TransAlta Corp (TAC) 2016 Q4 法說會逐字稿

Good morning. My name is Mike and I will be your conference operator today. At this time, I would like to welcome everyone to the TransAlta Corporation 2016 fourth-quarter results conference call and webcast. (Operator Instructions)

I will turn the call over to Jaeson Jaman, Manager, Investor Relations.

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 qualifications which is set out in the slide deck and detailed in our MD&A and incorporated in full for the purposes of today's call. The amounts referenced are in Canadian currency unless otherwise stated. The non-IFRS terminology used including comparable gross margin, 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 transfer the call to Dawn Farrell.

Thanks, Jaeson, and welcome to everybody on the call. Today I am going to review our results in 2016 and how they positioned us for 2017 and beyond. You all know our strategic themes of balance wins, execution advantage, and history repeats, so let me start today with balance wins.

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 our investors.

First, the off-coal agreement establishes 14 annual payments of CAD37.4 million from the Alberta government to TransAlta that will total more than CAD500 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 debtholders for assets that cannot run on coal past 2030 in our market here.

The second equally important component of the transition agreement is the memorandum of understanding or, for short, what we call the MOU. Now this MOU sets up the terms for working together with the Alberta government to implement and accelerate the goals of the Climate Leadership Plan. And when elements of this MOU are executed, we can make 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, went to invest in the Brazeau pump storage project. We believe this vital infrastructure is needed to support the reliability of the future intermittent renewable generation that will be built here in Alberta.

The MOU also sets out the work we will do to ensure that new rules in the capacity market and new rules for performance standards create a level playing field for existing and new generators. The MOU also directs 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 ISO to create new rules and systems that will support a functioning, resilient capacity market. We are committed to working with the ISO to ensure that a capacity market is in place by the beginning of 2021, the year just after when the PPAs roll off the coal fleet, and we are 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 the useful lives of our coal assets 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 assets 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 plants beyond the existing PPAs. This was indeed the most important news for the Company in 2016.

So to conclude, focusing on balance will meet the goals established in its Climate Leadership Plan, will reduce the cost the transition off coal for consumers, and will allow incumbent generators, such as ourselves, to be a pivotal part of the future power 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 CAD1.1 billion, which was 6% over 2015; comparable FFO of CAD763 million, which was 3% over 2015; and comparable cash flow of CAD299 million, which was in line with what we delivered in 2015, which was slightly higher at CAD315 million. We achieved these results during the lowest commodity price cycle ever experienced in Alberta, where the average spot price was just CAD18 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 CAD[362] million of nonrecourse project financing. These financings better align our debt maturities with contracted cash flow. Additionally, we did strengthen our balance sheet by reducing debt by over CAD350 million in the year, which we did by using a combination of cash flow and the proceeds of the CAD173 million that we received from the sale of some of our Canadian gas and renewable assets to TransAlta Renewables.

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 provisions of approximately CAD80 million. The investments we made in new renewable assets in 2015 contributed CAD25 million in EBITDA, which improved the 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 repeats. Imagine 105 years ago, TransAlta built and commissioned Alberta's first hydro asset. These plants all still operate today within our very high-value Alberta hydro portfolio that now totals about 900 megawatts.

In Alberta's new carbon-constrained environment, existing renewable assets and new projects, such as the 600 to 900 megawatt Brazeau pump storage hydro expansion, will add significant value for investors. This ambitious project will serve as a storage battery and support the renewable power plants 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 have continued to progress the project. We have already met or arranged to meet with the chief of the indigenous communities that live around the Brazeau area and we have progressed environmental and geotechnical studies. Now we are not spending a lot of money here. All this low-cost work is being done to prepare for discussions with the Alberta government regarding the 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 in our 2016 guidance. The annual comparability, excluding the K-1 provision adjustment, came in at CAD1.1 billion, 6% or CAD60 million better than last year. The higher EBITDA resulted from a return to normal performance from our energy marketing business, which contributed CAD52 million of EBITDA, up from CAD37 million last year.

The active management of our Alberta weather resource that resulted in an additional CAD10 million of gross margin in a low price environment also contributed. 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 market.

CAD25 million of EBITDA from renewable assets acquired in late 2015. This was the first full-year contribution from these assets. And, finally, CAD15 million reduction of our overhead.

During the year we continued to deliver efficiency and productivity gain at our SunHills mine. However, these gains were offset 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's largely hedged, but it negatively impacted our margins for Alberta wind and Centralia. FFO in 2016 was up CAD23 million at CAD763 million. Non-cash mark-to-market gain on physical and financial positions, as well as long-term receivables on a contract to a customer in Australia, were included in our EBITDA but excluded from FFO.

The chart on slide 8 demonstrate our ability to maintain our EBITDA around CAD1 billion, despite the rapidly declining price environment in Alberta. As you can see from the chart, price in Alberta moved from approximately CAD80 in 2013 down to the current historic low of CAD18 per megawatt hour in 2016. Our prudent and effective hedging strategy resulted in average hedge price of CAD46 per megawatt hour in 2016, again the average market price of CAD18, and CAD51 per megawatt hour in 2015 against an average market price of CAD33. This only reflects the value of our hedging transaction and excludes the value attributable to [proprietary] trading in the province.

Finally, our comparable free cash flow was CAD16 million lower than 2015 at CAD299 million. During the year we proactively managed our sustaining capital spend by rescoping outage work at Alberta coal and deferring major maintenance at the Sarnia gas facility to reflect current market conditions, which provide a reduction of CAD28 million, and by deferring a CAD15 million diversion project at our Ghost River facility. We will consider moving forward on this project when price supports 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 drop-down of our Canadian asset 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 segments. As slide 9 shows, cash flow from gas and renewables totaled CAD582 million in 2016, an increase of CAD60 million, or 11%, over last year. The increase is due to the full-year contribution from wind and solar asset acquired in 2015, better performance from the hydro facility, and a 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 that our coal business and generates 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 expected to land between CAD1.025 billion and CAD1.135 billion. This range is in line with our performance in 2016. The commissioning of the South Hedland project in 2016 and the off-coal payment will offset the impact of lower price as our hedge continue to roll off.

Also impacting our 2017 results is a planned major turnaround of a dragline at our SunHills mine that will impact our mining operation and increase our cost.

Interest expense may increase slightly in 2017 depending on the timing of certain financing and the repayment of debt maturing in 2017 and 2018. Interest expense will also be impacted by capitalized interest on our South Hedland project.

You can see from the table at the 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 these regions were CAD18 and CAD21, respectively, where in 2017 we are assuming the spot price to be CAD24 and CAD30 in Alberta and CAD23 to CAD28 in Pacific Northwest.

The continuation of an oversupplied market and a lack of demand growth are key drivers to this low price environment in Alberta. The driver of low price in the Pacific Northwest is the price of gas and [carbons]. We do remain highly hedged in 2017 at 85% at a price of approximately CAD45 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 CAD260 million to CAD280 million. As we progress our coal-to-gas conversion strategy, our sustaining capital strategy at Alberta coal will be adjusted to reflect the remaining life of the plan and its potential conversion to gas. As a result, we expect our 2017 comparable free cash flow to be in the range of CAD300 million and CAD365 million, or between CAD1.04 and CAD1.27 a share. The annual dividends are set at CAD0.16 a share resulting in a payout ratio of approximately 13% to 15%.

The capital required to complete the construction of our South Hedland power plant is estimated at CAD230 million to CAD250 million, which includes a large payment of CAD160 million to Horizon Power at the completion of commissioning.

Over the last two years, we have raised approximately CAD800 million in project-level financing. The market for financing high-quality contracted assets with solid counterparties continues to be robust and we expect to further this strategy over the next two years. We plan to raise between CAD700 million to CAD900 million over the next 18 months to repay some of our existing debt and support our growth.

The closing of our asset sales 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 CAD350 million during the year. Year over year our liquidity has increased from CAD1.3 billion to CAD1.7 billion, including approximately CAD305 million of cash. In January 2017, we also announced the sale of our 51% interest in an 88 megawatt non-contracted wind project in Alberta for approximately CAD60 million. A portion of our liquidity will be used to repay our $400 million bond that comes due in the second quarter of 2017.

In the fourth quarter, we also extend our US bilateral credit facility to 2020. As part of this we reduced the facility to $200 million from $300 million. This reduced our available credit from CAD2.1 billion to CAD2 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.

The 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 of FFO to debt in the range of 20% to 25% and debt to EBITDA of 3 to 3.5 times.

With that I will now hand the call back to Dawn for our closing remarks.

Thanks, Donald. I want to spend the last few minutes of the call discussing what's ahead in 2017 and beyond.

In addition to the three strategic themes I described earlier, we are adding a fourth and we are calling it positioning for competition. All four of these themes are needed for us to succeed in our goal to become Canada's leading clean power company. To increase our competitiveness 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 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 leading clean power company. And then, finally, we will continue to create efficiencies and improvements 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 past couple of years, we have instituted new and more efficient processes, lowered our operating costs, and improved availability. These productivity efforts have reduced our coal costs down to CAD22.31 a ton in 2016 from a high of CAD26.73 in 2013 at our coal mine up north.

At Centralia we have lowered our weighted average coal costs by CAD7 a ton over the same period. We have also reduced our OM&A, as the chart demonstrates, by approximately 10%, or CAD50 million, since 2014. And that is at the same time that we have been changing assets, adding assets, and achieving a fleet of around 10 gigawatts. This cost reduction equates to CAD5 a kilowatt.

We are also much more diligent in the way we allocate capital to our 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 CAD300 million CAD350 million in the early part of the decade to a new run rate of CAD225 million CAD275 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 past growth and productivity initiatives can improve the run rate of the free cash flow 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 realize additional savings from the productivity investments that we have been making, we can begin to increase our target for free cash flow from the CAD300 million to CAD350 million range that Donald talked about for 2017 to the CAD400 million-plus range as we get into the 2018 to 2020 period. Now it takes a 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 debt sooner and gives us the cash for growth at both TransAlta and TransAlta Renewables.

I would like to conclude with our 2017 goals. Our first goal is to transition off coal to gas and renewables by working collaboratively with the government of Alberta on three major initiatives: the first, to advance our investment in Brazeau pump storage by working to secure long-term contractual arrangement; the second, to work with other stakeholders in the ISO to assist in the design of a new capacity market that will be fair to existing and new generators, keep prices affordable for consumers, and incentivize new investment; and the third is to establish specific terms and conditions for converting our coal plants to gas and extending their useful lives to prepare them for the new capacity market.

Our second goal is to commission the South Hedland gas-fired station by mid-2017 and deliver new cash flows to our investors in TransAlta and TransAlta Renewables. Our third goal is to grow our renewables platform by winning contracted renewable RFPs in Saskatchewan, Alberta, and in Australia. These investments will meet our required risk/reward return 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. Fifth, we will continue to lead in safety and environment performance while delivering against our 2017 financial targets. We are already advancing our plans to achieve each goal. The hard work and the results in 2016 have demonstrated that TransAlta can achieve a successful transition to a clean power future.

I cannot close without thanking the TransAlta employees. In 2016, our TransAlta team put in long hours, resolved tough problems, and never gave up. I am grateful to all of them. 2017 will be another challenging and interesting year, but because of their commitment, their capability, their determination and tenacity, and particularly their strong work ethic, I am confident that we will be successful.

I would also like to thank the investors that stood with us during the difficult times in 2016. You had faith that our team could successfully navigate through our challenges and preserve the value in the Company that others that could be lost. We intend to justify your faith 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 will turn it over to Jaeson, who will open the lines for calls.

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

(Operator Instructions) Linda Ezergailis, TD Securities.

Thank you. I was wondering if you could maybe help us out with your CAD400 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, etc.?

I guess I am 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 would appreciate that. But also what sort of further cost reductions might be needed to achieve that.

I can start and maybe, Dawn, feel free to comment after. Basically continue the work that we are doing on our O&M and administration costs. 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 costs, like improving our coal operation, reducing our overhead, so there's people working on this.

There's no specific goal that I can share with you, but I can tell you that people are working hard at all levels to basically reduce those costs.

The sustaining capital is also an important element. Like Dawn mentioned, like our -- like the new run rate that we will have, and clearly we will progressively get to the lower end of that range as we go closer to 2020. But over time as we're getting closer to the termination or the expiration of those PPA, you will see us managing our CapEx differently and improving on that front as well. So those are the two controllable that we have.

We are not speculating on power price. We don't believe power price will pick up in any significant way in 2017 or 2018, so there's nothing in this counting on a significant price increase in the province. Most of our generation is contracted or hedged so price doesn't have a huge impact on this. So it's basically like working on our cost efficiency, reducing our CapEx over time as we're getting closer to the PPA expiration.

Dawn, I don't know if you want to add anything.

I think I would just add one thing. Remember in 2018 we will have our first full year of South Hedland. And typically, when new assets coming to the portfolio they don't have as much capital requirement at the front-end of the curve. So our guidance on capital includes bringing on that asset and includes the kind of efficiencies that we expect to be able to make as we transition towards the future where we will be converting some of those plants.

And just in terms of your question about how much -- it's a very small amount of aspirational dollars in there. It's based on run rates that we know that we can achieve under productivity projects we currently have underway with employees and the full year of Hedland and the work we've done on the capital. We have no -- we'd love to see prices go up. That would be awesome, but we are not building that into our plans, at least between now and 2020.

And I think the other thing that is important there is all of that is in the current environment that we live in. There's always changes that could come out, Linda, like we don't exactly know what's going to happen here with the balancing pool. So if there were some changes there in terms of PPAs and stuff like that, we'd have to reassess. But on our current PPAs, the way they are set up, our current business the way it's set up, that's where we are gaining the confidence.

Okay, that's helpful. Maybe just a follow-up. In your annual report you talk about evolving and implementing a more competitive business model and cost structure that works for more distributed gas and renewable plants across several regions.

Can you just describe a little bit as to what that might entail? Again, I'm assuming that's not embedded in the CAD400 million cost or free cash flow, but just comment on how that fits in with your aspirations on the rest of your company on the coal and mining side, etc.

So the work that -- remember we have a cost structure for our company that has big coal units with lots and lots of work that gets done at those units and lots of POs and things like that. So as we look forward and we look at the mix between coal and gas and renewables, there is a different kind of cost structure that can be achieved. We are 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 are thinking about it. Linda, it will involve significantly -- we think as we go forward it will involve significant IT investments. Now don't hear that like all of a sudden we've got a CAD100 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 are working heavily with suppliers so that we effectively have the kind of operations that can be heavily data-dependent and of a lower cost structure. So those are the kinds of things we are thinking about.

Now that shift in there is not built into that target. That would be for -- as we move out of the 2020 period and move into the capacity market.

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

Rob Hope, Scotiabank.

Good morning, thank you. Just may be a follow-up on Linda's question regarding the CAD400 million of free cash flow. What assumptions are you making regarding the Mississauga plant there?

We just renegotiated the contract, so we will receive our payment in 2017 and 2018 and then the contract is rolling off and the cash flow go away. But we basically are able -- our plan is assuming that we will make it up.

But we are not assuming that we rollover that contract or that -- right now we have not built into our cash flow assumptions anything with that plant. We have people that are working on thinking about if they can find a way to get some stuff in that plant, but that's not 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's John Kousinioris responding. If there is a termination from the balancing pool, clearly those units would end up coming back to TransAlta. There would potentially be termination payments that would be coming our way as a consequence of the termination of those arrangements prior to their end-of-life. And then we would integrate the operation of those plants into our own system, including the bidding of those plants in the Alberta marketplace in a manner that we believe is appropriate.

All right, that's helpful. Thank you.

Robert Catellier, CIBC World Markets.

Good morning. I wanted to follow up on the Mississauga plant here, understanding it's not in your outlook beyond the existing contract. Maybe you can just spend a minute on what you are doing to try to maximize value from that asset.

You'd better explain --

So the team is already -- like it's more than just Mississauga. We also have Ottawa, we also have Windsor, so there's other facilities in Ontario that our team are working on to capture more value to extend basically the value that we are making with those projects. 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 are having with our team in terms of like surfacing more value from our Ontario gas asset, depending on where Ontario goes into basically in the future.

Just to be clear, the way the contract works is 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 off the parts or continue to keep it there and mothball it a bit.

We have made the decision that we will keep it for now and we have a team focused 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 sell it across the border. But as I said, currently that would be icing on the cake. At this point we have built-in as if that project stays there mothballed.

The reason we decided to mothball it is A), it's very cheap to do that and B), 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 rust is probably not a bad idea. But the teams will see what else they can do.

Okay, that's the color I was looking for. And just to follow up on the Brazeau pump storage project, it kind of looks a little bit like a catch-22 in terms of you want to reduce your capital cost, which obviously makes moving these projects forward.

But on that specific project, do you think you need a reduced or lower cost of capital to make that project work? Or is it really the mirror image, that moving forward with 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 -- the way I look at it is what makes that project happen is a long-term contract. In hydro projects you're not able to really develop them and take risks on them in emerging markets. It's impossible.

You can't go -- there's no investor who's going to line up and give you money for five-year capacity contracts on a CAD3 billion investment where you have to make your money on the differential between high prices and low prices. So it requires a contract.

What's unique about that project is under a carbon tax, under a CAD30 or CAD50 carbon tax, even with the performance standards there's no question that anything that doesn't create carbon but provides capacity and storage is extremely valuable. So the amount that we have done on it, it's more valuable than any gas-fired capacity that you could put in to back up renewables. 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 5,000 megawatts. If of that 5,000 megawatts let's say they set aside 2,000 for renewables and called for -- sorry, set aside 2,000 for hydro and called for hydro and we competed in that and won, I think the government is pretty clear: to bring on large hydro in Alberta you need those contracts. I think if we got the contracts that, of course, gives us a big future and lowers the cost of capital.

I think secondly, though, we'd probably look at the project and finance it separately on the basis of its contract. And part of the work we are doing is also thinking about whether or not there's a roll here for the Canadian Infrastructure Bank, because to the extent you can get an even 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 really want low prices as they go forward, even though they want the environmental benefit.

So I think just to kind of sum it up, winning the project will help the mothership company, but we will probably look at it as an independent project that we will finance separately. And the more low-cost sources of finance that we can get the lower the cost of PPA is, so that's currently how we are thinking about it.

Okay, thank you. That's a very helpful answer.

Ben Pham, BMO.

On slide 11, you mentioned on the debt side CAD700 million to CAD900 million in a bullet point below the monetization off-coal payments. And I'm not sure I missed it, but is that -- are you suggesting that you monetize to future streams and that would result in a pretty big portion of that debt that's being repaid?

First, the CAD700 million to CAD900 million is more than just a monetization of our off-coal payment. The off-coal payment as part of that but it's only a portion of it. There's other contracted assets that we are currently working on financing that also include in the CAD700 million to CAD900 million that will achieve over the next 18 months.

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

Yes, so that's part of our plan. The timing is still uncertain, but basically it's in our plan to monetize that payment over time.

Okay, that's what I wanted to clarify. And can you talk about your hydro plants specifically and how you think about how those plans could operate in a capacity market? And is it -- could it be different than today? Perhaps maybe some constraints that the contract has right now, the balancing pool. Or maybe there's maybe some utilization and efficiency that you could crystallize in a different market?

Well, first of all, just those hydro plants have more value outside of PPA than the PPA gives us. So just to be clear, the PPA constrains the value to TransAlta; there's huge value in those hydro plants. So that's kind of the first principle.

As we think about the capacity market, there's -- first of all, we can bid capacity out of the hydro projects into the capacity markets, 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. And then, of course, their third value is of energy. The energy value is never the big value in hydro; it's always our ability to shift and capture either ancillary services revenue or capacity market revenue.

So when we do our modeling, we think that there's kind of an equivalent value that's available as we go forward into the market with that because of the -- the biggest thing the hydro plants have is their flexibility. They are the fast-start capability, there's nobody can beat that.

What's really interesting about the technology that we are looking at for Brazeau is it is incredibly fast, so it beats everything. And those are the kinds of attributes you need because, as you know, one of the biggest issues with solar, if the province decides to do more solar, is when the sun goes down it goes off immediately. You have to start units up really quickly; and the same with wind.

So we think it's -- we have always known there's value beyond PPA and I think in the capacity market I think it's just restructuring that value differently.

Can I clarify, Dawn, the enhancement of value? Is that more in the production side where you may not be motivated to produce the [churn] level today or is it something else?

Keep in mind the capacity factor of our hydro is roughly 20%, so you need to look at the hydro as peaking plants. Most of them have storage, so we can manage the generation. The Brazeau project, even forget about the pump storage which increased this, but the current hydro project that we have at Brazeau it's a big peaking plant that we own.

Provides a lot of value, not only in the energy market because clearly we can pick the best 20% hour and generate value there, but it's also the ancillary value that it's creating for a province. And a lot of those revenues, like today, are capped through the PPA that we have. In addition to this, post 2020 they will be eligible to participate in the capacity market and earn additional revenue.

Think about it this way, currently the hydro PPA creates value for us and the balancing pool. And the reason it does is 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 Albertans, that PPA.

That value was always to come back to TransAlta and it will come back to TransAlta. So you go from a 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) Robert Kwan, RBC Capital Markets.

Dawn, if I could just follow up, you've made a couple of statements here that lead me to think, maybe incorrectly, that there has been some discussions around the capacity market in that framework. I guess the first one your comment being that you could bid the hydro capacity into the capacity market. Has that been confirmed and what that framework, whether it's going to follow the PJM framework or something else?

No, no. Discussions in the capacity market are early days and so all of this is based on our own work that we've been -- our own analytics that we have done on capacity markets. And you know us, we are crazy analysts here so we've got -- we have 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 will look like. But the actual rules in Alberta, I can't imagine -- I'm not lobbying here to ISO, but I can't imagine why you wouldn't want the Alberta hydro to be a capacity in the market here.

Those hydro with the backstop that they have and the storage that they have provides significant amount of capacity to the province, so that 900 megawatts needs to be recurring, I believe.

Okay. Then I guess the other statement you made a little bit was just what your pump storage facility or your existing hydro facilities having a much, much better ability to be a 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 wouldn't be load-following?

I'm just practically -- 31 years of experience -- thinking about doing the modeling and also thinking about what changes. If you bring in 5,000 megawatts of renewables and let's say 3,000 of them are more intermittent like solar and, wind. To a system as small as this the volatility will increase dramatically because you are 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 are going to have to, all else being equal, have more load-following and you're going to have to have a market that enables the backup of those renewables. Particularly if you're bringing them in on long-term contracts with -- what are those contracts called? If you are doing contracts for differences over 20 years and at the same time you are 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.

If you look at Brazeau with its storage capability of -- let's say we could get it to 900 megawatts -- and we think we can; it's the difference between two penstocks and three. So we are kind of modeling both. That's a significant storage for that wind and hydro, and it actually create significant value for those wind and hydro contracts.

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 knowing that the government is willing to sign contracts for other generation outside of the general capacity market framework?

What I've seen -- I kind of have it in three different buckets in my head. And again this is all speculation; I will say that for the lawyers in the room. I am speculating on what a capacity market could look like, so this isn't to think about value for our company. It is just to think about how you would do it here.

In my mind, if you take something like our coal to gas conversions, it's a small amount of capital and effectively 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 assets. That makes sense to me.

If you look at Hydro I think people who work on long-term hydro -- and of course I've got five years at BC 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 regulatory work, which takes four to five years, and the construction timeframe, which takes four to five years.

No one is going to bet CAD3 billion on the possibility that when they get there there will be five-year capacity contract that they can bid on and make a bunch of money. You're just not going to do it. At least we're not going to do it.

I think there the reason that you are doing sort of a capacity contract for different -- similar to what you are doing with the wind is you are doing that because that allows that kind of renewable asset to come into province, so that's a different bucket. And I think all of the renewables, frankly, all 5,000 megawatts will have those kind of long-term contracts.

Then in the middle it leaves new gas, effectively. And so our view -- what we have seen is in other markets -- and we are doing some more work on this, Robert -- there are investors, there seem to be investors that will bring some money into new gas 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 bets on that.

I think, if you thought about it, your three- to five-year capacity contracts are existing, your long term for renewables, and then the gas is somewhere in that five to seven years. Now that's just me, Dawn Farrell, talking. There will be stakeholders with all sorts of views; the ISO will have its views, but I think a functioning market could ensue if you kind of looked at it that way.

Got it. Just to your comment of there seem to be investors willing to bring money for gas in the three- to five-year contract range, is TransAlta one of those investors?

No, no. And I said more five to seven for new gas. No, my bet is on converted gas. Our plants 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 to the grid. I'm fine to bring gas on to do that, but I would not take a bet personally.

They will get a new CEO here eventually and that person might be different, but they would 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 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 this is what you get paid on the daily makes that decision, I might invest in that product.

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

I think that target is probably appropriate between now and ramping down over time probably. Past 2020 the number is different, for sure, because it's more [merchants]. And you have to understand that capacity -- the availability has less value when price is CAD20 than when price is CAD60. 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.

Charles Fishman, Morningstar Research.

Good morning. Dawn, (technical difficulty)

Charles, we lost you.

Dawn, let me repeat that. I know that your focus is on Alberta. (technical difficulty)

Operator, can we just move to the media calls? It 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. That will end the Q4 call.

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