TransAlta Corporation (TAC) Q4 2016 Earnings Report, Transcript and Summary

Good morning, my name is Mike and I will your conference operator today. At this time I would like welcome everyone to the TransAlta Corporation 2016 Fourth Quarter Results Conference Call and Webcast. All lines have been placed on mute to prevent any background noise. After the speaker’s remarks, there will be a question-and-answer session. [Operator Instructions] I will now turn the call over to Jaeson Jaman, Manager, Investor Relations. You may being your conference.

Thank you, operator. Good morning, and welcome to the TransAlta fourth quarter 2016 conference call. With me today are Dawn Farrell, President and Chief Executive Officer; Donald Tremblay, Chief Financial Officer; and John Kousinioris, Chief Legal and Compliance Officer. The call today is webcast, and I invite those listening on the phone lines to view the supporting slides, which are available on our website. A replay of the call will be available later today and the transcript will be posted to our website shortly thereafter. All information provided during this conference call is subject to the forward-looking 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 fourth quarter and annual results discuss the performance against our goals and priorities for 2016 and review our 2017 goals. After these prepared remarks, we will open the call for questions. I will now turn the call over to Dawn Farrell.

Thanks, Jaeson, and welcome to everybody on the call. Today I’m going to review our results in 2016 and how they positioned us for 2017 and beyond. You all know our strategic themes of balance wind execution advantage and history repeat. So let me start there with balance wind. In 2016, we achieved our top priority when we reached a mutually acceptable coal transition agreement with the government of Alberta. With this agreement in place, we can now focus our transition plan towards gas and renewables for generating clean power. Now as a reminder, our coal transition plan results from two key agreements with the provincial government, each critically important for investors. First, the off-coal agreement establishes 14 annual payments of $37.4 million from the Alberta government to TransAlta that will total more than $500 million by 2030. We do expect the first payment will be made in the third quarter of this year and these payments compensate our investors and our debt holders for assets that cannot run on coal past 2030 and our market here. The second equally important component of the transition agreement is a memorandum of understanding or for short what we call the MOU. Now this MOU set up the terms for working together with the Alberta government to implement and accelerate the goal of the climate leadership plan. And when elements of this MOU are executed, we can make six significant investment decisions, including first, when and how to extend the useful lives of our coal plants by converting them to natural gas; and secondly, when to invest in a Brazeau pump storage project. We believe this vital infrastructure is needed to support the reliability of the future internet renewable generation that will be built here in Alberta. The MOU also set up the work we will do to ensure that new rules in the capacity market, and new rules for performance standard create a level plain field for existing and new generators, the MOU also direct work to get the right standards for the coal-to-gas conversion. Our work under the MOU is ongoing. Today, we like other generators in the province are working with the government and the IESO to create new rules and systems that will support a functioning resilient capacity market. We're committed to working with the IESO to ensure that a capacity market is in placed by the beginning of 2021 just the year, just after when the PPAs roll out to coal fleet, and we're committed to our customers that this new market will lead to affordable power prices in the province for them. Work is also underway on the federal coal-to-gas conversion regulations. We expect these new regulations will support our strategy to extend a useful life of our coal asset and maintain the cash flows from these converted units post 2030. We are seeing the alignment needed to use existing infrastructure as backup to the new renewables that will be developed in the market. Now this is really important for our investors. The new capacity market and the opportunity to extend the lives of our coal asset has competitively positioned us to refinance our debt and create the financial flexibility needed to make new investments for the future. The move to the capacity market was the breakthrough we needed for investors to be confident in the cash flows from our plant beyond the existing PPA, this was indeed the most important news for the company and 2016. So to conclude focusing on balance, we’ll meet the goals establishing the climate leadership plan, we’ll reduce the cost of the transition off-coal for consumers, and we’ll allow incumbent generators such as ourselves to be a pivotal part of the future apparent supply here in the province, and this is truly a win-win for TransAlta and for Albertans. Our second strategic theme is execution advantage. This year we delivered performance that was in line with our 2016 financial guidance and expectations including comparable EBITDA of $1.1 billion, which was 6% over 2015, comparable FFO of $763 which was 3% over 2015 and comparable cash flow of $299 million, which was in line with what we delivered in 2015, which was slightly higher to $315 million. We achieved these results during the lowest commodity price cycle ever experienced in Alberta with the average spot price was just $18 a megawatt hour. Operationally, we delivered adjusted fleet availability of 89.2% just slightly better than our performance in 2015 of 89%. And during the year we repositioned our capital structure by raising approximately $352 million of non-recourse project financing. These financings better aligned our debt maturities with contract to cash flow. Additionally, we did strengthen our balance sheet by reducing debt by over $350 million in the year, which we did by using a combination of cash flow and the proceeds of the $173 million that we received from the sale as some of our Canadian gas and renewable assets to TransAlta renewable. We also received a very favorable decision in the Keephills 1 Force Majeure arbitration confirming that our Alberta coal operations team made the right decision when they took that unit out of service. This decision allowed us to reverse accounting provision of approximately $80 million. Investments we made in new renewable assets in 2015 contributed $25 million in EBITDA we can prove EBITDA run rate of this portfolio of assets. And of course, as you know, we advanced the construction of South Hedland, which is expected to be in service in a few months and expected to be on schedule and on budget. So all in all I believe we had a tremendous year. Our third strategic theme is history repeat. Imagine 105 years ago TransAlta built in commissioned Alberta’s first hydro asset. These plants also operate today within our very high value Alberta Hydro portfolio that now totaled about 900 megawatt. In Alberta’s new carbon constrained environment exiting renewable assets and new projects such as 600 megawatts to 900 megawatts Brazeau pumped storage hydro expansion will have significant value for investors. This ambitious project will serve as a storage battery and support the renewable power plant to be added under the climate leadership plan. This project will become yet another piece of our long history of building successful hydro projects in the province. Since our last call, we've continued to progress the project. We've already met our race to meet with achieved of the indigenous communities that live around the Brazeau area, and we’ve progressed environmental and geo technical studies. Now we're not spending a lot of money here of its low cost work is being done to prepare for discussions with the Alberta government regarding a long term capacity contract. With that I'm going to turn the call over to Donald for a review of our fourth quarter and annual results and an update on our financing strategy.

Thank you, Dawn. Slide 7 provides the financial highlights for Q4 2016 and the annual results again our 2016 guidance. The annual comparable EBITDA excluding the K1 provision adjustment came in at $1.1 billion, 6% or $60 million better than last year. The higher EBITDA resulted from a return to normal performance from our energy marketing business, which contributes $52 million of EBITDA up from $37 million last year. The active management of our Alberta water resource that result in an additional $10 million of gross margin in a low price and run also contribute. The hydro assets in Alberta are contracted under a 20 year PPA that expires in 2020. The PPA contract provides us with flexibility to optimize our margin to our physical delivery in the power markets. $25 million of EBITDA from renewable asset acquired in late 2015, this was the first full year contribution from these assets and finally $15 million reductions of our overhead. During the year we continue to over efficiency and collectivity again at our Sun Hills mine. However these gains were upset by the unplanned outage of a large dragline as well as outage caused by heavy rain in the third quarter. As a result our coal costs remain unchanged in 2016. Low price did not materially impact our Alberta coal generation, as it largely hedge, but it negatively impact our margins for Alberta wind and Centralia. FFO in 2016 was up $23 million at $763 million. Non-cash mark-to-market gain on physical and financial position as well as long term receivable on a contract with a customer in Australia were included our EBITDA but excludes from FFO. The chart on Slide 8 demonstrates our ability to maintain our EBITDA around $1 billion despite the rapidly declining price environment in Alberta. As you can see from the chart, price in Alberta move from approximately $80 in 2013 down to the current historic flow of $18 per megawatt hour in 2016. Our prudent and effective hedging strategy resulted in average hedge price of $46 per megawatt hour in 2016, again the average market price of $18 and $51 per megawatt hour in 2015 against an average market price of $33. This only reflects the value of our hedging transaction and excludes the value attributable to profit arbitrating in the province. Finally, our comparable free cash flow was $16 million lower than 2015 at $299 million. During the year, we proactively manage our sustaining capital standby we scoping outage work at Alberta coal and differing major maintenance at Sarnia [ph] gas facility to reflect current market conditions which provide a reduction of $28 million, and by differing a $15 million diversion project at our Ghost River facility. We will consider moving forward on this project when price support the investment. As a result of this initiative, we maintain our free cash flow at a similar level to last year despite an increase in distribution to TransAlta Renewables following the dropdown of our Canadian assets in January of 2016. Cash flow from generation, which we refer to as free EBITDA in the past consists of EBITDA less sustaining capital for each of our generation business segment. As Slide 9 show, cash flow from gas and renewables total $582 million in 2016 an increase of $60 million or 11% over last year. The increase is due to the full year contributions from wind and solar assets acquired in 2015, better performance from the hydro facility and the reduction of sustaining capital spending in our hydro and gas business. More importantly our gas and renewable business is now contributing approximately 80% more cash flow from generation than our coal business and generate approximately 60% of the cash flow from our generating asset. Next, I want to take a moment to discuss our 2017 guidance, which was released in December of 2016. Comparable EBITDA for 2017 is expect to land between $1,025 million and $1,135 million. This range is in line with our performance in 2016. The commissioning of the South Hedland project in mid-2017 and the off-coal payment will offset the impact of lower price as our hedge continue to roll off. Also impacting our 2017 result is a planned major turnaround of a dragline at our Sun Hill mine that will impact our mining operations and increase our cost. Interest expense may increase slightly in 2017 depending on the timing of surge in financing and the repayment of debt maturing in 2017 and 2018. Interest expense will also be impacted by capitalize interest on our South Hedland project. You can see from the table at bottom of Slide 10, that our 2017 guidance does not include any significant increase in price for Alberta and Pacific Northwest. In 2016, average price in this region were $18 and $21 respectively were in 2017, we are assuming the spot price to be $24 and $30 in Alberta and $23 to $28 in Pacific Northwest. The continuation of our supply market and a lack of demand growth are key driver to this low price in arrangement in Alberta, the driver of low price in the Pacific Northwest is the price of gas and carbon. We do remain a highly hedge in 2017 at 85% at a price of approximately $45 in both Alberta and Pacific Northwest, which is slightly below the hedge price achieved in 2016. Our sustaining capital for 2017 is in line with our spending in 2016 at $260 million to $280 million. As we progress our coal to gas conversions strategy, our sustaining capital strategy at Alberta coal will be adjust to reflect the remaining life of the plant and its potential conversion to gas. As a result, we expect our 2017 comparable free cash flow to be in the range of $300 million to $365 million or between a $1.04 and a $1.27 per share. The annual dividend offset at $0.16 per share resulting in a payout ratio of approximately 13% to 15%. The capital record to complete the construction of our South Hedland power plant is estimated at $230 million and $250 million, which include a large payment of $160 million to Alberta's power at the completion of commissioning. Over the last two years, we have raised approximately $800 million in project level financing. The market for financing high quality contracted assets with solid counterparty continues to be robust and we expect to further the strategy over the next two years. We plan to rate between $700 million to $900 million over the next 18 months to repay some of our existing debt and support for growth. The closing of our asset sale to TransAlta Renewables early in 2016 and the cash flow generated by the business contribute to a reduction of our net debt by more than $350 million during the year. Year-over-year our liquidity as increased from $1.3 billion to $1.7 billion including approximately $305 million of cash. In January 2017, we also announced the sale of our 51% interest in 88 megawatt non-contracted wind project in Alberta for approximately $60 million. A portion of our liquidity will be used to repay our U.S. $400 million bond that come due in the second quarter of 2017. In the fourth quarter, we also extend our U.S. bilateral credit facility to 2020, as part of this we reduce the facility to U.S. $200 million from U.S. $300 million this reduce our available credit from $2.1 billion to $2.0 billion going forward. Our performance again key financial ratio which has improved significantly in 2016 is set out at the bottom of this slide. At year end, our adjusted FFO to adjusted net debt was 17% this is up from 15.2% at the end of 2015. E-commissioning of South Hedland in 2017 is expected to further enhance this ratio and with a full year contribution to EBITDA in 2018, we expect to achieve our goal our FFO to debt in the range of 20% to 25% and debt EBITDA of 3 to 3.5 times. With that, I will now hand the call back to Dawn for her closing remark.

Thanks, Donald. I want to spend the last few minutes of the call discussing what ahead in 2017 and beyond. In addition to the three strategic themes I described earlier, we are adding a fourth and we’re calling it positioning for competition. All four of these themes are needed to see for us to succeed in our goal to become Canada’s leading clean power company. To increase our competiveness going forward we need to achieve a lower cost of capital. We know that and you know that. And to do this we plan to focus on a couple of our key areas. First, over the medium term, we do intend to continue to allocate a significant portion of our annual free cash flow to the repayment of debt. This will ensure maximum financial flexibility as we move from PPAs to a capacity market. Second, we will demonstrate our ability to reinvest in gas and renewable projects to create value for our shareholders which aligns with our goal of becoming Canada’s clean power company. And then finally, we will continue to create efficiencies and improvement in the existing business, which will free up cash for reinvestment. To be positioned for the ever greater competition we know is coming, we must continue to be more productive and we must continue to strive to be the lowest cost operator. Over the fat past couple of years, we’ve instituted new and more efficient processes lowered our operating costs and improved availability. These productivity efforts have reduced our coal cost down to $22.31 a ton in 2106 from a high of $26.73 in 2013 and our coal mine up north. .: We are also much more diligent in the way we allocate capital for existing assets. This diligence has driven a constant reduction in our sustaining capital while maintaining availability in the range of 88% to 91%. Our sustaining capital has moved from the $300 million to $350 million range in the early part of the decade to a new run rate of $225 million to $275 million, which we expect to continue into the foreseeable future. So as I look ahead over the next three years, I believe that the combination of our path growth and productivity initiatives can improve the run rate of the free cash flow as that we can expect from the business. Changes are also necessary as we prepare our fleet for the capacity market and as we execute the work contemplated by the MOU. As we bring on South Hedland and as we realized additional savings from a productivity investments that we’ve been making. We can begin to increase our target for free cash flow from the $300 million to $350 million range that you now talk about for 2017 to the $400 million plus range as we get into the 2018 to 2020 period. Now, we take the lot to move the needle on free cash flow in a low price environment even with our PPAs in place. But the hard work of the team is giving me the confidence to share that aspiration with our investors. This level of cash flow can help us lower our gas sooner and gives us the cash for growth at both TransAlta and TransAlta Renewables. So I would like to conclude with our 2017 goal. Our first goal is to transition off-coal to gas and renewables by working collaboratively with this government of Alberta on three major initiatives. The first to advance our investment in Brazeau pump storage by working to secure a long term contractual arrangement. The second to work with other stakeholders in the IESO to a system a design of a new capacity market that will be fair to existing and new generator keep prices affordable for consumers and incentivize new investment. And the third is to establish specific terms and conditions convert for converting our coal plant to gas and extending your useful lives to prepare them for the new capacity market. Our second goal is to commission the South Hedland gas power station by mid-2017 and deliver a new cash flow to our investors in TransAlta and TransAlta Renewables. Our third goal is to grow our renewables platform by winning contracted renewable RFP’s in Saskatchewan, Alberta and in Australia. These investments will meet our required risk reward returned criteria and create value for our shareholders. Fourth, we will execute our financing strategy to further strengthen our balance sheet and contribute to a strengthening of our cost of capital. And fifth, we’ll continue to lead in safety and environment performance while delivering against our 2017 financial targets. We are already advancing our plan to achieve each goal, the hard work and the resulting 2016 have demonstrated that TransAlta can achieve a successful transition to a clean power future. I cannot close without thank you the TransAlta employees. In 2016, our TransAlta team putting long hours without tough problems and never gave up. I’m grateful to all of them. 2017 will be another challenging and interesting year, but because of their commitments, their capability, their determination, and tenacity and particularly their strong work ethic. I am confident that we'll be successful. I’d also like to thank the investors who sit with us during a difficult time in 2016. You had faith that our team could successfully navigate through our challenges, and preserve the value in the company that others thought could be loss. We intend to justify your pay as we position to become Canada's leading power company. We look forward to reporting to you on our progress through 2017. And with that I'll turn it over to our Jaeson who will open the lines of call.

Thank you, Dawn. Operator could we start the Q&A session for today.

[Operator Instructions] Your first question is from Linda Ezergailis from TD Securities.

Thank you. I was wondering if you could maybe help us out with your $400 million free cash flow target for 2018. Can you comment on what sort of - what needs to be achieved by then versus what's already kind of baked in from existing assets in your cost structure et cetera. I guess some I'm most interested to know I mean we all have a view on prices, but to the extent that you can talk to what sort of recovery might be embedded in there I'd appreciate that, but also what sort of further cost reductions might be needed to achieve?

I can start and maybe Dawn feel free to comment after. Like it's basically like continue of work that we're doing on our O&M and administration cost like we believe that even though we did great work over the last two or three years there's probably still more that we can do, and we have team working on reducing our mining cost like improving our coal operation, reducing our overhead, so there are people working on this, and there is no specific goal that I can share with you, but I can tell you that people are working hard at all level to basically reduce those costs. The sustaining capital is also an important element like Dawn mentioned like the new run rate that will have and clearly we’ll progressively get to the lower end of that range as we go closer to 2020, but overtime as we're getting closer to the termination or the expiration of those PPA, you will see us like managing our CapEx differently and improving on that front as well. So those are the two controllable that we have. We're not speculating on power price. We don't believe our price will pick up in the new significant way in 2017 or 2018, though like there's nothing in this like counting on a significantly price increase in the province. So and keeping like most of our generation is contracted or hedge so like price doesn't have a huge impact on this. So it's basically like working on lower cost efficiency, reducing our CapEx overtime as we're getting closer to the PPA expiration. So Dawn I don’t you want to comment?

Yeah, I think I would just add one thing. Remember in 2018 we'll have our first full year tough headwind, and typically when new asset come into the portfolio, they don't have that much capital requirement at the front end of the curve. So our guidance on capital includes bringing on that asset and you know includes the kind of efficiencies that we expect to be able to make as we transition towards the future where we'll be converting some of those plans. And just in terms of your question about how much - if it's a very small amount of aspirational dollars in there from you know it’s based on a run rate that we know that we can achieve under productivity projects. We currently have an underway with employees and the full year of Hedland and the work we've done on the capital. We know that we have no - we'd love to see prices go up that would be awesome, but we're not building that into our plans that between now and 2020. And I think the other thing that's important there is, all of that is in the current environment that we live in, there's always changes that come out as Linda to like we don't exactly know what's going to happen here with the balance improve. So if there were some changes there in terms of PPAs and stuff like that we have to reassess, but on our current PPA is the way to set up our current business the way it’s set up that's where we're gaining the confidence.

Okay, that's helpful. Maybe just to follow-up in your annual report, you talked about evolving in implementing a more competitive business model and cost structure that works for more distributed gas from renewable plants across several regions. Can you just describe a little bit as to what that might entail and again I'm assuming that's not embedded in the $400 million costs, but for free cash flow, but to comment on how that kind of fits in with your aspirations on the rest of your company on the coal and mining side et cetera?

Yeah, so the work that - so remember you know we have a cost structure for a company that has big coal units with lots and lots of work to get done at those units and lots of PLs and things like that. So as we look forward and we look at the mix between coal and gas and renewable, you know there is a different kind of cost structure that can be achieved. So we're really working with our gas and renewables team to start to set that up, so that effectively they become the cost structure for the future, and as we convert coal plants they kind of get attached into that new cost structure. So that's kind of broadly how we're thinking about it. Linda it will involve significant, we think as we go forward it will involve as significant I can that now don't hear that like all the sudden we've got a $100 million IT project, our IT team is fabulous. These guys know how to shift from what they do internally, they use outsourcing, they use the cloud, they're working heavily with suppliers, so that we affectively have the kind of operation that can be heavily data dependent and of a lower cost structure. So those are the kinds of things we’re thinking about. Now that shift in there is not built into that target. That would be for as we as we move out of the 2020 period and move into the capacity market.

That's great. Thank you for the context. I'll jump back in the queue.

The next question is from Robert Hope from Scotiabank.

Good morning, thank you. Just maybe a follow-up on Linda’s question regarding the $400 million of free cash flow, what assumptions are you making regarding the Mississauga plant there?

We just renegotiate the contract, so we will receive like our payment in 2017 and 2018 and then the contract is willing off and the cash flow go away, but we're basically able like our plan is assuming that will make it up.

But it's not - we're not assuming that you roll over that contract or that, right now we have not built into our cash flow assumption anything with that plant. We have people that are working on thinking about if they can find a way to get some stepping that plant, but that's not in that in that target.

All right, that is helpful. And then just in terms of the balancing pool. What would you view as the potential implications of any terminations of the PPAs that they now hold?

It shown if you aren’t responding, I mean, we - if there is a termination from the balancing pool I mean clearly those units were coming back to TransAlta with potentially the termination payment and would be coming our way as the consequent of the termination of those arrangements prior to their end of life, and then we would integrate the offers of those plants in to our own system including the bidding of those plants in the Alberta marketplace in the manner that we believe is appropriate.

All right, that’s helpful. Thank you.

The next question is from Robert Catellier from CIBC World Markets.

Hi, good morning. I wanted to follow-up on the Mississauga plant here, I’m understanding it’s not in your outlook beyond existing contract. Maybe you can just spend a minute on what you’re doing to try to maximize value from that asset?

Don you explain that.

So like the team is already - like it’s more than just the Mississauga, we also have like Ottawa, we also have Windsor. So there’s other facility in Ontario that like our team are working on to capture more value to extend basically devalue that we’re making with those project. There’s also the Sarnia facility that is part of that mix. So it’s not just Mississauga, it’s a broader discussion that we’re having with our team in term of like surfacing more value from our Ontario gas asset depending on where Ontario goes into basically the future.

Yeah. Just to be clear. We have - so the way to contracts especially we get paid for 2017 and 2018. At the end of 2018, we still have the plant. We have a decision, we had a decision to make whether or not we would just close the plant down and try to sell up the part or continue to keep it there and mark power the best. We’ve made a decision that we’ll keep it for now and we have a team focus on whether or not there’s the potential to add additional revenue to a call that will likely come in Ontario for capacity to back-up their market or selling across the border. But as I said, currently that would be icing on the cake at this point, we’ve built in as the best project stayed there not fall the reason we decide to not fall is its very cheap to do that and be there’s good potential, there’s more potential for that plant for a capacity market post 2020. So it does have some value in that post 2020 period. So spending a little bit of money making sure that it doesn’t rock this is probably not a bad idea, but the teams will see what else they can do.

Okay. That’s color is looking for, and just a follow-up on the Brazeau pump storage project. It kind of looks a little bit like a catch 22 in terms of if you want to reduce your capital cost, which obviously makes moving these projects for it, but on that specific project, do you think you need a reduced or lower cost of capital to make that project work or is really the mirror image that moving forward look at what the project because of the nature of the project might actually reduce your cost of capital?

I think it’s exactly what you say. I think so the way I look at it is, what makes that project happen is a long term contract. In hydro project you’re not able to really develop them and take risk on them in emerging market. It’s impossible, you can’t go, there’s no investor going to line up and give you money for a five year capacity contract on a $3 billion investment where you have to make your money on the differential between high prices and low prices, so it requires a contract. And what unique about that project is under a carbon tax under $30 or $50 carbon tax even with the performing standards there’s no question that anything that doesn’t create carbon but provide capacity and storage is extremely valuable, and so we’ve done not that we’ve got it more valuable than any gas fired capacity that you could put in to backup renewable. So it’s got great attributes. Now, if we can win some sort of competition to be able to get into a long term contract so that some of the renewables that - right now Alberta is going to call for 5000 megawatts, if of that 5000 megawatts, but say they satisfied 2000 for renewables and call - 2000 for hydro and coal for hydro and we competed in that in one, I think the government pretty clear to bring on large hydro in Alberta you need those contracts. I think we got the contract that of course it gives us a big future and lowered the cost of capital. I think secondly, though we probably look at the project and finance that separately on the basis of its contract, and part of the work we’re doing is also thinking about whether or not there’s a role here for the Canadian infrastructure bank, because to the extend you can get even a lower cost of capital out of that, that’s what really gives Albertans low prices in the future, and it really makes the move from coal to gas and renewables less costly overall. And we all know that consumers are really want lower prices as they go forward even though they want the environmental benefit. So I think just kind of sum it up, winning the project will help the mother ship company, but we’ll probably look at it as an independent project that will finance separately and the more low cost of finance that we can get to lower the cost of the PPA so that’s currently how we’re thinking about it.

Okay. Thank you. It’s very helpful answer.

The next question is from Ben Pham from BMO.

Okay. Thank you. On Slide 11, you mentioned on the debt side $700 million to $900 million in a both point below the monetization of coal payments, and I’m not sure I missed that, but is that - are you suggesting that you monetize the future streams and that will result in a pretty big portion of that debt that’s being repaid?

So first like the finance [ph] and monetization of our off-coal payment. The off-coal payment is part of that, but it’s only like a portion of it. There’s other like a contracted asset that we are currently working on financing that also including the $700 million $900 million, that will achieve over the next like 18 months.

So your base plan now is as you will monetize the off-coal payments?

Yeah. So that’s what our plan. The timing is still uncertain, but basically it’s our plan to monetize that payment overtime.

Okay. That’s what I wanted to clarify. And can you talk about your hydro plant specifically and how you think about how those plants going to operate and capacity market and is it - could it be different then today process maybe some constraints that the contract has right now the balancing pool or maybe there’s just maybe give some utilization and efficiency that you could crystallize in a different market.

Yeah. Well first of all, just those hydro plants have more value outside the PPA than the PPA gives us today, so just be clear the PPA constrains the value to TransAlta a huge value in those hydro plants, so that’s kind of the first principle. As we think about the capacity market, I mean there is first of all we can bid capacity out of the hydro projects into the capacity market, but we’d also want to - we also have to balance that in terms of the ancillary services market, because those plants have really strong value here in the market for that. So and then of course the third value is energy, the energy value is never that they value in the hydro it’s always our ability to ship and capture either ancillary services revenue or capacity market revenue. So when we do our modeling, we think that there is there’s kind of that an equivalent value that available as we go forward into the market with that because of that the biggest thing the hydro plants have is their flexibility, they have the - they are the fact capability there is nobody can beat that. And what’s really interesting about the technology that we’re looking after Brazeau, is it - it’s incredibly fast, so it beat everything. And those are the kinds of attributes you need because as you know one of the biggest issues with solar if the product decide to do more solar is when the sun goes down it goes off immediately you have to start unit separately quickly and the same with wind. So we think it’s - we’ve always known the value beyond the PPA, and I think in the capacity market it’s just restructuring that value differently.

And can I clarify the enhancement of value is that, is that more on the production side where you are may not be motivated to produce the stream level today or that something else?

So given like the capacity factor of hydro is roughly 20% so like we need to look at the hydro speaking plan. Like both of them have storage, so we can manage the generation, the Brazeau project even if forget about the pump storage, which increases, but like the current hydro project that we have at Brazeau it's a big speaking plan that we own, provide a lot of value not only the energy market, because clearly we can pick the best 20% hour and generate value there. But it's also the answer we value that it’s created for a province, and a lot of those revenue like today are kept to the PPA that we have, and addition to this like post 2020 they will be eligible to participate in the capacity market and an additional revenue.

Think about it this way currently the hydro PPA create value for us and balancing tool and the reason it does it because it was based on a very low cost base at the time that it was set up for the 20 years. And so it's been a huge benefit to Alberta and that PPA that value was always to come back to TransAlta and it will come back to TransAlta, so you go from that cost of service type financial contract to a market based contract, and that's the move that creates the additional value.

Okay, that's very helpful. Thanks everybody.

[Operator Instructions] The next question is from Robert Kwan from RBC Capital Markets.

Good morning. Dawn I need to follow-up you made a couple of statements here that lead me to think maybe incorrectly that there's been some discussions around the capacity market in that framework, and I guess the first one your comment being that you could be at the hydro capacity into the capacity market is that been confirmed and what that framework whether it's going to follow the PGM framework or something else?

No, no, I mean discussions in the capacity market or early days and so all of this is based on our own work that we've been doing - our own analytics that we've done on capacity markets and we create the analysts here. So we've got - we've been modeling capacity markets with different attributes to them, some based on PJM, some based on other markets. And then what we do is, we pressure test our assets against those to see what we think they'll look like, so that - but the actual rules in Alberta I can imagine I mean and I'm not lobbying here, I thought, but I can't imagine why you wouldn't want the Alberta Hydro to be a capacity in the market here.

To do the hydro with the back step that they have in the storage, that they have like provide significant amount of capacity into province.

Yeah.

So that 900 megawatt need to be going nice I believe.

Okay. And then I guess the other statement you made a little bit was just kind of what your pump storage facility or your existing hydro facilities having a much, much better ability to be a low load following resource, do you expect there to be within the framework some sort of premium or put differently a penalty for things like solar and wind that won't be load following?

Well, I mean, let’s - I'm just practically 31 years of experience, thinking about doing the modeling and then also thinking about what changes. If you bring in 5000 megawatts of renewables and let's say 3000 of them are more intimate like solar and wind to a system as small as this. The volatility will increase dramatically, because you're going to want to capture every single hour that the wind is blowing and the sun is shining. You're going to want to get those low cost renewables into the system. In order to do that you've got to have - you're going to have to all have been needful and have to more load following. And you're going to have to have a market that enables the backup of those renewables and particularly if you're bringing them in on long term contracts with what are the contracts - yeah if you’re doing contract for differences over 20 years and at the same time you're trying to ensure that the capacity generators have compensation, so that they stay in the game, you have to create an environment where those values are created. So if you look at Brazeau with its storage capability, let's say we could get it 900 megawatts and we think we can, so the difference between two and three, so we're kind of modeling both. That's a significant storage for that wind and hydro, and it actually creates significant value for those wind and hydro contract.

Okay. If I can maybe ask about, how you’re thinking about the capacity market maybe a little bit longer term. If you think about the Brazeau pump storage and the potential capacity contracts on one hand that would be a really great, development or long term contract there. But then as you think about other developments maybe like a Sun 7, how do you approach the capacity market for those other investments kind of knowing that the government is willing to sign contracts for other generation outside of the general capacity market framework?

Yeah, what I've seen - so I kind of have it in three different buckets, right in my head, and again this is all speculation, I'll say that for the lawyers in the room, I'm speculating on what the capacity market looks like, so this isn't to think about value for our companies just to think about how you would do it here. So in my mind, if you if you take something like our coal-to-gas conversion you know if it's a small amount of capital and affectively if the capacity market had three to five year contracts in it. We can cope with that right. We can cope with that contract structure against those existing asset that makes sense to me. If you look at hydro, I think, people who work on long term hydro on a good side and you know I've got five years at B.C. Hydro where we had very, very big hydro, but if you're talking about bigger hydro here in the Alberta market the risk on hydro is always that front end and regulatory work, which takes four to five years and the construction time frame, which takes four to five years. No one is going to that $3 billion on the possibility that when they get there they'll be a five year capacity contract that they can bid on and make a bunch of money, like you just not going to do it or at least we're not going to do it. So I think there the reason that you're doing sort of a capacity contract for different similar to what you're doing with the wind, if you're doing that because that allows that kind of renewable asset to come into the province, so that's a different bucket. And I think all of the renewables frankly, all 5000 megawatts will have those kinds of kind of long term contracts. So then in the middle at least new gas effectively, and so our view what we've seen is in other markets and we're doing some more work on this Robert. There are investors there seem to be investors that will bring some money into new gas in that fight with contracts that are in that kind of five to seven year range, because gas is a easier to get regulatory approval for, and faster to build. So you've got a shorter timeframe to when the capacity market is and you can start to make some best on that. So I think if you thought about it, you're kind of three to five year capacity contract for existing your long term for renewables and then the gas is somewhere in that five to seven years. Now that just me Dawn Farrell talking, there’ll be stakeholders with all sorts of views the idea will have a view, but I think as functioning market could ensue if you kind of looked at it that way.

Got it. And just to you comment there seem to be investors willing to bring money in for gas in the three to five year contract range to TransAlta one of those investors?

No. And I said five - more five to seven for new gas. No, my bet is on converted gas. I will –a our plans converted my view is they can start out at 60%, 70% capacity factors and they can drop down over time and they can back up the grid, I'm fine to bring gas on to do that. But I would not take a bet personally, I mean they'll get a new CEO here eventually and that person might be different, but they'd have to knock me over to get an investment where unless Robert the government guaranteed me the same kind of contract that we have on South Hedland, so or in Solomon if I had a fee schedule in the contract, that said if you change your mind and you don't want carbon anymore, and you want to shut down these assets, and this is what you get paid on the day we make that decision, I might invest in that product.

Got it. Okay and then I can just finish here with improving free cash flow, and how you're thinking about coal availability, so 2016 you were below target, but really just more so looking forward is 87% really where you want to be given the new coal rags and you have the ability to further optimize the capital versus availability curve.

So I think that target is probably appropriate like between now and like ramping down overtime probably pass 2020 the number is different for sure, because like it's more like merchants. And like you have to understand that the availability have less value when price is $20 than when prices $60, so that’s the other thing that you have to have in the back of your mind when you're looking at availability.

Okay, that's great. Thank you very much.

The next question is from Charles Fishman from Morningstar Research.

Good morning Dawn.

Charles we lost you.

We lost you.

Charles Fishman your line is open.

Operator can we just to the media calls, seems that Charles has a communication issue there.

[Operator Instructions] At this time we have no additional questions I will turn the call back over to the presenters.

Thank you very much, and we’ll end the Q4 call.