contracting or raising money through our project debt, some of that project debt money can stay in TransAlta Renewables for future investments, some of it comes back to TransAlta for paying now 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've looked at our ability to raise projects debt; and we've -- basically we’re moving some of that towards the balance sheet and then some of that towards renewables. Now, I just want to say, it's got to be renewables at the right returns. So, we’re involved in the number of auctions. Everything we've seen to-date, returns are too level and we wouldn’t participate in that. So, if we can't find the right returns, we’ll improve the balance sheet.

Great, that's helpful. And then, just a follow-up on that. The 2,500 megawatts of potential renewable opportunities that you mentioned, I'm assuming that's largely held at TransAlta Corp. I am just wondering if you would look to have a co-investor in those opportunities or potentially sell them to RNW. [Ph]

Well, we can do those at Corp investments, we can do those as 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 Renewables. So, it's stuff that we would do on our own.

The next question is from Linda Ezergailis with TD Securities. Please go ahead.

Thank you. 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 are looking at outside of Alberta.

Yes, 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 takes us to big portfolios, right? So, they are just -- they might be an extension to an existing facility or they might be a facility that's closed to a facility we already have and our operating team can manage both facilities. And 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 and 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 are looking at are first of all, it’s 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. So, we're pretty careful about how we are 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 acquisitions that where we are seeing pretty dismal returns. There is a lot of discussion about how this is the new world of what equity returns you are going to be, but 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 greenfields.

That's helpful. And any slower you are looking at in Australia would be on existing land or contiguous to your presence there or can you describe that opportunity?

No, it’s -- the solar is a little bit different in Australia; it’s more -- I mean some of it is because we know the local jurisdiction really well, we know the regulatory, we know the political, we know the landowners, we know -- we’ve built that pipeline there, so know a lot of the land issues and the regulations. So, it doesn’t necessarily have to be contagious. But, as always, we tend to like to step out from a place where we’ve got a lot of insight. And what’s unique about Australia is they’re market is growing so quickly and there are a lot of opportunities, because of the way they do their renewable credits. So, they are pretty good jurisdiction for us.

That’s helpful. And just a follow-up question, as [ph] seeing your outlook and I know you’re [indiscernible] 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 that way, because the management team will say look, even Linda says we can't get any more out of this organization. But listen, I think there is not further cost reductions in terms of -- you can just cut cost 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 just in us really figuring out how to change the pace of decision-making. So, the more decisions that can get made, the more work that can get done, the get stuff done type of thing that the more energy you can put into new things. So that’s really where we’re focused right now and will continue to focus. So, I would continue to count on us for additional cost reductions as we go forward.

That’s helpful, final, 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...

Yes, it is available.

We’ll get Jaeson to send you that after, it’s in the ISO report. I just don’t have it top of mind here.

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

I guess, if we look at any market, one of the key underpinnings of any market is just confidence in the market. And 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 then maybe for comparisons, what we seen in other markets around world?

Well, I mean, the specific issue just going on between the government and the PPA buyers is an isolated incident between them. And 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 the market. So knowing that the balance 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’ve seen is in power markets around the world, they are trying to bring together power and environmental policy into one kind of sweeping policy that then incent investors to bring money is difficult, it’s 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 business. There is a lot of different mechanisms that people have used. They’ve used contracting. And our study globally is that we have not seen a market ever yet where the combination of environmental policy and pricing environmental attribute 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 -- 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 have 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 we’ve priced environmental attributes, I think we have 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 and environmental attribute 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 indented so far from what we’ve seen.

And then, maybe the next question more to Donald on the bonds on New Richmond, the 3.963. 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 likely be based on the cash flow of the business and the duration of those contracts, and that’s what vendors [ph] are looking at. So, how long is the contract and what are the cash flow and clearly like vendor [ph] looking at when project is going to reflect the variability of the wind. But that’s the way they are sizing. And the market is robust and our financing -- even though New Richmond, we went it’s witnessed [ph] like a marketed transaction. We want to achieve selected investors like it was like widely oversubscribed and we believe that basically we will be successful for rest of the year because all the other assets that we are looking at are like similar to that New Richmond has.

The next question is from Steven Paget of FirstEnergy Capital. Please go ahead.

You signed a water management agreement with the government on the Bow river, are you looking at similar water shed agreements on your Alberta hydro systems and what might be impact be?

No, we are not. It's just a one-time agreement for the Bow. And really this is -- it's kind of a neutral agreement. The way that it works is it basically allows the government to bring out -- instead of us getting paid for power revenues, we are using more storage or more work through the drought. So, it’s kind of a mutual agreement, and it just allows a little bit more operating control by the government based on other things that people need. But it's not necessary, we don't see this necessary on the board discussions with them.

When you measure cost control, how do you measure and benchmark your cost against other organizations?

We do a lot of -- benchmarking comes from a lot of different areas, so we do subscribe to a number of benchmarking services, to benchmark coal plants or that are the same type 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 costs, the cost of running finance, the cost of running our GR department whatever. So, we would get benchmarks from all over the placed, annually we review them, we look at where we are relative to those benchmarks and we tend to set our plans relative to trying to achieve the quartile that we think will make us the most competitive.

And what about utilization and in particular what is your target utilization for wind?

Target utilization for wind tends to be -- if you are 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. And we're just developing that metric right now, but our annual availability is in the 95% to 96% range.

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

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

No, I think it's in the -- like I don't have like quarter-over-quarter comparison but like I think we always quote in like same range. So, it's like it'll be [indiscernible] like Jaeson is telling you that we're just looking forward only. Sorry.

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

Yes.

Exactly.

Because we've got a 157 or 159 behind us. And this is what we have got to do. So, the target is 400 to 600.

And then, 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 $50 million for dividends, effectively the low-end of this year's range times three years of the high end of the cash portion of business range, just wondering do you have any color or comment on that?

So, look, like a two year and half, three years and we also take into account like some cash that is in our use that we earmark for growth.

So, basically it’s a bit miss -- well, not a mismatch but, like it's a two and a half year's forward, okay. And then maybe let me 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? And Dawn, you mentioned one of the things just keeping the existing units and maybe turning them to intermediate peakers, is that the point you are looking at Centralia capital that you've got, it looks like you can almost spend under 50% of what you are spending right now on the coal units from a routine maintenance to sustaining maintenance basis?

Yes. So, we haven’t completed our work yet in terms of really understanding the exact capital that we’d spend as they become intermediate units. So, we're -- 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 could bring some of that kind of thinking forward. But really, you've got a range of options. You can keep the coal plant on coal and make them into intermediate or peaking plant. You can slate some of them for combined cycle plants where you effectively reuse a lot of the equipment and then put a commodity cycle plant right there and utilize -- reduce the overall capital cost of that and then you can also just convert the boilers to gas. So, we're looking at the optionality of all of that.

Okay. And then, we’d expect sounds like Dawn that end of November Investor Day we'll get a little bit more clarity maybe around numbers and actually where you think path forward.

Yes.

The next question is from Paul Lechem of CIBC. Please go ahead.

Thank you. Good afternoon. Maybe just following on from Robert's question. I guess your comment around existing plants expected to be more competitive than investments in new gas-fired plants. Does that essentially take some 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, it has -- there has to be more incremental load growth in the province for it to go. And so, what I've done is -- what we've done is we started to say okay, what the existing load amount, 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 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 commodity type plant to replace a coal plant, we've got plants that actually if you convert the capital and they are fairly depreciated, you 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 pick up here in GDP, I would expect the electricity growth as a percentage of GDP growth to drop or moderate. So that does kind of 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 generations. 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. And the other point you have, the first point on that slide 14 about you expect Alberta supply-demand to remain balanced through mid 2020. What is other assumptions and other than load growth and what assumptions have you made about the market, what about -- how much new renewables do you see coming in over the balance of the decade, what you expect around Sun A after it comes off its PPA? Can you give us any assumptions underlying that statement?

Yes, I mean, I can give you some general assumptions. I mean, basically, we’re assuming that the federal plan for coal -- so, we have coal staying open till the end of its federal life. We have slowed down load growth, because we’ve seen more off grid generation coming into the market, and we’ve seen that everywhere. Paul, you go to Australia, my gosh, they have a better solar regime than we’d in Canada but there is -- the cost of solar coming down dramatically. So, you see a lot of that on new build apartment buildings and new build housings. So, we’ve moderated for that. Cogeneration absolutely has a an advantage under the carbon tax regime and in fact they probably get a credit, as opposed to pay a carbon tax. So, that puts -- they start to really dispatch ahead of just regulatory life cycle plan. So, we try to build in as many -- we have taken the carbon leadership plan and the incentives that in there, we’ve taken them exactly a face value and we’ve then made some of our own assumptions about things we've seen in other markets, taking the federal plan and then taken some of our optionality and used that to make our assessments.

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

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

Okay, thanks. Just one last quick question for Donald. You mentioned Donald I think that there was a decision upcoming in Q3 or Keephills 1 force majeure provision half way. Can you remind me again how much -- what’s provisioned?

We haven’t disclosed the provision, Pau. So, it’s like 50% of the potential claims have been provided for but we are not disclosing the fix rate for each of the claim but back in 2013 and unit was up like nine months, so I guess you can run your own math, on your side.

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

I just wanted to follow-up some earlier questions regarding the sources and uses, which I guess repositioning the capital structure on slide 11. And I didn’t quite understand that answer, because from Q1 presentation and from the Analyst Day presentation, you showed about $200 million more project level financing, and now that’s not there. So, could you just clarify little bit more about, how you make up that short fall, if it sounds like may be that financing has already been accomplished?

That’s like the sources, like looking forward, so the 650 to 900 is after we complete the recent financing of New Richmond arrangement, which raised like 160 million. So, you have to add that to the analysis here, sorry about that. They are consistent.

So, the New Richmond financing that’s already -- that you’ve already completed is excluded from that project level?

Yes.

And so, should I think that obviously, there is some variability around that range. And even with the financing that you completed, there is some potential that you might not achieve the $1.5 billion of cash for the -- to meet your upcoming uses, your $1.5 billion uses. So, how should I think about that?

So, we also have our credit facilities, we have $2 billion of liquidity of which $500 million to $600 million we are using for LC [ph] but we still have $1.5 billion and we’re growing but just we are building up that number a little bit but to basically to take the -- pickup the track on the source and use there.

So, it's just credit facility for funding shortfall?

Yes.

[Operator Instructions] Next question is from Charles Fishman of Morningstar Investment Research. Please go ahead.

Dawn, I just have one quick one left. If I look at slide 13, bullet point two, based on your comment you made answering another question about Sun 7, the replacement of the retiring coal fleet one-third with gas and you invasion 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 plants, is that my understanding 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.

Okay, and obviously that’s a lot less capital than building a new plant?

Right.

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

Just one question here. Dawn, I think you mentioned, off the top, something about RNW evaluation and the free cash flow being spun out at the RNW entity and when you think about growing RNW, do you think that it could become maybe more profitable or there trends could be better if you would purse more third-party acquisitions rather than waiting to grow the entity solely by dropdown acquisitions, what's the perspective there?

Yes, I think it's kind of -- well, three is things, right? You can do acquisitions, you can do greenfield, and greenfield, you to wait, and then, so the two immediate things you can do are acquisitions and dropdown. And then, thing you can wait on is getting better returns by being more patient on greenfield. So, we look at all of those. But if you look at the -- dropdown strategy that we had before was really to take some capital out of TransAlta Renewables and pay down that at TransAlta. We don’t need to do that anymore. So, for us any capital that is freed up in TransAlta renewables should be invested in new projects going forward, those should either be either acquisition or greenfield. And I guess my comments were that the acquisition market is pretty thin. So, if you do acquisitions, you got to be pretty careful because you are 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 on 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 drawn off in there, there will be some assets that will be under-levered. 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.

Just following on that, do you think it might be appropriate then to sort of increase the 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 Renewables is a financing vehicle and really you want to think about it as having the attributes of very stable long-term contracted cash flows from both 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 the defined sort of rules for the different structures? Okay, I got it thanks.

No.

This concludes the analysts’ question-and-answer session of today's call. We will now take questions from members of the media. [Operator Instructions] The first question is from Alesia Fieldberg of CTV News. Please go ahead.

Hi, Dawn, I just want to know how it would affect trend of the customers 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 PPA would probably not 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're 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 would happen 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 the 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 ballparking right now, but?

No, I wouldn't want to speculate. I know there's been a lot of speculation in the media what those amounts would be. I mean, I think as you may know, we're actually haven’t been named as part of the legal dispute which is going on. So, I wouldn't 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 powers from us and we supply it through the power that we have here in the province. So, it wouldn't affect them.

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.