TransAlta Corporation (TAC) Q2 2017 Earnings Report, Transcript and Summary

Good morning. My name is Christine and I will be your conference operator today. At this time, I would like to welcome everyone to the TransAlta Corporation Second Quarter 2017 Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be question-and-answer session. [Operator Instructions] Thank you. Ms. Sally Taylor, Manager of Investor Relations, you may begin your conference.

Thank you, Christine. Good morning, and welcome to the TransAlta second quarter 2017 conference call. With me today are Dawn Farrell, President and Chief Executive Officer; Donald Tremblay, Chief Financial Officer; John Kousinioris, Chief Legal and Compliance Officer; and Brent Ward, Managing Director and Treasurer. The call today is webcast and I invite those listening on the phone line to view the supporting slides, which are available on our website. A replay of the call will be available later today and the transcript will be posted on our website shortly there after. All information provided during this conference call is subject to the forward-looking statement qualification which is set out on Slide 2 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 second quarter results and discuss progress made against TransAlta's goals and priorities for 2017. After these prepared remarks, we will open the call for questions. With that, let me turn the call over to Dawn.

Thanks, Sally, and welcome to TransAlta and welcome to everybody on this call. We've covered a lot of ground since our first quarter call and first I want to talk about how we've advanced our financial strategy. Our business units have delivered results that were in line or above expectations for the quarter. I'm pleased with our performance as we look at the first half of the year. With this improved operating performance from the businesses, we have allocated most of our free cash flow and the proceeds from the sale of the Wintering Hills wind project to reduce our debt by $184 million, which is what we said we would do. We have been advancing the company-wide Greenlight initiative, which is expected to result in new efficiencies and cost savings starting in 2018. We will be using the expected proceeds from the repurchase of the Solomon power station to strengthen our balance sheet and support new growth projects. And finally, we advanced our initiative to put project financing on some of our contracted assets. Now, the second area of focus for the year and of course for the quarter was our focus on advancing growth. In July, we were really excited to commission the South Hedland power station and we met the conditions under the PPA for Horizon Power, who we now welcome as a customer to TransAlta and they began purchasing power as of July 28th. We also negotiated the expansion of the Kent Hills wind farm to 167 megawatts and we extended the Kent Hills 1 PPA by two years to 2035.Our third area of focus of course is advancing our off-coal strategy. We continue to work with both the provincial and federal governments to formulate regulations that will govern the conversion of our coal fleet to gas. I'll talk about that more at the end of the call. We progressed our gas supply options and we advanced engineering works for converting the boilers to natural gas. On Brazeau, the environmental work and the stakeholder engagement work was advanced and is tracking and we prepared several projects for submission to the Alberta Renewables call that we expect to take place in the fall. As we look ahead to the balance of the year, we do have some emerging headwinds, which I'll talk about in a minute. First, let me give you some of my color on the quarter and our expectations for the balance of the year and then I'll turn it over to Donald to give you more detail. So I'm going to start with availability. Lower availability in the quarter of 84% as compared to last year of 86.5% was absolutely planned and expected. It was primarily due to the higher planned outages that were at the Canadian and U.S. coal facilities; the work that we had planned to do at Sarnia, which was completed; and work we did at the Windsor gas plant to turn that plant into a peaker. Let me turn for a minute to production. Despite the lower overall availability, our overall production from our fleet was essentially flat year-over-year on both the quarter and a year-to-date basis. The shutdown of operations of our Mississauga facility reduced production, which was offset by higher generation from renewables. Going forward, South Hedland's generation will offset the Solomon facility as it comes out of our fleet at the end of 2017.Now, it's important to remember that we receive monthly capacity payments from the Ontario IESO until the end of the 2018 for Mississauga and that by the end of the year we will have a one-time payment of approximately $350 million for our Solomon plant. Now, turning to our financial results, all our business segments reported results in line with or above our expectation. As a result, the reported comparable EBITDA and funds from operations for the second quarter are the highest second quarter results we've achieved in over five years. So my congratulations to the TransAlta team who worked hard to achieve that. Our free cash flow for the first half of the year is slightly lower than last year, but in line with our expectations as we plan to fund and load our capital sending in the first half of this year compared to last year. Now, looking at the balance of the year, we are facing some challenges. The South Hedland commissioning was slightly later than we expected and it could take some time to resolve our commissioning dispute with FMG. Emerging labor concerns at our Alberta coal mine have impacted productivity at the mine, significantly reduced our coal inventory and will reduce production this year by about 600 gigawatt hours. We don't expect that coal shortage to persist. It should be fully resolved by the end of September. But clearly we're going to have to take a much more proactive approach in both labor relations and hiring as we move to the next couple of years. The rest of the operations are performing well; marketing some has dried in the second quarter and did great and the renewable segment are achieving or beating their targets. So with that, I'm going to pass it over to Donald to go over the details of the quarter and our execution of our financial plan.

Thank you, Dawn, and welcome to everyone on the call. As you can see on Slide 5, comparable EBITDA from our power generating asset for the first 6 months of the year has grown year-over-year for the past three years, with strong performance across our portfolio. For the quarter, EBITDA from our operating assets totaled $270 million, an increase of $70 million or 7% over the second quarter of last year. On a year-to-date basis, EBITDA of $580 million was up 8% over last year. During the first half of the year, EBITDA growth was most notable in our U.S. Coal, Canadian Gas and Wind & Solar segment. This number excluded EBITDA from Energy Marketing and our corporate overheads. On the slide, you can see that second quarter and year-to-date EBITDA from our Canadian Coal segment is lower than last year. This wasn't a surprise as we were expecting higher coal cost and lower realized price from our on-contracted generation when we issued our guidance. As discussed on the Q1 conference call, the higher fuel cost in the first half of the year was due to lower equipment availability and the higher strip ratio, which requires handling more overburden at the mine. The development of new pit areas during 2017 and 2018 will improve our strip ratio moving forward. However, as Dawn mentioned earlier, we are facing lower performance at our mine operations due to the emerging labor constraint. This has negatively impacted the amount of coal produced and reduced our inventory by 1/2. We have notified our customers and the AESO of our intention to derail the unit in periods of high supply and low demand for the next two months so that we can build our inventory and preserve grid reliability. This will negatively impact our availability, generation and our coal costs for the rest of the year. Our U.S. Coal segment results for the second quarter and year-to-date have improved by $60 million and $30 million to $34 million and $44 million respectively. Results for the quarter and year-to-date benefited from higher revenue and favorable mark-to-market positions on forward contract that hedge our generation. Lower cost for the purchase power used to meet obligations during economic dispatch and movement in foreign exchange rates also had a positive impact on the second quarter results. Our Wind & Solar EBITDA was up $6 million over the same quarter in 2016 and $13 million on a year-to-date basis. The increase is primarily due to increased generation at our contracted facility in Eastern Canada and lower operating expense after we renegotiated long-term service agreements for our Alberta wind projects. Energy Marketing results reflect a return to a normalized gross margin, with EBITDA in the second quarter of $12 million compared to $6 million last year. However, on a year-to-date basis the results are below our expectation due to lower margin in the first quarter. With gross margin of $19 million for the first half of the year, we believe it is prudent to further reduce our guidance. For the year we now expect our gross margin from Energy Marketing to be in the range of $50 million to $70 million, $20 million lower than our initial guidance target. Before I talk about our hedge and power price, I would like to comment on our free cash flow. Our free cash flow for the second quarter totaled $30 million compared to $56 million last year. This was mostly caused by higher planned outage in the second quarter of 2017 compared to last year. Our sustaining capital during the period was $21 million higher than last year due to major work and inspection at Sarnia, Windsor, Centralia and Key Hills 2. Also impacting our free cash flow in the second quarter of 2017 is the higher amount paid to our non-controlling partner in key -- for their share of the Ontario Electricity Financial Corporation settlement. As you can see on Slide 6, the Alberta power price -- on this Alberta power price slide, sorry, our EBITDA and FFO are not directly connected to the average Alberta spot price. Over the past three years, both EBITDA and FFO have increased year-over-year and this year we have the highest second quarter result we have had over last five years. During the same period, the average Alberta spot price for the quarter has dropped more than 80% from a high of $123 per megawatt hour in 2013 to $19 per megawatt hour in 2017. This is the result of our strategy of maintaining a high percentage of contracted generation and hedge in our portfolio. Looking out to 2018 and 2019, we have contracted or hedged more than 80% of our generation at a price which exceeds the current power price in both years. Let's move on now and talk about our balance sheet and credit metric. As you can see from Slide 7, our liquidity is $1.4 billion, including cash of $50 million. The reduction of liquidity was expected and planned as we were building cash to meet our scheduled US $400 million bond payment in June of this year. Subsequent to the quarter, TransAlta Renewable entered into a 500 million 4-year committed syndicated credit facility and cancelled the 350 million credit agreement with TransAlta. At the same time, we reduced our 1.5 billion credit facility to 1 billion and extend its maturity to 2021. From a consolidated perspective, there is no change to our liquidity. Turning to Slide 8, during the first 6 months our FFO to adjusted net debt ratio improved from 17% at the end of December to 18.2% at the end of June, resulting from strong performance across our businesses, our debt reduction program and the strengthening of the Canadian dollars. Over the last 12 months, our rolling 12 months adjusted FFO is up $41 million to $760 million and net debt has been reduced by $184 million all in the first half of this year. We accomplished this by allocating most of our free cash flow and the proceeds from the sale of Wintering Hills project to debt repayment over the last 6 months. In July, we paid Horizon Power $160 million as a prepayment of transaction cost and for the acquisition of some existing asset on the site. As a result, assuming the Canadian dollar remains at current level, we expect our net debt to remain between $3.7 billion to $3.8 billion by year-end. In August, we received a notice from FMG of its intention to exercise its option to repurchase our Solomon facility for the contractually predetermined price of $335 million. The net proceed in Canadian dollar of approximately $350 million to $360 million are expected in November and we intend to redeploy proceeds in growth initiative to replace the cash flow from the Solomon facility. In the meantime, the proceed will reduce our net debt and will provide us more flexibility in executing our financing plans and the timing of financing will be adjusted to match the redeployment of the capital. With the commissioning of the Solomon power project last month, we expect to achieve our goal of FFO to adjusted net debt in the range of 20% to 25% and adjusted net debt to EBITDA of 3% to 3.55% by the end of 2018. South Hedland is expected to contribute $80 million in EBITDA and FFO on an annual basis. We are now focusing our attention on future of corporate debt maturity, which total $1.36 billion through December of 2020. As mentioned on our Q1 call, we plan to raise approximately $700 million to $900 million by financing contracted cash flow over the next 12 months. We are actively advancing the financing of Kent Hills wind farm. We expect a rate between $240 million and $275 million of project financing. A portion of this proceed will be used to fund the expansion of the project to 167 megawatts. The rest of the proceeds will be distributed to TransAlta Renewable to repay maturing debt and to our 17% partner in the project. Our goal is to improve our debt metric to the high end of our target of 20% to 25% FFO to net debt by 2020.During the first half of the year, emerging labor constraint at our Highvale Mine had impacted productivity significantly, reducing our coal inventory and causing coal supply constraints at our facility in Alberta. The shortfall affect our Sundance coal-fired power gen unit 1 to 6 and Keephills unit 1 to 3.We expect additional mining cuts at our Highvale mine for the remainder of 2017 and a shorter term reduction in the power generation at Sundance and Keephills in order to rebuild our coal inventory. Also, higher distribution to our non-controlling interests, a higher level of productivity capital to support company-wide transformation initiative and a reduction of our expected margin in Energy Marketing has negatively impacted free cash flow. Accordingly, we have reduced our free cash flow target range to $270 million to $310 million from the previously announced target range of $300 million to $365 million. Additionally, we tightened our range for EBITDA and FFO by reducing the high end of EBITDA from $1.135 billion to a $1.1 billion and FFO from $855 million to $820 million. Earlier this year, we told you we were targeting to deliver $400 million of free cash flow for the period of 2018 to 2020. This is how we are progressing toward that target. Our South Hedland power station was commissioned at the end of July. As we mentioned before, it is expected to contribute $80 million to EBITDA and FFO on an annualized basis. Production from South Hedland is contracted under 2 25-year power purchase agreement, One with Horizon Power for 110 megawatt capacity and the other with FMG for 35 megawatt of capacity. The power plant is not available in providing capacity and energy to the grid. However, FMG is disputing that the plant has achieved certain milestones required to confirm commercial operation under their power purchase agreement. We are continuing to work through this issue with them and are confident that the plant has reached commercial operation. As discussed earlier, FMG has decided to repurchase the Solomon gas plant, which will impact our free cash flow in the near-term. We expect to redeploy the proceed over the next 12 months to make up the shortfall and don't expect our 2018 to 2020 cash flow to be materially impacted by FMG actions. Our cash flow between 2017 and 2020 will include the Alberta government's annual off-coal payment of almost $40 million. This is expected to compensate TransAlta for early elimination of coal generation from Keephills 3, Genesee 3 and Sundance 1 and 2. We received our first payment under this agreement in July of this year. As discussed, we are reducing our free cash flow guidance for the remainder of the year to $270 million to $310 million. We do not expect this issue to impact our free cash flow in 2018 to 2020 and are confident that we will meet our target $400 million of cash flow in that time frame. Lastly, I would like to discuss our corporate transformation initiative, our project Greenlight as we call it. More than 1/3rd of our employee are engaged throughout the company and have designed and put in place new way to operate, which will increase efficiency and reduce expense. Most of the cost of the program will be incurred in 2017. Next year, we expect to see the bottom line benefit of these initiatives. We are confident we can deliver $50 million to $70 million of recurring savings, which are included in our forecast to reach $400 million of cash flow in 2020. With that, I will now pass the call to Dawn for closing statements.

Thanks -- thanks, Donald. I'm going to spend the last few minutes of the call to update you on the work we've been doing to advance our transition to gas and renewables. The regulatory environment in Alberta is moving forward and our team is engaged in the process. Changes in the Alberta market continue to provide some really strong future opportunities for TransAlta. Work continues on studying the criteria and defining the operations of the province's new capacity market. We are in early stages, but we continue to believe that prices for energy and capacity will be set to maintain system reliability, but also to ensure that returns will be fairly compensated for the incumbent and new generator. Our focus on bringing the lowest cost capacity to the market remains steadfast. During the quarter, we were able to get regulatory approval to run Sundance Unit 2 for 2 years beyond 2019, which is its current expected end of life. This new date will allow us to put Sundance Unit 2 in contention for a coal-to-gas conversion if the market needs new capacity by the time we get to 2020.Our team continues to work with the federal government to ensure that we can run our converted gas-fired operations at our Sundance and Keephills plants for at least 15 years on gas. We are also hoping that plants such as Keephills 3 and Genesee 3, which are much more efficient and which currently have lower greenhouse gas emissions and will have much lower greenhouse gas emissions if they are converted to gas, will be granted additional life and will be able to run well into the late 2040.As part of the MoU we signed with the province of Alberta last November, we gained assurances that greenhouse gas credits will be given to existing wind and hydro facilities under the new carbon tax regimes. This makes sense to all the existing electric power greenhouse gas emitters, as what they will be able to do is deduct approximately 0.42 tons of CO2 per megawatt hour from their emissions profiles before calculating their payments of carbon taxes to the government. Because existing hydro and wind facilities do not emit greenhouse gases, we believe owners of these plants should be permitted to create and sell credits for their generation up to the CO2 performance standards that is ultimately established. Our team is working to ensure that the regulations we expect to be finalized by the end of the year will treat all generation on a level playing field. We do continue to aim our transition of our plants to the 2021 and 2022 timeframe. Our strategic and economic assumptions on this transition were further supported by the recent drop in the forward curves on Alberta natural gas prices and the progress we're making on engineering and discussions on pipeline options are giving -- are making these decisions the right thing to do. Our Brazeau hydro pumped storage project is another investment that will benefit both the province and TransAlta. It will provide the storage necessary to gain the full value of the large renewables build out that is being planned for Alberta. This carbon free project will generate renewable energy and provide backup generation to support intermittent wind and solar generation. We are advancing early stage development activities, as I said earlier, including preliminary geotechnical investigation, construction and hydrology engineering and we're actively advancing our discussions with our First Nations groups. However, we will require a long-term contract to support the ongoing investment. We are working with government and hoping they will decide by early next year to recognize the benefits to Albertans of meeting some portion of the provinces renewables target with cost effective long lived assets like Brazeau. These assets will serve Albertans about 3 to 4 times longer than wind farms and 2 to 3 times longer than any thermal plant. So the value of these durable assets must be carefully considered in any electric policy framework here in the province. I will take a minute to talk briefly about the Balancing Pool Consultation. The recently announced Balancing Pool Consultation on the Alberta PPAs allows the balancing pool to decide on the termination of the Sundance PPAs as early as this fall. Now, remember the original PPA arrangements were based on setting regulated rates of return on low cost hydro and coal assets that have served Albertan for well over 50 years. We have 3,770 megawatts of gross electric generation under the PPAs, which includes our hydro and coal-fired plants, and in total this represents about 23% of the electric generation capability in the province. If the balancing pool chooses to terminate the Sundance PPAs, we would expect to receive approximately $230 million in payment for the net book value of these assets. This will be used to reduce our outstanding debt in the short-term. In addition, termination of the PPAs could result in increased operational flexibility and the potential to accelerate the transition of some of the plants from coal-to-gas potentially earlier. Now, there are many moving parts to consider in making this decision and it's not clear at least to us the termination of the PPAs is in the best interest of Albertans. Our job is to be ready whatever the decision and we have plans ready to go if the PPAs are terminated. I'd like to talk for a minute about our improving financial strength. TransAlta Renewables announced an approximate 7% increase in the dividend due to the commissioning of the South Hedland power station, which we expected. The dividend increase in combination with the conversion of the Class B shares translates to an additional $30 million in annual dividend payment from TransAlta Renewables to TransAlta shareholders. Now, as we've told in the past that South Hedland is expected to contribute $80 million of annual EBITDA from the 25 power purchase agreements. Our PPA with FMG for South Hedland accounts for about 25% of this, as Donald told you, and we're working diligently to resolve this dispute. The decision by FMG to exercises its repurchase option of Solomon became inevitable and they determined that integrating the plant would lower their financing costs and in turn lower their iron ore unit cost. And while we would have preferred to remain a supplier, the proceeds totaling US $335 million will be used to improve TransAlta Renewables balance sheet in the short-term and it gives us significantly more financial flexibility to pursue growth. Our intention is to quickly redeploy this cash, and as well as we close the financing for Kent Hills, we will have additional cash. So the TransAlta Renewables team is busy looking at significant projects that will help us during that. So in summary, I am really pleased with the first half of the year. We're facing into some headwinds in the second half, but even with that, we are tracking to deliver our best free cash flow over the last five years. So we're determined to do that and everybody is on deck on everything that we can do there. The company is running well and all our people are engaged and focused on authentic improvement projects that will increase our competitiveness. Our regulatory team is doing some outstanding work. They consistently put Alberta first in their deliberations and analysis and they are working hard to ensure the policy framework in Alberta serves both customers and investors. So with that, I'll turn it back over to Sally for questions.

Thank you, Dawn. Operator, we would like to open up the call for questions from analysts and the media please.

[Operator Instructions] Your first question comes from the line of Robert Hope from Scotiabank.

Yes. Good morning. Maybe to start off on Highvale, could you add some additional color on exactly what these labor constraints are, what brought them on and why you do not expect that higher coal costs will persist into 2018?

Yes. Just in terms of -- as you know, in November we announced the new policy framework which included the off-coal payments for TransAlta as we move towards getting off coal in this province. And then by April, TransAlta announced our intention to advance our movement off coal on to gas of our power plants. So effectively what that did unfortunately is really, really made a lot of the people that worked up in that mine nervous. And as you know, Alberta is also opening some new mines up in north, so there are a lot of good jobs for our people there. So where we -- and I'll take accountability for this -- where we got behind is as there was higher attrition and people leaving, experienced people leaving to go up north, we were having trouble getting experienced people to work for the mine because of its expected short timeframe. People don't want to move their families in if they think they're only going to be there for three or four years. So we got behind on our hiring and that caused an issue that we didn't get ahead of fast enough. So we've now corrected that. We're doing -- in the short-term here we've been able to hire contract miners who have been able to come in and really work hard and give us a lot of assistance while we're turning that around. We've had to retool ourselves and I think we'll have to retool ourselves over the duration to ensure that -- we do have to expect higher turnover in the mine because of its short duration and we do have to be able to train people much more quickly on the equipment and then accept sort of the additional supervision that will be required with people that will be less qualified. So I think at this point the work that we've done on it here to make sure that we can get back where we need to be by the end of September is very solid and very strong. And then as we go forward into 2018 and 2019 -- we'll continue to update you on -- it's really our ability to manage a labor force in a mine that has a shorter life and that's making sure that we have all the contingencies in place to overcome some of the anxiety that the people have up there.

All right, thank you for that color. Switching gears, looking at RNW, with the Solomon proceeds as well as the refinancing of Kent, you could have a significant amount of capital there and you did reference some opportunities you're seeing in that vehicle. Is that more on the M&A side, either third-party or drop downs or would RNW be potentially where you would be investing in Alberta Renewable organic projects?

Yes, I mean it really does -- so we do have the Alberta Renewables call coming and so it really positions us with some cash for that. And we have a number of projects that we -- on the M&A side that we have been looking at, but frankly we're being pretty picky because of capital. So now we'll continue to be picky because that's the kind of investors we are, but now that we see both the cash coming from Solomon and from the financing of the Kent Hills assets, it gives us some opportunity actually to be a little bit more strategic and to do something that's a little bit bigger than what you've seen us do in the past. So that's where the team is focused.

Your next question comes from the line of Ben Pham from BMO Capital.

Hi, thanks. Can you guys add more color on Centralia during the quarter, just haven't seen strong numbers I guess for a while?

Well, like two things, Ben. First, mark-to-market, which is mostly like timing. The one with mark-to-market is timing because like those hedges that were marking to market are like economic hedge, and depending on power price, like we capture EBITDA like sooner or later during the year. Well, that's one. The other impact is FX. Like even though like the Canadian dollar both -- in the quarter very strong, like the average for the quarter was like lower than last year. So we basically got like some FX gain as well in Centralia. So those are the big driver. Plus like very cheap power price in like the Pacific Northwest in Q2, where we're normally like are shutting down and buying power to basically supply the contract we have with Puget. So those are the driver.

And that's a cash realized gain you guys are booking too or just moving --

Net unrealized, it's unrealized.

Okay, all right. And some of your commentary on the balancing pool, just waiting to see what happens there. But can you -- do you have a sense of timing on this? Obviously, this is uncharted territory. But how do you guys kind of manage -- if the balancing pool does give you money, I think it's six months or so until you get it and you want to convert earlier. How do you guys kind of mash it with the timing of the pipeline approvals?

Well, there's a lot of different ways to think about getting gas to that plant, and as and you can imagine, when we first started down this road, we had some pretty traditional ways of thinking about how we could get gas there. But since we've announced that, we've had -- everybody in Calgary stopped by to see us with some pretty interesting proposals. So we can see some different ways to potentially get gas to the plants. But I just want to underscore, I mean there's still a consultation going on. The consultation is with customers. And really the balancing pool has to take into consideration whether or not customers in Alberta will be better off or worse off by the termination of the PPA. So at this point, we're ready to go one way or the other. And I wouldn't promise at this point any early conversion, because frankly having a very -- having a plan that's organized that kind of gets done in the 2021, 2022 time frame makes a lot more sense to us. But to the extent that we can see some ways to get a bit of gas there earlier, that may bring some earlier things or it may even allow us to take Sundance Unit 2, which I announced earlier is now back in contention for the running for capacity, it could be a plant -- it could end up being our first plant converted, because, as you know, we're mothballing those units and it would be easier to convert them when they're offline. So that's basically how we're thinking about it. But I am not making a bet either way as I -- I think it's a complex discussion and I'm not sure customers are going to think it's beneficial to them. So I think there's a bit of road to go here.

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

Good morning. Just going back to the question along RNW, the entire -- available liquidity and stretching maybe your scope and possibilities, are you looking at any corporate transactions given there's a bunch of sort of -- in the state for sale potentially? Is that something on your radar or is that just off the table completely?

No, nothing is off the table for RNW. I mean, there's a lot -- like you say, there's a lot of renewable assets around. Just remember, though, that there's also a lot of money chasing that and the financial guys are chasing just absolutely the lowest returns you can imagine. So as our team looks -- what we do is we always look and say, okay, what is it that we could add here? Is there some sort of synergy with our existing operation or is there some reason that somebody -- if they are big packages of assets and they have got long-term contracts on them and they are really, really simple financial plays, their returns they are bid down to nothing. We don't want to build a company on returns that are bid down to nothing. So nothing is off the table. We look at everything. Our investment committee meets weekly on different things that the team is working on. But we're pretty picky and we have been and I think that has served us. So a little bit of patience. We deploy that capital, but you like the returns when we get it redeployed.

Okay. Then going back to Centralia, given where prices are and they continue to be weak, just maybe you can comment based on where the hedge book is whether or not the results realized in Q2 could also happen again in Q3 or the back half of the year for that segment?

The answer to that is no. Like basically we're -- like most of the generation that we have at Centralia basically is hedged and we're marking it to market. So like I don't expect Q3 to be at the same level.

Okay. And then in the MD&A there's some commentary about some initial spending on upfront design work, engineering work for Brazeau, that $5 million to $10 million will that be expensed and come through G&A? And then just wondering as you think forward, you think with that project, are you looking to build that out in sort of one large chunk or would you consider sort of a phased build out of that pumped storage facility?

No, it's -- so that money is capitalized, so it's not going to the G&A right now and it's really for the early geotechnical work that we're doing and the environmental work, all that, all the baseline studies that have to be done so that you can prove that what the impact would be of the project. And also we need -- we'll work -- we're doing -- we're taking a very early approach to working with the First Nation partners out there. But when you look at the project, it actually -- the way the engineers have looked at it, it actually could be done as a 1, 2. But it's not as efficient for the system overall to do that, because you mobilize all that labor and all that construction and then you demobilize and then you remobilize and you demobilize. And that's where the big expenses are on a construction project. So currently we're working on it as if it's one big project. And frankly by the time it would get in place, there will be a significant need for it because it would be a 2025 start time with -- construction start time in that 2021 timeframe. So right now we would like to keep it in one big project. And it's -- all the work we've done on it on the financing side -- if the government does the PPA with us, we can finance it at very, very low rates today. It's important to get that done today because who knows what interest rates will be in the future. So there's really, really low cost to capital for that, which benefits Albertans with low price storage and capacity. So that's how we're trying to -- we're aiming on it.

Your next question comes from the line of Robert Kwan from RBC Capital Markets.

Good morning. Just coming back to Kent Hills, I just -- as you get closer; really you're ending up a shorter and shorter duration on the mine. So I'm wondering how you think of -- how do we think about the very short-term, where it sounds like you've got a bunch of extra costs, to kind of get everything back on track. But as we think out over the medium-term, does that still not lead to an elevated level of cost, whether that's having much more staff just to manage the attrition or paying people to retain or contract mining?

Yes. Robert, that's certainly something that we're working on right now. So as we give you guidance for next year, we will have considered all of that to see just is there -- there might have to be -- there might be a different algorithm that's required to run it in the short-term, but of course our job is to keep the cost as low as possible and look for the ways of doing that. So I wouldn't want to answer that right now. I want to be cautious as we look ahead because these are real issues as you can imagine. But at the same time, I do think there's -- there will be some ways to see if we can do this without the cost being too high and we will give you more guidance on that as we go into our guidance for 2018.

Okay. Just following on that then, is that something you also think about with respect to the coal power operations or is attrition over time okay just given less staff needed to run gas plants versus coal plants?

Yes, that -- I mean, the big important thing there is it's a massive amount of attrition that's required as you go from coal to gas. It's a very different number of people. So that -- on that side of it, that can be quite helpful. But at the same time, we've been managing this issue now at Centralia for a long time. So we -- the Centralia -- it's surprising -- it's not surprising, but for power plant people when they look ahead and they see Centralia Unit 1 shutting down potentially at 2020 and 2025, all else being equal, they will take a job if they think there's a plant that's going to run longer. So we have other mechanisms that we use in terms of retention packages and things like that which we will have to put in place. But net-net it's not as difficult an issue with the plants. You're right on the money with that.

Okay, got it. If I can just ask about the hedging in the chart on Slide 6. Looking at the second half of the year, recognizing that those bars are expressed in megawatts, is the amount of megawatts already taking into account the derates on the coal plants and it's not just straight kind of rated capacity?

No, they're not. Normally, however, when we basically hedge, we take into account the fact that the availability will be at a certain level. So there may be some buffer in the hedging program that you have there.

Okay Then when you say it isn't, does that mean that the hedging is actually higher because of the derates or is this inclusive of derates for at least 2017?

If you look forward for the next 2 months, we may have more percentage of our production that will be hedged over the next 2 months.

Yes, you to remember in Alberta our hedging group finds out about what's going on in our plants the same time the market does. So they now have to adjust their hedging program to reflect what they got the news on this morning at the same time that you did.

Understood. And if I can just finish on Centralia. It sounded, Donald, like from your answer earlier that a bunch of the strong results in Q2 was more the unrealized mark versus economic dispatch, is that fair?

Yes, a big portion of this is the timing on the hedge exactly.

Your next question comes from the line of Jeremy Rosenfield with Industrial Alliance.

Yes, thanks. I just wanted to come back on the contracted Alberta portfolio position and just with regard to the Sundance PPA. So if the balancing pool does terminate the PPA, would you -- based on where you are in terms of contracted just right now in that portfolio, do you think that you are actually over contracted potentially going into 2018-2019 assuming that Sundance won't run as often if that PPA is terminated?

So is your question, are we over contracted in the event that the Sundance units come back from the PPA?

Yes.

Is that your question?

Yes, exactly. Like what would --

So given like the -- the chart that we have in the deck is basically contract and hedge. If the PPA roll off, like that will create more length in our portfolio. And clearly like when that happens, that people that are hedging the portfolio will have to take action. But at the same time, the people running the plants and -- we will look at the economic and we will make the appropriate decision in terms of -- like that we will dispatch those units.

Yes, the simple way to think about it is if you take 500 megawatts -- well, if you take the megawatts of each unit -- in our hedge forecast today the PPAs are included as a hedge. So when we get the money for the PPAs, they become open and we take those hedges out and you'll see that we have more open exposure and then we'll have to decide whether or not we're going to hedge those or just leave them open in the market. And all of that has got to be determined once we tell the market what we're going to do in terms of how we're going to run the plant, because we have a very different operating regime with the plant if they are not under the PPA.

Right. What I'm getting at is basically, based on what the outlook for market prices might be, if Sundance comes out of the market, what's the consideration in terms of the portfolio contractedness today looking forward? Though, essentially --

Yes. So remember all that happens is Sundance is not hedged, but it's still in the market. So the question is, without the PPAs what happens to prices. And when the PPAs are extinguished, their dispatch rights come back to TransAlta. Today we have to dispatch them based on what the PPA say and what the buyers want. Tomorrow we dispatch them based on what we think is the right dispatch for the economics of the market. So there's lots of people there forecasting what prices might do if the PPAs are taken off. So what you want to be able to do in your thinking through this is say to yourself, okay, what will actually happen to market prices and then what's the new margin that TransAlta will get off those plants when they dispatch them into the market? Now, we may hedge some of it, and if we do, we'll tell you that we've hedged some of it. But we can also -- we also have the option to keep them open if we think prices are going to rise.

Right. Maybe if I can just ask it in response. The question is really, would you proactively look to shorten your portfolio length with the recognition that market pricing might increase?

When you say proactively, what do you mean?

No, I think -- so are you saying would we --

I mean, today.

Would we hold more open than we have historically if we thought prices were going to rise? We have the ability to do that. Yes, we have the ability to do that. Yes, we like the idea of making more money.

Okay, thanks for that. And then just -- the other question was just -- whether the balancing pooling has been in discussion with you specifically regarding the Sundance or just as a general consultation and there haven't been any specific bilateral discussion?

Yes, Jeremy, it's John Kousinioris. We've had a very introductory discussion with the balancing pool, but what they're going to do with the PPA's, as Don alluded to before, is really their decision having gone through the consultation process. So we have not had any kind of extensive discussions with them at all on this point. And to the extent that we have had discussions, obviously they would be confidential. But they're going through their process and we respect their process at this point.

Your next question comes from the line of Adam Mitchell from Polar Asset Management. Your line is open.

Hi, guys. I was just wondering if you can walk me through the flow of funds from the Solomon proceeds. I guess you're set to receive -- or TEC Pipe that receives $335 million of cash, which is about $420 million. Where does that go pro-forma that transaction, it goes all down to renewables?

The answer is yes, given like there's like tax implications as well. So that will create a taxable gain. So that's why like the -- we expect the Canadian proceed to be between $350 million to $360 million. And what TransAlta renewable own, it's an economic interest in the plan. So there will be a reduction of that economic interest to the different like financial instrument that we have there. So we have tracking pref, we have pref share and we have like notes. And like the money will flow through those instruments to TransAlta Renewable.

And that's expected in what month?

We are expecting FMG to exercise their option in November based on the notice they gave us.

So you get the proceeds in November, okay.

Yes, that's right.

So I guess Renewables will have close to $1 billion of liquidity pro-forma with that transaction, right?

Exactly.

Okay. And then the first -- I guess the first -- so you'll sit on that liquidity looking for potential growth opportunities. And I think you make reference in this -- one of the slides, say on Slide 8 that the money could be used to retire debt at Renewables. Given that you've already -- it looks like you've refinanced the credit facility that TransAlta provided to Renewables, the only other debt that's available to be prepaid is the Canadian Hydro Developers Bonds, correct?

That's correct. And there's also like timing because like -- to make all payments, so we haven't made a decision yet on what we're doing. We are also planning to raise like between $240 million and $275 million in Kent Hills, which is a subsidiary of TransAlta Renewables. So that's also additional proceed that will be in TransAlta Renewable by the end of the year and we will also have to decide what we're doing with that.

Right. What about -- is the convertible debt that's held at TransAlta, is that pre-payable at all?

Like clearly it's only payable in 2020 I think. But clearly like if we -- there's -- like that's one option. If we decide to move cash from TransAlta Renewable to TransAlta, there's potential drop down. But like the priority is to grow the company more than to do a drop down or to be paid the convertible debenture.

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

I just wanted to come back to one thing, Dawn, you talked about earlier in terms of if the power purchase arrangements come back to you and the dispatch rights and in the very different operating regimes you talked about, in terms of -- although there's no prohibition on economic withholding, I'm just wondering your thoughts on dispatch control given the revocation of OBEG?

Yes. I mean, the way I've always looked at it is I think the -- I think it's -- the accurate thing is to have the appropriate level of pricing for electricity over the long-term to have a competitive economy, and that's basically what we're guided by. So the way we think about dispatching is on the basis of long run marginal costs and our long run marginal costs would include a return for the equity and a payment, both a payment -- a repayment principal on the debt and an interest on the debt, because that's really the cost, the overall cost that have to be incurred. So to us, we have kind of our financing cost, our fixed cost and our marginal cost and they affect -- and we would calculate our cost at a reasonable rate of return based on what we see in this power sector and what you can prove in the market as reasonable. So that's how we think about it, Robert.

Okay. So directionally you're comfortable with the data based on the fully-loaded cost versus the marginal cost?

I am comfortable with that I can defend to customers and to the market and to everybody that long run marginal costs are appropriate in a time of excess demand.

There are no further questions at this time. Ms. Sally Taylor, I turn the call back over to you.

Thank you, Christine. Thank you, everyone. That concludes our call for today. If you have any further questions, please don't hesitate to reach out to the Investor Relations team.