Good morning, everyone. Welcome to Capital Power's eighth Annual Investor Day event here in Toronto. My name is Randy Ma. I'm the senior manager of Investor Relations. This event is being webcast, so I'd like to welcome the listeners on the webcast participating today.
Earlier this morning, we issued a news release outlining financial and operating targets for 2017, dividend and guidance out to 2018 and implications from the coal phaseout compensation. Before we begin, let me cover off the standard disclaimer regarding forward looking information. Certain information in today's presentation and responses to questions contain forward looking information. I ask that you refer to the forward looking information disclaimer at the end of the presentation as well as our disclosure documents filed on SEDAR for further information on the material factors and risks that could cause actual results to differ. Let me introduce Kappa Power's management team and the following people that are presenting today.
We have Brian Vageault, President and CEO Brian Denive, senior vice president finance and CFO Darcy Truffin, senior vice president operations, engineering, and construction and Mark Zimmerman, senior vice president commercial development and commercial services. The management team also consists of Kate Chisholm, senior vice president, legal and external relations, and Jackie Polipiak, vice president, human resources. So this is the agenda for this morning. We'll start with presentations by Brian, Darcy and Mark, and then we'll take a midmorning break. After the break, we'll conclude with a CFO presentation and a summary by Brian.
After the presentation, we'll take your questions, so if you can hold all your questions to the end. And then hopefully, you can join us for lunch afterwards. Okay? Over to Brian.
Thank you, Randy, and good morning. Thank you for joining us this morning for our Capital Power's Annual Investor Day. This morning, we're going to describe for you how Capital Power is executing on strategy, The strategy that stayed relatively the same for the last couple of years. Operational excellence and a strong financial position enables contracted asset growth across North America and enables the growth potential that we're seeing in the evolving Alberta capacity market. Capital Power's strengths remain the same, a growth oriented IPP with excellent assets, established and strengthening competencies in operations, development, construction and risk management, a balance sheet that enables growth.
And as you can see on this map, Capital Power's which shows Capital Power's existing operations and development sites that we have under control that we're targeting a very diverse portfolio of largely contracted assets that supports both the existing dividend and a growing dividend. Before we talk about 2017, I want to briefly touch on 2016. Capital Power's assets continue to have excellent actual operating performance. We expect to meet all our cost and sustaining CapEx targets. We did the work to start reducing our carbon footprint from existing facilities and our trading activities have done very well in a very uncertain Alberta power market.
This year, we've taken a significant amount of risk out of our balance sheet and our financial strength has been enhanced by compensation payments that we will be receiving from the Alberta government, all supportive of further growth and a growing dividend. We've made great strides from a growth perspective. The Bloom Wind project continues to do well, including recently securing a tax equity partner. We announced this morning securing one of the best wind sites in Alberta and we'll discuss the potential to further invest in the Genesee mine. Although not discussed today, we expect to announce over the next month or so another U.
S. Wind farm. 2016 is a pivotal year in the Alberta power market. Both the compensation issue related to the coal phase out and the legal dispute relating to Sundance C terminations have been resolved. I'll speak to these in-depth in a moment.
In November, the government announced they were moving towards a competitive capacity market. On the environment front, the Canadian government has been overlaying policy considerations on top of the provinces, culminating in the First Minister's meeting last week. It's actually potential outcome of that meeting is why we decided to defer our Investor Day in case something came out on Friday that we needed to address with you today. The coal phase out agreement is straightforward and is available on SEDAR. Capital Power will be receiving 14 annual payments of $52,400,000 starting next July.
These payments total $734,000,000 to be paid over the next fourteen years. The formulation follows the net book value approach we've been advocating for the last year and a half. Under this agreement, Capital Power is obligated to cease emitting coal based emissions by 12/31/2030, And that is the only operational constraint that we have. In addition to that, we need to spend $1,000,000 annually on development, on maintenance capital, on new projects within the province of Alberta to a cumulative total of about $70,000,000 We expect to meet that cumulative total within the next two years just through maintenance and normal expenditures. We are also committed to maintain a significant Alberta presence, which should be easily met.
Later this morning, Brian will be describing the accounting and other implications of this stream of $52,000,000 payments. The PPA termination is also straightforward. In exchange for $39,000,000 of which Capital Power will be funding or has funded $20,000,000 the balancing pool will assume the PPA obligations back to March of this year. Of significance is that that puts our two major issues with the government of Alberta behind us. The announcement by the Alberta government that they are moving to a capacity market from an energy only market was a bit of a shock to many.
We still believe the government objectives could be served by the energy only market, but pursuing a well designed capacity market would increase investor appeal. In the past, our biggest concern about the move to any other market is the treatment of incumbents during the transition. The move to a capacity market in a manner described by the Alberta government is the most positive and least risk to the incumbents from our perspective. Their commitment to fairness and equality of existing capacity is extremely positive and again is very constructive from an incumbent perspective. As well, a capacity market in Alberta is expected to be supportive of coal generation and natural gas conversion.
On top of the Alberta regulatory activity is the federal push for more national response to climate change. Although there is a clear recognition that provinces may have different underlying regulations, what has been suggested federally has been generally positive. The proposed federal coal regulations are actually moot as the established provincial regulation is zero tons per gigawatt hour beyond 02/1930. However, the federal approach to natural gas conversion is enabling as it sets the standard at five fifty tons per gigawatt hour for fifteen years or 02/1945, whichever is earlier. Our units converted to natural gas fall well within that standard.
So we see definitely natural gas conversion extending the lives of our facilities for the fifteen years. As Brian and Mark will touch on, this represents attractive economics for capital power. The development that took place last week at the First Ministers Conference is that the previous proposed increase in carbon price to $50 by 2022 is actually been replaced by a still undefined process where the federal government in conjunction with the provinces will set carbon prices for 2020 and beyond. I would like now to highlight what you'll hear during the balance of our presentation this morning. Darcy will speak to how we continue to make great strides on plant availability and cost.
He and Brian will comment on not only how we are viewing our carbon inventory, but how we are working to actually reduce our carbon exposure. Mark will be addressing how we are maintaining our competitive position across a number of good contracted operations or opportunities in The United States. He'll comment on our favorable existing asset position in Alberta. So in short, excellent assets and competencies in an energy only market translate directly to great assets and competencies in a capacity market. From a growth perspective, in addition to the Helcurt II site, we will be adding Whitlock, the proposed development we announced today.
We'll have four fifty megawatts of shovel ready projects to potentially bid into the first Alberta REP. We also expect in the next few months to announce a strategic initiative that creates a substantial future pipeline for renewable development in the province of Alberta. Brian will comment on actions we've taken this year to increase our balance sheet strength and how we are positioned to fund future growth, all of which goes to increasing shareholder value and maintaining and growing our dividend. I'll now turn it over to Darcy.
Well, thank you, Brian, and good morning. So today, I'll provide an update of our asset optimization, and then I'll touch briefly on some of the things we're working on both in operations and in construction. So Capital Power, we're in year five of our journey, improving performance and availability through our reliability program and driving optimization through formal plans that we have for each of our units. At Capital Power, we have been successful at getting much more production out of our units while spending less. And while we become very cost effective, it's all about spending smarter.
We have and will continue to do the right things to ensure we don't put ever our assets at risk. And on risk, we've done a variety of things. Some of those things I've spoken about at past Investor Days. And I think this year, a testament to how far we've come is that because of our lower risk profile, our insurance premiums are actually substantially reduced this past year, and it's because our insurers now view Capital Power as a very low risk operator. And as we've improved production, our safety and environmental performance has also improved, which really demonstrates that a productive plant is in fact a safe plant.
And in response to the climate leadership plan that has been announced by the government, we've implemented a very formal CO2 reduction program for our coal fleet which we term the Genesee Performance Standard or GPS. And I'll provide details about GPS later in my presentation. So this slide shows our journey on availability of the CP operated assets since 2012. Now the sawtooth is just because of irregular planned outages, but there's definitely a trend of improvement. You can see from the slides that in 2012, our average availability was at 93.5%.
And for 2017, we're budgeting actually for our own fleet a 96% availability. And that's those are substantial megawatts of production added to our company. And so on that, just this next slide shows the megawatt hour output improvements in that same period. And again, if you go back to 2012 when we were producing just over 8,900,000 megawatts with our thermal fleet, That same fleet for our 2017 budget is actually at 9,600,000. So that's 700,000 extra megawatt hours, which is substantial added EBITDA for the company.
From a solid fuel side at North Carolina, we have the two plants there. The journey has been very much the same. And you can see here from the slides the improvements we've made, and we're still pushing ourselves to get more out of those assets. But it's the same story, more EBITDA coming out of our units. On the renewable side, wind has become an increasingly bigger component of Capital Power's fleet.
And while we can't control Mother Nature, we're doing everything we can to drive our capacity factors up and to improve our availability so that when the wind blows, we are there ready to capture it. And again, this slide shows the journey. Again, it's a little bit irregular, but it is definitely trending upwards, and we continue to push our availability on the wind assets. From a cost perspective, the story is the same. Now these are normalized dollars.
I'm an engineer, so I look at it maybe different from an accountant. But we are you can see the journey. We continue to push down our cost. This is expressed in dollars per KW, but you can use any metric. It's the journey is there.
You can see that we're getting way more out of our assets by and yet spending less. And you can see in 2016 where we budgeted and where we're targeting to finish substantial improvement even in just this past year. Now the low hanging fruit has been picked. It's getting harder and harder to find cost savings, but we continue to
look for it.
And I mentioned earlier, it's not about cost reductions. It's about spending smarter. And a key part of that is that we have become way more proactive in how we maintain and operate our units. And so we're finding ways to prevent excessive wear and breakage, which means fewer breaks means fewer forced outages, which means fewer dollars spent. That the proof is right there.
From a CapEx side, now this slide, I'll just this is sustaining capital for the capital power fleet. And so the numbers that Brian will be talking about later in his presentation are all encompassing, but I'm just here focusing on the CP operated. So there's two types of sustaining capital. There's the ongoing maintenance capital, which primarily is the outages, the planned outages. I don't have a slide there, but spending has been fairly consistent over the last number of years, and we are working on that.
But that is the spend to replace in kind during outages to keep the plants going. And as I said, that spending is pretty consistent. But on the sustaining part here that I show, this is the more, what I would call, the nice to haves. And on this, we really just cut it out of our spend. You can see from the numbers here.
And what this is, is new projects, things that we would typically be adding to our existing plants. So at Capital Power, on our own fleet, we really try to eliminate this type of spend. So unless it's actually going to add value and add production or it's a safety item, we just don't spend money anymore. And the numbers are reflected there. Now I did flag separately GPS.
It's a significant cost component for 2017 in our budget. And I'll speak specifically about GPS. Now GPS, it will have a business case to it, and it's separate from normal sustaining capital. So we've broken it out separately and we'll talk about it separately today. On the mining side for Genesee, the journey has been very much the same.
In parallel to our plant performance improvements, we've been working with our mining partner, Westmoreland, to drive the costs of our coal down. And these two slides here capture very well the journey. So we've done a lot of things in terms of using some new tools and new mining methods that have helped improved our productivity of our equipment. And the result is, again, you see the coal cost there and how they've improved since 2012. And that's real dollars when you look at the fact that we're mining over 5,000,000 tonnes a year of coal.
And in parallel to that, it's not that we're only mining at a better cost, It's the quality of the coal that we're mining that's gotten better. And there's a 5% improvement shown in the heat value. And that's just with the new mining techniques we're using. It means that we're delivering that means less coal needs to be hauled to the plant. And less coal into the plant means there's less ash and less wear and tear.
So it has a whole knock on effect in our operations. But we're very proud of these achievements. And this is all about getting more from the assets. From an HSE perspective, the journey has been the same. You can see the trend in terms of improvements, both on a recordable incident and on an environmental perspective.
At Capital Power, unlike many in our business, we actually include in our statistics all of our contractors and subcontractors. So we do that because when you work in our sites or at our plants, we feel responsible for your safety. And this past year, we've actually gone it's over two years now without a lost time with us, with all our employees and all our contractors and subcontractors. And we're really proud about that. I just want to make a little comment about because I think it reflects on our operations and specifically about the burden batt mitigation.
Burden batt mortality is becoming increasingly more important with wind assets. And we've just completed successfully at PDN in Helkirk our three year program, which was part of the permit. And how we did that, rather than just counting, we actually tuned down our units during specific times of the year. And we did that to reduce the mortality. And the net result is that we were well under the permit requirements.
But it just to me reflects on how we operate. Rather than waiting for a problem, we were proactive in addressing it. And it had a small impact on our output, but really we think that that's the right thing to do. So on GPS, this slide is capturing the journey that we expect to go through over the next five years. Now we've already started, and I actually talked about this last year at Investor Day, about some of the changes we'd already started to make.
And those changes were primarily in terms of boiler tuning, in terms of tweaks in operation. CO2 has never been a metric that we had to worry about until now as we go into the new climate leadership plan. So we've already started on that and started to make a number of operational changes. And we substantially improved our CO2 performance over the last year and a half. Now in this slide, we don't show us capturing as much value.
And that's because on G1 and G2, the benefits really accrue to the balancing pool who own the PPA on hold the PPA on those units. But what we are showing here is that over the period of time from now to twenty twenty one twenty twenty one is when we take over G1, G2, and then we'll get all the benefits then of our emission improvements. So you can see that we're ramping up to about $30,000,000 of expected avoided cost for our fleet, our coal fleet, by 2021. And about $5,000,000 in parallel of savings that will become an annual avoided cost. And that will be funded or paid through a program that we think will cost around $30,000,000 of changes.
And this is some hardware changes, software changes and other types of changes that we'll make to our fleet between now and then. So we're very excited about this. And I'll be reporting about on this year over year in Investor Days. Now on a I want to just briefly talk about new asset development. Now since our inception, we have successfully demonstrated that we can build plants on time and on budget.
And Bloom, it's latest project. It's our second U. Wind development. It will be a success. Bloom, I think, confirms that Capital Power can really build anywhere successfully in North America.
Now we are a very much hands on builder. We are very prescriptive to our contractors and OEMs as to what we want. And we do that because we want to make sure that when we take over that plant, that it's a plant that will be cost effective to run. We also have a group of people that we assign to the projects, probably more than some others. But we do that because we want to ensure that what we get that what's built is what we've paid for.
And that we have people on the projects that can deal with issues before they become, you know, expensive problems. We've standardized our systems, our tools, our processes, both from an operations and a construction perspective. And this helps ensure that our plants are built to the same standards and that we operate to the same parameters across our entire fleet. We also have in house estimating and front end development and engineering capability that we I believe personally that it gives us the ability to really be cost very competitive, cost competitive, and find solutions. And so on new builds and new opportunities, we think we're going to be extremely competitive and win more than our market share.
So on Bloom, just a quick snapshot of Bloom. Bloom is 178 megawatt project in Kansas. There's fifty four three point three megawatt Vestas machines. This project is going extremely well. All the civil work is done.
We're ahead of schedule. We're starting to receive towers as we speak, and we're accelerating the construction, the erection of the turbines to early January. The COD is planned for the June. So I just say here, this will be another successful capital power project. Now just a few words on coal to gas.
Now Mark has got much more on this from a commercial perspective. I just want to make a few technical comments about the coal to gas conversion opportunities. Really, a key message that I want to deliver, you can read the slide here, but the key message is that we have the youngest coal fleet in Alberta, the best conditioned units, the highest available units, the the the best heat rates of all the units in Alberta. And all those advantages, when the time comes that we want to convert, all those advantages will follow us to gas. We don't lose them.
And that's a really key point for you. Now again, Mark will go through the commercial aspects of timing and that, but I just want to leave that message with you. So all the stuff that we've done over the years to make our units better will capture that value even when we convert to gas. So in closing, we are executing to maximize asset value. We continue to drive optimization.
And now included in that optimization is a methodical approach to reducing our CO2 footprint. And the advantages we have with our coal assets will follow the units as they are repurposed. So thank you, and I'll now turn the podium over to Mark.
Thank you, Darcy. And I'd also like to extend my thanks to everyone for taking the time out of your busy schedules to be here with us. To recap, Brian has provided you guys with a strategic overview, and Darcy has followed with a physical and operational snapshot of our business. I'd like to provide now a commercial development overview, set the stage for Brian's summary of what our future will look like. To begin with, we've got a very strategic footprint in the province of Alberta.
We have low cost, high efficiency assets. We have the people to operate and optimize those assets. And it's those same people that we're able to leverage off of to support and grow our business. I would observe the uncertainty that has overshadowed us in Alberta over the last year is starting to clear up, and it's leading to an improved business environment for us. As that business environment stabilizes, we are ready with a number of investment opportunities to exploit our incumbency advantage in the province.
In addition, we view the migration to a capacity market as something we can compete and win at as many of the energy market trading skills we have, and as Brian had pointed out, are equally applicable in a capacity market setting. That said, we do see the value in having a geographically and field diverse portfolio to provide the stability and visibility to our growing cash flows. So we'll continue in our efforts to secure investment opportunities elsewhere in North America. It is with this combination that we see sustained and growing cash flow and increased shareholder value. So what does that mean to us and what our key focus areas are?
First is the recognition of the unique position we have in the province and the value and opportunities it provides to us. It also means that we need to continue in our efforts to secure investments in other North American jurisdictions and ensure we continue in the development of a diversified investment portfolio. Within that focus, we will ensure we capitalize on the competencies we possess. Specifically, as an example of some of them, our strict construction capabilities span thermal and renewable generation, as Darcy has reviewed. Our fuel management skills is a critical element in all our thermal generation.
Our commercial skills in prospecting, contracting and optimizing is equally important. And our partnering and structuring skills to arrange and enhance joint ventures and partnerships to enhance our competitiveness is key. It is this focus and combination of competencies that will lead us to an improving cost of capital. So let me start with the strategic footprint in Alberta. This map shows the main transmission routes in the province with a low overlay of our existing assets, illustrating our incumbent strategic position.
We are strategically connected and thus require minimal incremental cost to connect additional supply. We have a highly trained workforce. We are one of the largest builders in Alberta over the decade, demonstrating our ability to assemble and permit opportunities on time and budget. We have the trading skills to enhance our margin, skills which are portable to this new structure. And it is this footprint that gives us an advantage in gas generation development at the least consumer cost and the highest reliability.
We do have a shovel ready new build in the form of G4 and G5. We and our partner continue to enjoy contractual flexibility. And with the uncertainty arising over the last year, we continue to push out our final notice to proceed decision until more clarity on the market design and the need emerges. When market conditions are conducive, we are ready to ramp up and create one of the most cost and emission efficient plants in the province. And in addition to the new builds, opportunities also exist for the conversion of our coal fired units, which Darcy referenced and which I'll speak to in a moment.
Finally, we also have expansion peaking opportunities available within our Clover Bar Energy Center facility should market conditions warrant. In short, in a market of 16.5 installs of gigawatts of capacity, we currently have around 15% of that fleet with the potential to grow further. Now I mentioned our trading capabilities. I thought I'd spend a brief moment on the trading track record. As this chart illustrates, we have historically on average been able to realize better than the market spot price as a result of our activities.
As you can see, more recently, we have been experiencing very low spot pricing as daily volumes are being bid and dispatched at variable costs. However, one month out forwards and beyond have remained robust. Two key points are highlighted by this slide. One, we are well positioned to continue to generate enhanced value from managing our inherent long position. And two, the trading capabilities are portable to this new capacity market.
As we move forward, there is the expectation that the low spot price that we have now will not be sustained. As supply and demand come into balance, improving market fundamentals will emerge. The dash blue line represents the current forward market's expectation of this. And while we have seen historically a directional correlation of gas prices to power prices, going forward we feel gas prices will recover less than power as other influences like carbon tax and the merit order will move to influence the power pricing on a forward basis. In short, the market is indicating that prices are due for recovery.
And this dynamic will assert itself regardless of which market structure is in existence. In other words, moving to a capacity market shouldn't change overall pricing fundamentals. As many of you know, Alberta will be implementing a capacity market structure. The current status is that the policy decision has been decided and the details will now be worked out over the next twenty four months. The government has initiated consultation for implementation.
The first auction target is targeted to occur in 2019 for delivery in 2020, 2021. The key to us is the promise that the existing generation will be treated fairly. As Alberta's Energy Minister, Martin McQuade Boyd recently stated, power companies have her word that the new market framework will continue to promote a level playing field. So with a level playing field like we have before, we will be competitive such that overall revenue should be similar to that which we would have enjoyed previously. It's just that now it will be provided in two components.
And the mechanics are pretty straightforward, however, with more certainty on the capital component. All generation capacity will bid in with the last bid in to meet the target setting the clearing price for everyone. Similarly on the energy side, those that receive capacity payments will need to offer in with the price being set by that marginal unit. The key will remain though, specifically those with the lowest cost and best efficiency will generate the best margins. So to reinforce this point, I thought we'd share some analysis with you guys.
The following chart illustrates a number of things. First off, the solid lines are representing the historical realized and spot prices that we've enjoyed over the last number of years. The dash lines are the forwards in our expected realized price given our targeted hedge positions that Brian will review shortly. If we back calculated what our assets would have realized from capacity energy revenues in a PJM like capacity market, that represents the shaded area on the graph. And if we project that forward going forward, pardon me, a number of interesting observations emerge.
First is the expectation that under either market scenario, the total market price by 2021 will be similar in either market as the market fundamentals do return to balance. Secondly, there is a higher degree of stability in a capacity market than that which we enjoyed in an all energy environment. With respect to supply and demand fundamentals, a meaningful component of our current supply stack is the coal fleet. As we move into a world of higher carbon taxes, the merits of converting from coal to gas fired will come into play. The following graph is a simplified representation comparing coal fired to converted gas fired generation.
The actual comparison will be more complex as it will be influenced by a number of additional considerations. But for purposes of today's discussion, it does give you a visual for the decision we'll be faced with. The chart illustrates an indicative variable cost structure, including variable operating costs, fuel and a carbon tax at a $30 level, and compares the cost of existing coal generation to a converted gas operation. A number of observations occur. First, breakeven economics are close and we are almost indifferent between continuing to run coal or converting to gas.
Second, the vintage of the units is very important as older subcritical are costlier and less efficient than newer subcritical and even more so than supercritical. This analysis will also be very contingent on gas price and heat rates as can be seen by the large fuel component. Finally, in a capacity market structure, the viability of generation will have to be in the context of combined capacity and energy price relative to the rest of the stack. In other words, a higher certainty of dispatch for those lower on the cost curve. So putting this all together, we put forward an indicative dispatch curve which will help to illustrate how the mechanics would work.
Capacity and energy will be bid into market based upon the needs of the market. The current dispatch curve is the blue line on the lower right portion of the graph, illustrating that at current peak demand of 11.4 gigawatts, pricing is in the mid-twenty dollars range. When a $30 carbon tax is applied, that dispatch curve will move up into the green line. Plus, gas and coal generation will switch places as illustrated by the wider ranges upfront. As shown by the black square, our G1 plant will move from lowering the current dispatch curve to slightly higher when a carbon tax is applied.
Equally as shown by the red circle, our Shepherd plant would move from being quite high in the dispatch curve to much lower. If we then take wind out of the stack, we would move to the purple dispatch line and it illustrates a very tight reserve margin emerging relative to the peak. So given the critical need for reliability in a system, a reserve margin will need to be applied and that is the dashed vertical, I guess black line. Therefore, new build signals or higher capacities will begin to materialize. So with that, I'd like to move to a discussion of Alberta renewables.
First, to recap the situation, The policy has indicated a desire to move to 30% of the fleet being renewable generation by 02/1930. This represents about 5,000 megawatts of renewable electricity program. The Alberta system operator will run the process. The first call will be for 400 megawatts for delivery in 2019. It will be under a twenty year contract and this first call will be awarded to the lowest cost alternative.
The structure for subsequent auctions will evolve and may include stakeholder criteria as we move forward. But of critical importance is the timing of the award being in Q4 of twenty seventeen with delivery in 2019. This is a very tight turnaround, which as a result will really only be available to those that have projects that are well advanced. And it's within this context to note that we are ready. As already highlighted, we have the demonstrated construction capabilities as evidenced by Tumbler Ridge and Alkirk, both projects that were able to be delivered on time and budget.
We also have the training skills to manage the overall portfolio. While I'll speak to our two most advanced projects, Halcirk II and Whitla shortly, I would also like to point out that we're working on many other wind and solar opportunities within the province for future auctions. We are actively pursuing a number of new and existing sites that are well positioned in the best wind regimes and closest to the existing infrastructure. And that's what this map is attempting to illustrate is the wind resource that we would be looking at, Central Alberta, Southeast Alberta, and the overlay of the transmission grid. In addition, we are looking at different partnerships that would supply a significant pipeline of future development sites.
As Brian has mentioned, we expect to announce a strategic development that will provide significant solar and wind capability for future development. I would also like to observe that as you will see on my comments on The U. S. Efforts, we are increasingly becoming competitive in those markets and we expect that we can equally apply those learnings in Alberta. So the first opportunity I'd like to review is our Helkirk II option.
Approximate 150 megawatt proposed project will be co located north of Capital Power's existing Helcurt wind facility in East Central Alberta. We're pursuing permitting and regulatory applications. Two meteorological towers were installed in early twenty sixteen and environmental assessments and wind farm design are underway. The project is located about three kilometers away from a substation, which has estimated four fifty megawatts of capacity. We have the local support.
18,000 acres have been secured. In summary, a project with a great wind resource in the high 30s capacity factor. The second opportunity is our Whitla option. Project will be located Southwest of the City Of Medicine Hat in the 40 Mile County Alberta area. As announced in our press release, we have reached an agreement that allows us to leverage off of seven years of wind data.
Our access to the data will give us a significant time advantage. 33,000 acres have been secured for this initial 300 megawatt opportunity that will be built in two phases. The project will use the latest technology and utility scale wind generation. We are pursuing permitting and regulatory applications and have filed an application for interconnection with the ASIL. The site is located approximately eight kilometers away from a substation, which is connected to the Southern Alberta transmission reinforcement line, a line that is estimated to have 700 megawatts of capacity with very cheap expansion capability of up to 1,000 MW.
The proposed site has a very attractive wind resource expected to be in the high 40% capacity factor range. And finally, there's some real potential for future expansion. Now I mentioned at the start that we remain focused beyond Alberta as well. We have been very active in many other opportunities. And I should note this has not only been greenfield but M and A as well.
I would observe that buying or building generation infrastructure does remain a very competitive environment. However, given the focus and the competencies I previously reviewed, we believe we can compete while maintaining our investment discipline. We expect over the next couple of months that we will be in a position to announce two moderately sized investments. On a broader basis, we do see policy initiatives evolving. Given the recent U.
S. Federal election results, there are some questions arising in respect of the level of federal support. But we would note many of the initiatives we are pursuing are more state driven mandates than federal. In short, there's a lot of renewable initiatives that are out there and that we are prepared for. And for context, we're not just limiting ourselves to just one market.
The initiatives we are pursuing cut across many markets in The U. S. Of the installed 1,000 gigawatts of existing generation in The U. S, we are active in six of the 10 markets. The key for us is playing where we can be competitive.
Evidenced by our Bloom opportunity in Kansas, our demonstrated capabilities of commercial contracting, stakeholder relations, permitting, supply chain and construction places in a very attractive position. Before reviewing some specific opportunities, I should also note that the nature of who the counterparties are has started to change. We are seeing an interesting emergence of a significant additional driver in the form of additional demand arising from commercial and industrial requirements. In short, many corporations are becoming greener with their load characteristics And as we have seen with Microsoft being a major subscriber for our Bloom capacity, we expect this trend will continue. An example is Altanex as an aggregator, is who we have used to assemble load and act as the intermediary counterparty for our Bloom project.
And we see this sort of arrangement continuing on many of our other developments as well. I also mentioned the evolution of federal policy versus state. While there's been much discussion of potential declining federal support, as can be seen from this summary, the state level support for renewables continues to be significant. In short, it is clear the states are continuing with their plans. Many states are well established and continue to move forward in execution.
So with this in mind and to maintain our competitiveness, we have taken steps to preserve the value of our production tax credits or PTCs. As many of you will recall, as shown on the table, the PTC eligibility was set to ratchet down if not under construction by the year end 2016. Put another way, projects must be under construction by the end of the year to qualify for the full tax credits. Plus, developers have four years from commencing construction to reaching COD in order to be presumed to have had a program of continuous construction. We believe our projects are fundamentally sound and will go ahead.
So to enhance our competitiveness, we have taken steps to maintain our PTC eligibility. And to demonstrate that we have initiated construction, we have made a commitment for seven transformers as a way to demonstrate the start of construction and expect to utilize these within the four year window. Darcia has reviewed the status of Bloom. I thought I'd review some others in the queue that we're working on. First out of the gate is Tisch Mills in Wisconsin, which is part of the MISO.
It's roughly 100 megawatt investment opportunity for us. 12,000 acres have been secured. And Tisch is well positioned for RFP as it's one of a limited number of utility scale renewable projects in Wisconsin which they will seek out in order to meet their mandated Wisconsin Renewable Portfolio Standard requirements. The second is New Frontier Wind in North Dakota, a 99 megawatt investment opportunity, 11,000 acres secured. It is already permitted and ready to go.
It arose as a very strong wind resource in the MISO region where utility transmission arrangements and the potential for bilateral contracts could enhance its competitiveness. Another one is Black Fork Winds Ohio. This could be anywhere from a 100 to 200 megawatt investment for us. 24,000 acres have been secured. And it is one of a handful of permitted Ohio projects that AEP might look to for its 500 megawatts of renewable requirements.
And Cardinal Point wind in Illinois, 150 megawatt investment, 15,000 acres secured. Illinois has an RPS requirement that is not procured much under. And in addition, the recently passed legislation in respect of Exelon has also included an additional 1,000 megawatts of renewable procurement required in the medium term. So the foregoing was just a sample of some of the nearer term opportunities which may arise. And I should clarify that one of the two imminent projects that I had mentioned at the beginning would include one of these near term wind opportunities.
We continue to work on a number of additional options which may become viable in the medium to long term as evidenced by this table with some additional options. We also continue to look at other pure greenfield sites to assemble and we do remain active in the M and A space where the characteristics of the assets being monetized are consistent with our investment parameters, specifically that they exceed our risk adjusted hurdle rates, are consistent with our articulated strategy and that we'll be supportive of the dividend paying company. So to recap, hope I have left you with an appreciation for how we plan to invest and grow our cash flow. To reiterate the key observations I wanted to leave with you today, we have a very strategic footprint in the province of Alberta and are growing our presence elsewhere. We have the steel and the people to support and grow our business.
The uncertainty that has overshadowed us for the last year is clearing up. And as this clears up, we are ready with a number of investment opportunities. We view the migration to a capacity market as something we can compete in and win at. But we've also realized the value of a diversified portfolio and providing the stability and visibility to our growing cash flow. So we'll continue in our efforts to secure investment opportunities in the rest of North America.
It's with this combination that we see sustained and growing cash flow for our investor base.
Thank you.
Okay. Thanks, Mark. It's 09:50, so we'll take a ten minute break and come back at 10:00. You can if you can take your seats, we're gonna start right away here.
Good morning. My name is Brian Denis. This morning, I'm going to, touch on, first of all, a recap of our overall finance strategy at Capital Power, then get into a little bit of the accounting under the coal compensation, talk about 2016 guidance and then 2017 guidance, and then touch on an update around our GHG obligations, status of our inventory of offsets, and then conclude with an overview of some of the financing initiatives that we've completed this year. So moving to start with the finance strategy, there's really four pillars that Capital Power pursues. The first one being maintaining investment grade credit rating.
Certainly, we see some IPPs in The U. S. That don't maintain investment grade. From our perspective, it does give us lower cost of capital, but also just as importantly, access to the capital markets as we go through business cycles. So as you look at our strategy that Mark covered, entails a lot of longer term development projects that we need to finance over time.
The second component is on the dividend. And certainly, I'll talk about this in more detail. But for us, a key focus is maintaining consistent growing dividend over time. And we look for opportunities for projects that do sustain that or support that strategy. In terms of managing financial risk, that primarily focuses around us putting in place medium term debt, but also includes our capacity to be able to manage foreign exchange risk, in particular given our U.
S. Operations. So we don't typically like to be speculating on the foreign exchange rates. So we look on a net basis of our exposure and then take positions to manage that in the market. And then finally, ensuring discipline around the growth.
As Mark alluded to, we do have very well defined financial criteria that we apply to those growth opportunities. But we also look at those growth opportunities through the lens of ensuring that they won't compromise our ability to maintain our investment grade credit rating, but also that the profile of those projects in terms of cash flow is going to contribute to providing that base to support a growing dividend. So this chart shown in the past, just to reiterate our priorities for capital allocation. Number one is to ensure the funds are going to maintain a sustained growing dividend. Then of course, our second priority beyond that is looking at growth opportunities in finding those as we move forward to support that underlying growth in the dividend.
And finally, if we do go through periods where we may not have the growth opportunities, We went through this about a year ago. That will be a point in time where we'll look at paying down existing debt or buying back shares as appropriate in the market. So turning to the coal compensation. As Brian mentioned, under the agreement with the government, we'll be receiving $52,400,000 per year over the next fourteen years. And that will be received at the July of each year.
When we look at that payment, it will be recognized as other income and will be then forming part of our EBITDA and adjusted EBITDA on our income statement. In terms of net income or earnings per share, it will reflect the difference between the coal compensation and the higher depreciation expense that we're going to experience due to the fact that we will no longer be able to burn coal starting at the February. Now what's interesting around this is, as we've worked through in the discussions with the government and did internal work, it's become apparent to us that for our coal units, at 02/1930, when we're no longer allowed burn coal, we'll have an average remaining life of the equipment in those plants of about fifteen years. So that would include the steam turbine, the generator, and the boiler. So when we look at coal to gas conversion, one of the big benefits with our units is very little dollars will have to be put into the equipment that's downstream of the coal handling facilities.
So as a result, when we look at our depreciation expense, it's really the coal handling facilities and the mine capital equipment that has to be depreciated through 02/1930. So as a result, we're expecting an increase in our depreciation expense in 2017 of about EUR 27,000,000. So that'll leave a lift in net income of about EUR 25,000,000, which translates into about EUR $0.01 9 per share on an EPS basis. The final point I would like to make is through initial work we've done, we don't expect an impairment to our assets as a result of the 2030 date. And that's after, of course, taking into consideration the level of the coal compensation, but also the value that will remain in those units to operate beyond 02/1930.
So you take those two together, we don't anticipate seeing an impairment. So when you look at the nature of the cash flow from the provincial government, basically, it's important to look at the underlying obligations in that agreement. And those conditions are basically fall into three buckets. The first one is we will no longer burn coal to produce electricity at the end of 02/1930. The second condition is we need to spend a minimum of 1,000,000 each calendar year as investment in the Alberta market, but with a total investment of 70,000,000 by the end of the next fourteen years.
Those obligations are will be fairly easy for us to meet. Our sustaining and maintenance CapEx on our units is about CHF 65,000,000 per year in Alberta. So those obligations ones that we don't anticipate there'll be very low risk of us not meeting those obligations. And then the third one is maintaining a significant presence in Alberta, which of course we're doing now and don't foresee any changes in that. So what that leads us to is the prospect of potentially being able to securitize those cash flows given their low risk.
We've had some initial discussions with around potential securitization. And it's possible that we may see a cost of capital associated with it in the 2.5% to 3.5% range. And if you take that on a net present value basis of the EUR $734,000,000, that translates into about EUR 600,000,000 in proceeds. Now of course, for us, the timing of doing the securitization will depend a lot on what's happening on the growth side. We do have further work to do in terms of understanding the interplay with some of our existing covenants, but certainly is an opportunity for us as an organization as we look forward.
So one of the areas we're also looking at as we roll into 2017 is purchasing the remaining 50% interest in the Genesee mine. So currently, we own 50% of the mine equipment and the current operator of Genesee mine owns the other 50%. When we look at that, basically the structure of the arrangement is such that for the capital that the partner puts in, we pay them basically a cost to service type payment for the coal, which would include a return on capital investment as well as a depreciation expense. One of the things we're seeing happening, of course, as I mentioned earlier, is that, that equipment now is going to be amortized over through 2030 or depreciated over that period. So as a result, we were expecting to see quite a lift in our coal cost expenses.
By buying out the balance of the mine, that will result in a substantial reduction in our coal costs in 2017, and we should see a lift of about $12,000,000 in FFO. The one other area I want to touch on quickly was just to provide some guidance from a modeling perspective around Bloom wind. As Darcy mentioned, Bloom is on track to be completed in June of next year. Once that project is completed, at that point, we will receive cash from the tax equity investor, who is Goldman Sachs. We just closed that arrangement yesterday.
So Bloom's total capital cost is about CAD $350,000,000. We'll be funding that up until completion of the facility. At that point, we'll see an investment from Goldman Sachs of CAD $235,000,000. And the way we look at that from an accounting perspective is that's essentially debt that will be going on to our balance sheet. And then that will get paid down as we recognize the predominantly the tax benefits Goldman will be receiving through the production tax credits as well as from the makers on the accelerated depreciation.
So you'll see quite a gap as this graph shows between actual cash flow and EBITDA that will be flowing through our statements. That gap closes though by time we get to the flip point when the tax benefits are fully realized by the tax investor. Just want to touch briefly on our G and A expense. You'll recall last year, we walked through in a bit of detail around steps we had taken as an organization to effectively rightsize on the G and A expense. And the result of that work is that when we go back from 2012, we're going to see our G and A expenses decreased by 8% as we look into 2017.
Over that same period, we've seen inflation running about a cumulative amount of 10%. So 2015 was that period of time where we feel we did get the organization right sized. We have the systems operations in place that allowed us to streamline the operations. And now we're just seeing increases that are more commensurate with inflation as we go forward. I'll just note the increase from 2015 to 2016, that was primarily driven by increase in business development spending.
Our out of scope management salaries we held constant over that period. As we look forward into 2017, we're expecting some wage escalation to increase about 2%, the overall G and A expense. So I'll turn now to our 2016 guidance. You'll recall that our guidance going into 2016 was a range of EUR $380,000,000 to EUR $430,000,000 of FFO. At the end of Q3, we were guiding that we were going to end up in the top end of that range.
However, with the agreement in the settlement on Sundance CPPA, we've now made a payment of EUR 20,000,000. So that reduction in FFO means we'll probably come in or we expect to come in, in the low end of the range for 2016. As we look forward to 2017, you've seen this graph before. We've now added our targets for next year. And the key message there is we're expecting continued strong cash flow generation.
From an operations perspective, we're expecting the FFO to be more or less stable year over year. However, we are seeing a lift, of course, from the coal compensation payment. So together, that will result in approximately a 10% increase in our funds from in our cash flow in 2017 relative to 2016. When we look at the components of the allocation of that cash flow, and I'll get into a bit more detail on the next slide on this, But you'll notice that on the common dividend side, it's about 35%. It's remained constant.
So what's happening there is we have built in a projection in our common dividend of 7% in 2017. But that is, of course, because we have the increase in overall cash flow, that percentage remains constant. There's a slight lift on the preferred share dividend, and that was due to the placement of EUR 200,000,000, which I'll earlier this year. And then when you look at the sustained maintenance CapEx of 19%, that suggests quite an increase on sustaining maintenance capital. However, you want to keep in mind that there's EUR 10,000,000 in there for the Genesee Performance Standards Program that Darcy referred to.
So that's expected to produce benefits for us, particularly as we look forward into 2021. This just shows the breakdown in more detail. So sources of cash in 2017, EUR $440,000,000 from funds from operations and compensation. And then the proceeds from the tax equity investor on Bloom of $235,000,000 In terms of uses of that cash flow, common shares projected to be 155,000,000 which includes a 7% increase. Preferred shares of 30,000,000, so that includes about a 10,000,000 increase as a result of the 200,000,000 of preferred shares we raised earlier this year.
The Genesee performance standards, break out separately on this table is EUR 10,000,000. And then our sustaining and maintenance CapEx is EUR 75,000,000. So net, when you look at cash flow available for growth, we're seeing about $385,000,000 next year. Our projected expenditures on growth is $320,000,000 That would include the completion of the Bloom wind project. It would include the another wind development project that we expect to be underway next year.
The purchase of the 50% interest in the Genesee mine and then also capital expenditures to continue to maintain the Genesee Fourfive project as a shovel ready initiative. So one change we're making this year's guidance is we're going to switch to providing the guidance on adjusted funds from operations. And effectively, the definition of the AFFO is consistent with what we see in the industry with the exception of the coal compensation, which is a unique beast. But we start out with our traditional funds from operations as we've defined in previous years. We add the coal compensation and then we subtract sustaining and maintenance CapEx and then subtract the preferred shares dividends.
And we're making the switch primarily because we feel the FFO will be a much stronger line of sight to the funds that are available to exclusively support the dividend, the common dividend as well as what's available for CapEx expenditures. So what we've done here is we've cast 2014 through 2016 in terms of the AFFO metric. So 2014, twenty fifteen would be our actual AFFO. 'sixteen would be based on our guidance we provided last year translated into an AFFO number. And 2017 would be our guidance around AFFO of CHF $325,000,000.
Now we've shown it broken down into the amounts that we see going to common dividends and the amount that will be discretionary cash flow that's available for growth investment. And the payout ratio over those four years has been constant in the around the 4546% range. As we look forward to 2017, we're looking at a payout ratio in that ballpark. For us, what's really important is that, that payout ratio is substantially below where we see our peers, which averages about 58% of AFFO. So just want to turn to some of the initiatives that Capital Power has completed.
In 2016, that has resulted in improving the strength of our balance sheet and improving our positioning to be able to fund growth on a go forward basis. So the first initiative that was completed was in July of this year was extending our credit facilities by one year. So that's maintaining that five years was very important to us in terms of maintaining liquidity. Through those discussions and extension, we also increased the credit facilities by EUR 55,000,000 through the next four years. We also have maintained an inquiry feature which permits an additional $245,000,000 to the credit facilities if appropriate.
The second initiative that was completed was private placement debt financing with Prudential. This work followed on a lot of good relationship building across capital power with Prudential in the market. And effectively is a ten year unsecured senior note that with a rate of 3.85% over ten years. So this the cost of this debt relative to what was being quoted at the time, the Canadian bond market is very favorable. And it certainly led to a reduction in our overall cost of capital.
The other important points to note about this private placement is it's non amortizing. The other thing is it's similar covenants associated with it as our credit facilities as well as our other U. S. Private placement we have in The U. S.
The third element that was completed as a follow on to the private placement was preferred shares issuance. We felt the timing was right following the completion of the private placement to go into the preferred share market. We saw a lot of activity starting in the preferred share market and it was reopening. So we took advantage of that and we're able to place $200,000,000 with the yield of 6%. And in terms of the yield that we achieved on that financing, part of that, we believe, was driven by the fact that we were able to achieve 3.85% on the ten year debt placement.
So as we look forward to financing growth opportunities in the pipeline that Mark spoke to, we're very well positioned. We've in terms of the strength of our balance sheet, most of our credit facilities are available to support development expenses or as a short term financing vehicle. We also have CHF 170,000,000 of discretionary cash flow in 2017 That's left after we meet all our financial obligations. And we're now in a position to also raise equity if the right opportunity presents itself. Certainly, the improvement in our share price, a year ago, we were sitting at around $16 per share.
We're now getting close to $24 has together, along with our lower cost of debt, has dramatically reduced our cost of capital and made us more competitive. And when you look on the our ten year spreads in Canada, we've seen 150 basis point reduction over the past year. A lot of that due to the certainty that's been gained in the market, but also I think by of the private placement financing that was completed. So when we look at from the credit agency side, the debt to total capitalization remains very low. For 2016, we're targeting that will come in at approximately 34%.
And of course, strong corporate liquidity measures with the credit facilities that are in place. We continue to be remain at investment grade credit rating by both S and P and DBRS. So one of the key metrics for us when we look at the guidance that were provided by DBRS and S and P is the cash flow to debt metric. And as you'll see from DBRS's metric, which kind of requires a threshold of 20%, we're well above that as we look at 2017. And similar from the S and P perspective, with a minimum of 15%, we expect to be close to 20% this year and 20% next year.
So certainly, we're in a position where we have a good cushion over that FFO to debt metric, which is critical of course to maintaining our investment grade rating, but also provides us flexibility as we look forward and look at different opportunities in the market. This chart you've seen over the last several years, basically the change made to it is we have the new private placement in there coming due maturing in 2026. We continue to have very well, very nicely spread out maturities on the debt side. So certainly, that's something that fits with our objectives of minimizing overall financing risk. So I'll turn quickly to the compliance on the carbon side.
And I'll start with the climate leadership plan in Alberta. And the climate leadership plan, doctor Leach's report to the government that came out a year ago, provided recommendations on changes to the specified gas emitters regulation in Alberta. So what was recommended was to move to a gas standard, and that you'll be required to comply down to a best in gas standard on the coal units in Alberta. So effectively, we would see that best in gas standard is probably being something similar to the CO2 intensity on our Shepherd facility, around 0.37. Certainly, there's been some discussion, maybe that will come in more around 0.4.
And of course, our coal plants, the intensity ranges from 0.9 to one ton per megawatt hour. So that delta is one that we'll be obligated to comply to. We expect we'll have two ways to comply. The first is to have carbon offsets that have been approved and made in Alberta carbon offsets, or pay into the carbon tech fund at $30 So there's a process now underway. Government has started to iron out the details on this.
And we would expect in the first half of next year to have line of sight on this. But we still anticipate it will look more or less consistent with what we saw in the report from Doctor. Leach. So when we look at the impact of this change in the carbon tax, it's important to look at it from two periods. So through the end of twenty twenty, we have the obligation from the compliance perspective on Keep Hill three and Genesee three.
On Genesee one and two, that compliance obligation rests with the balancing pool, which is effectively the PPA buyer. So as Mark showed, once this new carbon tax is implemented, we're going to see the merit order change in Alberta. You're going to see this reflected as part of the variable costs of coal units bidding in. And we expect to see an increase in pool price of around $7 to $8 a megawatt hour in 2018 solely because of the higher compliance costs. So when you look through to 2020, effectively the increased cost to us, a lot of it will be covered by higher pool prices as a result of the variable cost nature of those compliance obligations.
When we look beyond 2020, at that point, we'll be then also assuming the obligation on Genesee one and two. But I think what's important there is the focus and the good work that we're doing as an organization to physically reduce our emissions from our units under the GPS program that Darcy spoke to. And we anticipate that that will reduce our compliance costs by 35,000,000. Well, part of it will be fuel, part of it will be avoided CO2 costs, but in total a 35,000,000 benefit in 2021. So the other element though to complying in Alberta is going to be our carbon inventory of offsets.
And the first bar you see here is what our cost of compliance would be for our coal units in Alberta, assuming we didn't have any offsets. So you see it increases dramatically from $6 a megawatt hour in 2017 to twenty dollars a megawatt hour in 2018. And again, that's just the fact that we now have to comply down to a best in gas standard. So last year walked through the other element to it, which was our inventory of offsets that Capital Power owns. And that second bar was what our cost of emissions would be as we utilize our inventory to meet those obligations.
And it was interesting when we got to 2019, unfortunately, our inventory would essentially be exhausted. Now with pushing back Sundance Sea to the balancing pool, our inventory is gonna last all the way through to the end of twenty twenty. So what that has done is is reduced our cost of compliance materially from what we anticipated last year because we no longer have the obligation of the Sundance CPPA. So one of the areas that, of course, we're tracking year over year, And we like seeing these bars with multiple colors on it. But I think it is a powerful representation of how much we've increased our contracted EBITDA as an organization since 2020.
And of course, with the completion of the Balloon wind project next year, that will continue that trend. So switching to our hedging activities in Alberta. Mark gave you a flavor of how we've performed historically in the Alberta market just to provide a little bit more detail as we look forward at the next three years. So in 2017, we've sold forward actually a little over 100% of our base load generation into the Alberta market at a contract price in the mid $40 range. Average forward prices right now are trading about $32 In Alberta, we've seen a little bit of recovery in those forward prices given the record demand we had in the last couple of weeks in Alberta due to the cold weather.
So that was certainly a good sign. And one of the things we are seeing in the Alberta market is a return to positive demand growth the last couple of months. So certainly, from a electricity demand perspective, we've seen things turn the corner. When we look forward to 2018, 2019, 2018 were percentage sold forward of 52%. Some of you recall that this number hasn't changed a lot over the past six months.
And there's two things I'd like to comment on there. The first one is, as we've gone through 2016, Shepard has been running more as a base load unit as opposed to a mid merit unit. A lot of that's given where natural gas prices are at. So what we've done is now we used to only include minimum stable generation as part of our base load portfolio. Now we include the entire output.
So what that does is it increases the size of denominator and push down the percentage, which we have offset with additional hedges. But the other thing that we want to keep in mind is the forward price of $39 For us, from a trading perspective, it's always based on us looking at our fundamental expectations for the year versus where the forwards are trading. And right now, that $39 price from our perspective is on the low side, and we would expect some recovery there. So another metric we track closely is our coverage by long term contracted cash flow to our financial obligations. So just as a refresher here, in 2017, that bottom line is the percentage coverage of our long term contracted cash flow, which would include all our assets outside Alberta that are on long term PPAs, but also our twenty year contract tolling arrangement off of Shepherd as well as our twenty year contract on Rex off of Helcirk.
When we take that contracted cash flow and look at it, we compare it to our overall financial obligations. So preferred and common dividends, debt servicing, all our fixed O and M, all our maintenance sustaining CapEx, so all our financial obligations. And we can see now in 2017, we're now heading into a period where we've got approximately 115% coverage. As opposed to before, it was 95% to 100%. And that lift has come from the fact that we have 52,400,000.0 of contracted cash flow now coming in the form of compensation payment.
So certainly, very much very powerful in terms of supporting that contracted coverage. Now when we look forward out to 2019, what that now means is that margin we're making off of sales from our merchant facilities in the Alberta market over the next three years, that margin will be solely needed just to go towards growth. We won't need it to manage any of our financial obligations. So I'll just recap quickly terms of the dividend growth story with Capital Power. So in July, we announced our third increase in the dividend of 7%.
So consecutive increases of seven percent over three years. Now when we look at how 2017 and 2018 are shaping up, of course, it's subject to always maintaining a look at what's happening in the environment, what's happening with our operations and subject to Board approval. But when we look at it in the strengthening of that contracted coverage and what we see in terms of adjusted funds from operations, we don't see any reason why we wouldn't continue that dividend increase through 2018. Beyond 2019 is something we'll be looking at and assessing as we move forward. And part of that, of course, is going to be looking at those projects that Mark referred to actually crystallizing and taking shape to support the dividend strategy beyond 2018.
So I'll wrap up with just a comparison to our peers. Feel these graphs these two graphs are very instructive to the Capital Power story. The first one shows a breakdown of AFFO yield relative to our current share price. And basically, when you look at the AFFO, we're projecting or giving guidance on for 2017 relative to share price, that's about a 16% yield. Exceptionally strong.
But also important to note is that the dividend yield at 6.8% is the second highest of our peers. Again, suggesting very good value from that perspective. When we look at it on an AFFO payout ratio, we're sort of, as I've mentioned, in that mid 40% range, which again is materially below what the average would be of our competitors, which is or our peers, which is 58%. So certainly very strong from a cash flow perspective as we look forward. So with that, I'll turn it back to Brian to wrap things up.
Thank you very much, Brian. I will close out the formal part of our presentation this morning by identifying our twenty seventeen targets. As most of you know, we identify our annual targets during our Investor Day and report back on them on every quarter as to the progress we're making towards those targets. In terms of our operating priorities, our target for plant availability is 95%, and that's both capital power operated facilities and the facilities that we have an interest in that are operated by others. Our maintenance capital is $85,000,000 As Darcy mentioned and Brian mentioned, this is higher in 2017 in large measure because of $10,000,000 we're investing in the Genesee performance standards.
Lastly, our target plant operating and maintenance expense is in the range of $195,000,000 to $215,000,000 In terms of our growth perspective for 2017, certainly deliver Bloom project on time and on budget or hopefully earlier and under budget. Execute two long term PPAs for new contracted facilities. And again, those PPAs in support of new builds. Continue to build development pipelines in Alberta and The United States. Our key financial measure is adjusted funds from operations, as Brian has just described.
Our range for 2017 is $3.00 5,000,000 to $345,000,000 in comparison to our midpoint for this year of $320,000,000 So in terms of summarizing what you've heard this morning, in terms of 2016, our performance has been very good, particularly under an Alberta power price environment that has not been constructive. We resolved the outstanding issues with the Alberta government on what we see as a very favorable basis. In 2017, despite the operating performance improvements that we've been talking about, our expectations financially is we'll end up similar to 2016. In 2017, we will more actively manage and mitigate our net carbon position, which I think over time you'll see will be more and more significant to the capital power story and our bottom line. We'll continue to work with the government of Alberta to define a capacity market that works very well for incumbents.
In the longer term, we are very well positioned in Alberta with our existing assets. Our plants are very competitive as coal units and will be competitive as natural gas units. A move to capacity markets improves the outlook for both our existing coal facilities and the transition to natural gas plants. Genesee 4 And 5 continue to be continues to be the leading option for new baseload generation in Alberta as needed. And we have excellent short and long term renewable opportunities in Alberta as announced this morning and with the further announcements we expect over the next few months.
In The U. S, we are making great strides in our competitiveness and an additional wind project should be announced within the next month or so. These current and future growth initiatives are well supported by our financial strength and supports further dividend growth. In summary, we are executing well on virtually every aspect of our business. Thank you very much, and I'll now turn it over to Randy for questions.
Okay. Thanks, Brian. For the benefit of the people listening on the webcast, if you can use the microphone when asking your question and also identify yourself before asking the question. Kate, we're ready to start.
Hi. It's Ben Pham, BMO Capital Markets. I'm just wondering on your your dividend expectations for next year. If you did not receive compensation, would you have still reiterated your guidance? Because it seems like your FFO is declining if you're excluding that compensation amount.
Yes. I think that's really good question, Ben. If we take a look at what our payout ratio would have been without the compensation, we would have still been below that average of our peers at 58%. So we would expect we would have still moved forward with the increase.
Okay. And then you mentioned with RP in Alberta potential strategic partnership. I'm just wondering what benefit do you think that would provide to you guys? Is more cost of capital or access to sites that you don't already own?
Probably a a little bit of all of the above. Some of the individuals or or entities that we're speaking with do have a collection of sites. Some are smaller that could be helpful for us to join forces in terms of capacity to build things. Some are more pure developers that would be looking for their construction expertise. So it's a whole gambit that we're having these discussions with.
And some of the more strategic ones are giving us the potential for larger access to larger land masses and very good wind resources that we find very attractive. So we're we're following up on those conversations as well.
Rob Hope, Scotiabank. Just want to know if you're in discussions with the Alberta government regarding your carbon offset inventory and just to ensure that offsets under the SGER would still be valid under a clean power plan?
So maybe I can answer that. The discussions that have taken place historically has been that the carbon offsets that have been accumulated in those carbon offsets that are, you know, on the books of of many companies in in Alberta will be recognized on a go forward basis without restriction. Now that hasn't there hasn't been new discussions on that. That issue hasn't come up again, but we see no reason why they wouldn't continue to be fully valid carbon offsets. The protocols on which they are generated continue to be valid protocols.
One of the things that you can expect in Alberta and across Canada is a greater diligence in terms of defining what a carbon credit is. And under the, I'll call it, more diligent criteria, those the carbon credits we have would continue to be valid.
All right. Thank you. And just as a follow-up, you you mentioned that we're seeing positive demand growth once again in Alberta and that you're maintaining G4 and G5 as a shovel ready project. When in your view, when do you see the need for that new capacity entering the market there?
So I think as was illustrated on March chart on where power costs are going and the convergence of both the capacity market and the energy only market, so that pretty much signals when there's a need for potentially new capacity in the market. Again, that's we'll have to also see how the capacity market timing and bidding process comes into play because, of course, that's very significant. And certainly with the timing that's being identified, there really isn't an opportunity to bid and build, because you've only got sort of a one year window. So again, there's a lot of details to be worked out over the next little while. But certainly, if there is a demand for capacity in the market, the way in which the capacity market timing will evolve will certainly provide for an opportunity for a project like Genesee four to participate.
Pat Kenny, National Bank. Just on Page 67 here, looking at the AFFO charts. Can you give us a sense how much of the cash flow has been trading contributions over the last few years? And I guess how should we think about your trading contributions post-twenty twenty one under a capacity market with less volatility? Maybe putting another way, what's your expectation relative to your track record of achieving 13% above the spot?
So I'll start, and then Mark may add to the response. When we look at 2016, we would have built in trading gains of probably around approximately EUR 15,000,000 to EUR 20,000,000. Now one of the things to keep in mind is, of course, when we provide our guidance, we take into account the value of our positions at that point in time. So some of the strong performance that you've seen this year from the trading side was actually crystallized well in advance of 2016. But on a year over year basis, we look relative to add about CHF 20,000,000 from the trading.
I don't disagree that the reduced volatility will dampen some of the opportunity around that. But I think as Mark pointed out, there's still going to be an opportunity to realize a good portion of that under the new market design.
And I might add, a new market design and with the capacity market, there's really going to be two bidding strategies that are going to start coming out. There's going to be, of course, the capacity bid itself and how we want to position ourselves and what sort of margin will be created and where we appear in the stack. And then there will be the ongoing daily bidding that will be required in terms of pricing the energy itself. So I still think there's going to be quite a value associated with that skill set that our guys possess in knowing the market and knowing where we need to bid in at.
And maybe just one follow-up, Slide 25 on the GPS program there. Can you give us a sense as to what your expectation is from an emission standpoint? What do you expect your tonnes per megawatt hour to drive down to?
I think just a simplistic response is is, you know, we're targeting, depending on the unit, between 1011% reduction of of CO two emissions per unit. It's in that magnitude.
Andrew Kuske, Credit Suisse. Since we're in the negotiation phase of the capacity markets and really for the next two years that will go on before we go live, how do you think about what's best for capital power? What attributes of the capacity market is? When when we think about capacity markets, there's all sorts of different market structures around the world. There's some similarities, but there's a lot of differences.
So what are the key things you'll be negotiating for with the government?
So the when you look at a capacity market versus an energy only market, you know, the real difference is that, you know, the the actual revenue that's generated is is in two components. When one of the significant elements when we looked at going to any market, and as I commented earlier, we've been a strong advocate of the energy only market historically. And the reason for that isn't that that's necessarily the best market for capital power and the way our business is. The reason for that is the road to whatever is a new market may and in most cases, if you look at Ontario or if you look at California and other markets that have evolved, it's been horrendous for incumbents. With the commitments that the Alberta government has made and as we see it, the introduction of an underlying capacity market has some significant benefits.
Those benefits are around a more predictable cash flow to a degree. I mean, still is a merchant market. Still the bulk of your revenues will be coming from the energy side. The issue around volatility is quite interesting because you end up with a bit of a different volatility because you're also introducing a lot of renewables. So overall magnitude of changes from year to year are not necessarily there, but certainly daily volatility continues will continue to be fairly strong.
So the long and the short of it is, you know, when we look at the evolution to a capacity market, if it's a level playing field, if existing generation is treated equally to new generation coming into the market, we think that that's sufficient for capital power. And again, at the end of the trail, we believe that probably on balance, capacity market is better for capital power given the environmental directions of the province than an energy only market might have been.
And then maybe just a follow-up on that. How do you think about the new market construct affecting you from an operational standpoint and how you position yourself operationally? And then just some of the how the competitive behaviors may change. And you know, one classic example of capacity markets is you wind up with antiquated equipment that just sort of lives forever, but never really runs that often.
Right. I mean, there's a lot of interesting dynamics that can unfold. Certainly, as you say, and we've seen it in other markets where equipment that should have died didn't because there's enough in a capacity payment to keep doors open. With a coal plant, it's a little bit different because you have a significant amount of fixed costs. Unlike a gas facility where you have 500 megawatts and 25 employees for a coal plant of the same size, you've got hundreds of employees and significant maintenance.
So you'd expect the pressures for, as I say, around a coal plant to probably convert ore to die a lot sooner under that kind of a market condition. When you look forward to the elements of conversion, which is going to be the large issue in the Alberta market, is what plants convert. As Darcy, I think, you know, actually I was going to say alluded to, but he didn't allude to. He made the very strong point. If you have a very good coal plant, very efficient, relatively low maintenance, it will translate into the same kind of plant on a converted gas basis.
It will be as efficient in the stack. And what that drives us to is to say, we've been on a track of significantly improving the performance of our units. We'll continue to do the same. And one of the things that was maybe not brought out in terms of these improvements from a carbon perspective is those are also improvements to the efficiency of the plant. Basically, it improves your heat rate.
And those will apply to natural gas as well. So not only do we see properly maintaining the plants and improving the plants excellent from a coal perspective, they will, you know, shine through as well when those plants are converted to natural gas. So our approach to plants is going to continue to be the same.
David Quezada from Raymond James. Just wondering on the coal to gas conversions, if you could provide a little color there, what the process is going to be like, capital costs and the time line for those projects?
Yes. So I think it's in the slides. I didn't talk about it. But just a simple conversion would I think we've said for our units, and we don't envision much rebuild in our units, it's really just changing the burners. And so we're saying for us, it's the 25,000,000 to 50,000,000.
And the reason there's that spread is really just on the NOx side. We're not sure of the NOx requirements. So if it's a low NOx requirement, we'll be buying more expensive burners. But it's a very simple conversion. It would we would estimate it would take something like eighteen months or so or sixteen months.
And there would really it didn't entail probably just an outage of maybe two months duration to actually make the switch. But it's a very, very simple process to convert. That is just a simple conversion. There's other types of gas conversions, but we're not talking about that here today.
Great. Thanks. And would you be contemplating going ahead with that towards the 2030 timeline? Or is there any potential to do that earlier?
Yes. I think what Brian and Mark both spoke to is that with the price of carbon as we know it today at $30 it just makes sense for us because of our high efficiency fleet of coal fleet. We it just makes total sense for us to continue to run on coal to 2030 and then do the conversion at 2,030. Now circumstances could change. The price of carbon could change, etcetera.
But but right now, that's our best guess going forward, and that's how we're planning.
Great. Thank you.
Just a quick question on new gas. How are you thinking? I mean, previously, before the new rules came out, you're you're pretty optimistic on new gas CCGT. What are you thinking now versus renewables, I'd say?
So in so speaking from an Alberta perspective, certainly we think there's probably an expectation of the government or desire of the government. And it does make a tremendous amount of sense if you end up in a situation where you have rapidly changing environmental regulations. And I think as many of you have seen, some of the federal government scenarios on low carbon futures result in natural gas plants having a potentially a relatively short life if you build one in, say, 02/1930. So as we look at that, probably the lower risk for investors would probably be converting to natural gas. Certainly, if you build a new natural gas plant, say, in 2021 or 2022, there's definitely a lot of runway there to achieve the economics that you've gone in with.
When it starts getting to February and '30, and that starts getting to be a little bit more dicey from our perspective. So we certainly see in Alberta, new natural gas as a place early, but probably not later. When you look at it from a North American perspective, there's still a need and you're seeing, you know, a more definite switch towards peaking type facilities and less large generation that's taking place outside of the utility, the major utilities. So don't see a lot of necessarily opportunity for large scale natural gas generation. But again, there's still peaking plant opportunities throughout much of The U.
S. Markets.
So I'll just add one just technical point to it to add to Brian's comments. And that's just with the simple gas conversion, it doesn't give you the ramping capability that a new combined cycle unit would give. And so a lot will depend on what the market needs are as well. And that's why it still makes sense for us to have that G4, G5 option available. Know, converting the gas units as we just or the coal units, as I spoke to a few minutes ago, that's a you know, it will have a better ramping capability, but it's still quasi base load is it's optimum.
And combined cycle G4 type unit is much, much different in terms of its dispatch capability.
Robert Kwan, RBC. Just to follow on that question to start, have you done the calculations you looked at g four, g five, what net cone might look like for the Alberta market?
Sorry, Robert. Could you repeat that, please?
Just when you look at your G4, G5 and the capacity markets to go forward, have you looked at what the net cost of new entry might be in with respect to how the capacity market might function going forward?
Well, I think, you know, as the charts were somewhat indicating, you end up, you know, almost an indifference as to whether you're in an energy only market or a capacity market in terms of the signal of when you need new generation. And again, the projections that we put up here are somewhat indicating in the 2021 time frame, 2022. And essentially, as you bid into capacity market, say, with something like Genesee four or five, what you'd be doing is looking at the revenue that you would expect to be getting from the energy side. And then out of your total requirement, which is, you know, generally speaking, in the $60.65 dollar range, you know, you would then layer in or establish what you'd need as a capacity payment for whatever that time period is, whether it's three years or four years or five years, whatever the duration of the capacity call is. So the decision isn't is still largely hinged on what makes sense in the marketplace as to whether or not you would invest.
Again, if there was a the government felt that there was a strong need for new capacity in, say, 2021 or 2022, they'd be signaling that and we'd be participating in whatever that process would be. But we do see that there is a need for additional capacity sometime in the early part of the next decade and would expect Genesee four to be definitely a front running candidate for that.
And as you think about the capacity market going forward, not having the rules yet, you're pursuing a number of wind projects at this point. Do you have any concerns about bumping up against any seller side mitigation in the capacity market?
Not really because what's happening is we had been again, assuming an energy only market, have been promoting the rec approach. The way the government's going is it'll be essentially CFD approach or essentially, they'll your revenue will be guaranteed. There is some changes that may be taking place in the transmission side of the business that we'll be keeping an eye on. But those changes, we had expected that probably, if any, that impact on the economics of any renewables would likely be covered by things like changes in law provisions. So basically, signing participating in the rec process in in Alberta, we'd see as the same as participating in BC or Ontario and so on that, you know, generally speaking, you're guaranteed your revenue.
And and, again, there'll be things over time that that have to be dealt with around the edges, but there won't be anything fundamentally at risk in going into at least as we expect, going into the first rep process in Alberta.
Okay. If I can just ask one last question. You're projecting an AFFO yield of kind of in that 15% range. Have you and it sounds like as you go forward that you're seeing stability and growth in AFFO. So I'm just wondering, have you given thought, unless you've got these development projects with an AFFO yield of greater than 15%, allocating the capital to investing in your existing capacity and just buying back stock?
Maybe, Robert, you could sort of expand and invest you mean in terms of share buybacks?
Yes. So if your shares are at
a 15% AFFO yield, unless your new projects are greater than that.
Well, I think there's one of the other elements that's at play is we do want to increase that mix of contracted cash flow. And certainly, that comes from an investment in the types of projects that Mark described. So certainly, that we're in a transition where we're reducing the merchant cash flow to a higher percentage of contracted, typically has to come from the growth side.
Rob Catellier, CIBC. I wondered if you could go back to your comments about diversification and partnering. Is the partnering comment really to do with new projects in Alberta? Or is there a legitimate chance to sell down some of your position in Alberta and use that as a way of diversifying?
So the way we're looking at right now is not so much as a source of raising capital, but rather relationships that allow us to deploy additional capital. And if these partnerships can give us access to more sites, give us risk sharing capabilities, or give us other strategic advantages where we can combine our competencies with a partner's competency. It's those sort of things that if we can improve the overall approach and improve our competitiveness, improve our probability of success is really what we're trying to do. At this juncture, it's not really looking to monetize a selection of our assets into a joint venture. It's more about deploying capital, not raising.
You've chosen to safe harbor some some projects and PTCs through the use of transformers. So we've seen this approach usually through turbines. Can you elaborate a little bit on that choice? And how many megawatts have been safe harbored? And what's the related capital project project capital?
So at a very high level, I guess, a series of questions. One, the choice of transformers was because of some specific language in the code that identified the commitment to transformers would qualify as the start of construction. Hence, that led to the selection of that. We chose seven transformers as it relate to many of the sites that are reviewed earlier today. And those transformers have the capacity that is applicable to to those those sites.
You know, and I guess the view would be over the next four years, we are very bullish that all of those sites will go forward in one form or another so that that equipment will be absolutely required. The use of trying to safe harbor with turbines, frankly, was probably just more of a larger capital outlay than the transformer selection that we've made.
So I'll just add a couple of things, just specifics. I mean this is about USD 10,000,000 type allocation of purchase. And just on megawatts, it's in that 800 to maybe 1,000 megawatts of potential. So we think that's a very good bet for us. And we're very confident that we can compete on those sites.
I think the other thing to point out, and we've been in the position before of having turbines that have flexibility as where they get placed in contractual arrangements around how prices get lowered with greater turbine use, etcetera. When you look at those arrangements, you're basically putting a pin in your technology and you're putting a pin in a number of other different parameters that in our view, as time moves forward, over the next four years, we'll be in a much better position and we'll get a much better cost response and performance response from contractors and from turbine manufacturers as we have real projects and as we have, I'll call it a larger portfolio of projects to be under construction. So we think you're not going to save a whole bunch or you're not going to gain any cost advantage around transformers, but you can create a significant cost advantage for yourself by negotiating for turbines later in the process. So we would putting capital dollars aside, we think this is this probably leads to a longer term lower cost of projects.
And my final question has to do with the balancing pool. Any any idea what what they might do with the PPAs?
I think at this point I mean, we, of course, hear lots of different rumors and lots of things going on. And I would say that, you know, right now, it's pretty uncertain. It's quite uncertain as to as to what the balancing pool is going to do. They're positioning themselves to do, you know, a whole range of different things. So, again, uncertain and, you know, hopefully, we'll see some clarity around that within the first quarter of next year.
Hi. Just the the US dollar private placement, has that been swapped back?
Sorry. Repeat the question.
The US dollar private placement that you spoke about, first of all, the $160,000,000, is that US dollar or Canadian dollar?
That would be Canadian dollars.
So has it been swapped back?
No. It's it's the deal was done in Canadian dollars.
Okay. So the 3.85 is your is your Canadian dollar cost? Is it US dollar it was originally US dollar debt?
No. Actually, so it was placed there there there it's being landed as Canadian dollars.
Okay. And then you have about a billion of liquidity, of additional liquidity. Is that is that been kind of state like, kinda normal for the last since you've existed? I'm just wondering why it's so high.
Well, actually, was higher. And one of the things we did about a year ago is when we did the previous extension is we actually reduced it from about $1.3 down to $1,000,000,000 And the size of it really is just gauging how much we're going to have under development in terms of we need that access to short term financing. And at 1,300,000,000.0 we felt that was a bit higher than we needed. So in order to reduce the cost, we reduced it to 1,000,000,000
Andrew Kuske, Credit Suisse. Just back on market design and market structure. So for the next, I think it's four years, the government's capped retail at 6.8 percent. We've seen that strategy used in other jurisdictions around the world, and some of it didn't work out so well, some of it worked out okay. If you just maybe give us your thoughts on what that means from a power generation standpoint.
Have have they thought out all the options, or is this really just a political action to lessen the volatility on at least very least a perceptual basis, but also maybe a real basis for retail?
You know, maybe to answer that from the perspective, so not to comment on the political side of it, but when you look at what the actual impact is, they've established a cap with a view of subsidizing amounts around that as opposed to putting per se an absolute cap. And what that does is that impacts on the retail side, but it doesn't impact on the wholesale side. So again, it impact on the appetite for people to be taking contracts and there to be that kind of increased contract length in the marketplace. But other than that sort of secondary impact, it it should not have an impact on, you know, the the spot price of power in the province.
And then maybe just a follow-up. What kind of inbounds have you had from industrials since we've had greater clarity in the last month or so? Has there been any change in activity level and just dialogue?
Not significantly. I mean our guys continue to be very active in those relationships. Those that want to hedge, we continue to have those discussions and look to secure longer term arrangements. There are some with the spot price where it's at, have been comfortable taking more exposure in the near term. We would expect as prices start to recover, then we'll probably see that activity come back at us, those that are trying to minimize their cost going forward.
But the activity level has been similar to what we've seen for the last little while.
Maybe a bit of a, excuse me, broader macro question. But with respect to the balancing pool, how do you see their mandate evolving, if at all? And I guess this is all part of the mix. And what sort of criteria beyond just pure cost to consumers and taxpayers do you think they'll consider when they weigh on the merits of holding on to PPAs versus canceling them outright?
You know, to and, you know, there's there's obviously been some changing legislation and enable and enablement and so on around the balancing pool. I I think, ultimately, what what would end up happening is they will be enabled to do whatever essentially they're directed by the government. And, you know, that decision as to whether to hold on to the PPAs or which ones to to move on or to push back to the owners and so on. Certainly, the balancing pool, I
wouldn't
expect would have a view and there'd be some discussions. But, ultimately, I would suspect that it it is a a government response. And, you know, whatever is necessary to to do that would end up you know, the government would ensure the enablement of it.
And just as a follow-up, do you think that they would kind of look at various cost considerations primarily? Or do you think there there'd be some kind of equitable allocation maybe of cancellations across various players? Or
Well, the, you know, the the the basic fundamentals continue to be the same. Some of those plants, given the PPA's structure, makes sense for them for the lowest cost resolution for, I'll call it Albertans, is to push them back to the plant owners. Others, it makes no sense. Like, for example, Genesee, you know, one and two, the cost to put the PPA or put those plants back to us is huge because it's based on net book value. So, you know, don't see that the the that the government would be taking actions that would significantly increase the cost to to Albertans.
You know, one of the things where the PPAs are today and is a little bit lost in the narrative is the fact that, you know, the the balancing pool holding them and dispatching them the way they are or the way they're being dispatched results in lower power prices in the province. So there's, you know, tremendous benefits to consumers. But again, that gets lost in the narrative and people are looking at, you know, pennies as opposed to the dollars that that are there. And not so sure whether the government may, you know, recognize and and they do know it, but but recognize that benefit and maybe hold on to them for longer than they otherwise might have just from from a purely pure perspective of the balancing pool decision. So there's a lot at play in in what might evolve there.
Any other questions? One in the back.
Thank you. Can you just talk about your appetite to raise equity? Just thinking in terms of as you diversify into more contracted production, Do you see your cost of capital at your 16% AFFO yield? And should we expect some dilution there as you diversify?
Certainly, there's a lot of headroom we have in terms of our discretionary cash flow right now to support growth CapEx. And as you saw on the charts, we're looking at €20,000,000 in 2017 without having to go to the capital market. So certainly, those investments will be by definition accretive. When we look at opportunities that are bigger and may require us to access the equity market, we certainly would we're going to be very mindful of the implications from accretion or dilution perspective. And those are some of the metrics that we look at.
But at this point in time, we wouldn't expect that, that growth will be so rapid as to we would be causing dilution by a lot of accessing the equity markets multiple times.
Just back to your pipeline of growth opportunities for both wind and solar in Alberta. I know more details are still to come here, but can you just give us a sense maybe as a rough ballpark number of potential megawatts outside of Alkirk II and Whitla as well, just on the wind side and then on solar as well.
So it's a rough ballpark, if you will. When I think about Alcirca and Whitla right now combined, that's about four fifty megawatts. We do know that the overall renewable build over the next fifteen is targeted at 5,000 megawatts. To the extent we can be in a position to be targeting, you know, a series of those over the next three, four years, a 150 megawatts in size so that we can participate in each, you know, that that would be preferable. But we, of course, got to balance that with the cost to maintain those options, the cost to carry and the nature of the the arrangements that we're getting into.
You know, I I think as Brian has already pointed out as well, we're continuing to be very cognizant of how the market is going to unfold and what these auctions are going to look like. That will also inform how aggressive or not we want to be in securing additional sites to bid into this marketplace. But directionally, would think if we could get to 500 to 1,000 megawatts of options for us, that would be preferable, again, depending upon the cost.
Thanks. And maybe just for Brian, as you pursue these opportunities, would you are you going to continue to go it alone? Or would you consider bringing in a financial player with perhaps a lower cost of capital?
So certainly, we have to look at how competitive are we going to be in the landscape. And certainly, with what the first couple renewable opportunities are going to look like in Alberta, being that essentially your revenue is guaranteed, that will attract a lot of players with relatively low cost of capital. Our approach to that obviously is to be very effective in terms of keeping our costs associated with the wind turbines, etcetera, to be quite low. In addition to that, execution on the construction side. But a real key, and we talked about this a couple of years ago, is the value of
a
site. And the value of the sites today in Alberta are associated with the you need to essentially be able to just plug them in without any, you know, transmission additional transmission costs. And both Whitla and Helkirk are are in that vein. And on top of that, it's gotta be, again, really low cost and ready to construct. So that eliminates in the first couple rounds probably a fair amount of potential going forward.
One of the things that's going to happen in the end, so in terms of partnering, we will seriously look at how competitive we think we are. And if we believe that our cost of capital may not be competitive, we would look to partner to ensure that the projects are competitive. So I think that goes without saying. And I think Mark was commenting about our willingness to bid with others and participate with others that bring significant value. One of the other things and maybe a little bit more squishy going forward, but represents definitely a perspective around partnerships is that there's gonna be, as time passes, and this may be sooner rather than later, you know, the Alberta government will start including consideration of, you know, local benefits, local partners, First Nations participation, and those.
So, you know, we would absolutely expect that in time we will have those kinds of relationships and partnerships as part of the bid on any renewable project. So, you know, you'll see in Alberta, and I think you're seeing it, you know, everywhere, an increasing need for broader participation, and, know, we're definitely gonna be responding to that.
I think Alberta hit a new peak last week. Can you just talk about whether that's a change in shift? Like what's happening behind the fence? Is it are they drawing more from the grid? Or is that true demand?
Can you just talk about that generally?
Yes. So that would be true demand in the Alberta market. So there hasn't really been much change in terms of behind the fence generation and the magnitude of it. So I think our record previously was about November and we hit 11/1940.
Any other questions? If not, I'll turn it over to Brian for closing comments.
Well, thank you very much for your interest in Capital Power and for joining us this morning. We certainly continue to be in a bit of a world that's evolving, particularly in the Alberta market. And in contrast to where we were last year, where we're talking about a lot of things that we hope would evolve and the issues of compensation. Certainly, PPA issue was starting to bubble a little bit, but certainly didn't take on the stature that it did through 2016. But as we look forward, we're seeing increasing clarity in the Alberta market.
We're seeing an Alberta market that is definitely positive from a capital power perspective, both in terms of what we can do with our existing assets. And maybe just on that point and maybe to tease you a little bit, we're hoping that by the time we're talking to you next year, it's you can simply convert to natural gas, but there's a lot more to an overall strategy and how you'd approach it and other elements that you can bring to that, that again, next year we hope to be able to talk to you about in a little bit more depth. But you can see that there's a continuing strong focus and although we've had this focus definitely last year, an increasing visibility of our focus on developing projects, particularly renewable projects in Alberta and certainly in The US. And so our outlook has changed in terms of certainty. And from our perspective, it has increased and uncertainty by definition has decreased.
But you're seeing the organization continue to do what it's been doing. And again, in some respects, a little bit of a different focus. But applying the same competencies, the same approaches to increasing our business and moving forward from a financially responsible perspective. So again, hopefully next year, we'll have some additional exciting news for you and approaches and conversation around the evolving market and what it's meaning to us and what some of the actions are that we're going to be taking. And would invite you all at any point that and again, there's going to be a lot of noise and a lot of news and a lot of people creating news that isn't news and so on and so forth in our market, in our Alberta market over the next year or so.
But I'd invite you to call us at any time for our take on it and our perspective on it. You can certainly expect us to be very involved in the discussions and looking for fundamentally good, strong markets to prevail and once again that are very constructive from an incumbent perspective. So, again, thank you very much for joining us this morning. And to all of you, have a very happy and safe holiday season. Thank you.