Capital Power Corporation

Randy Mah - Senior Manager, Investor Relations Brian Vaasjo - President and CEO Stuart Lee - Senior Vice President and CFO

Ben Pham - BMO Capital Markets Linda Ezergailis - TD Newcrest Paul Lechem - CIBC World Markets Andrew Kuske - Credit Suisse Robert Kwan - RBC Capital Markets

Good morning. Thank you for joining us today to review Capital Power’s first quarter 2015 results, which were released on April 24, 2015.

The financial results and the presentation slides for this conference call are posted on our website at www.capitalpower.com. We will start the call with opening comments from Brian Vaasjo, President and CEO; and Stuart Lee, Senior Vice President and CFO.

After our opening remarks, we will open up the lines to take your questions. Before we start, I would like to remind listeners that certain statements about future events made on this conference call are forward-looking in nature and are based on certain assumptions and analysis made by the company.

Actual results may differ materially from the company’s expectations due to various material risks and uncertainties associated with our business. Please refer to the cautionary statement on forward-looking information on slide two.

In today’s presentation, we will be referring to various non-GAAP financial measures as noted on slide three. These measures are not defined financial measures according to GAAP and do not have standardized meanings described by GAAP, and therefore are unlikely to be comparable to similar measures used by other enterprises.

Reconciliations of these non-GAAP financial measures can be found in the Management’s Discussion and Analysis for Q1 2015. I’ll now turn the call over to Brian for his remarks starting on slide four.

Thanks, Randy, and good morning. Last month, the Shepard Energy Centre officially began commercial operations.

The facility is now able to generate its full capacity of over 800 megawatts for delivery into the Alberta power market. I want to acknowledge the excellent work of our joint venture partner ENMAX, who led the successful construction of the facility.

Final construction costs are expected to not exceed $854 million, which includes an accrued performance bonus to the turbine manufacturer based on final facility performance measurements related to electrical output and heat rate. The higher performance measurements are expected to improve the overall economics of the project and are more than offset the additional capital costs from the performance bonus.

Turning to slide five, our Board of Directors had approved the construction of the Beaufort Solar project in North Carolina, which is Capital Power’s first solar project. This 15-megawatt project was part of the portfolio wind and solar development sites from our acquisition of Element Power last December.

It is a fully contracted facility with a 15-year PPA with Duke Energy. We will begin construction shortly with commercial operations targeted for December of this year.

This project has its sale leaseback arrangements where we would sell their asset to a tax equity investor when solar project begins commercial operations in exchange for lease payments. Slide six summarizes the plant availability operating performance of our plants for the first quarter of 2015, compared to the same period a year ago.

Overall, we had a strong operating performance across the fleet with an average plant availability of 98%, compared to 94% in the first quarter of 2014. The strong first quarter operating results benefited from minimal unplanned outages and a deferral of short-term planned outages to the second quarter.

I will now turn the call over to Stuart.

Thanks, Brian. I’ll start my comments on slide seven.

The recent $225 million Secondary Offering of Capital Power shares by EPCOR, their ownership position in Capital Power L.P. was reduced to 9% from 18%.

On the April 2nd closing date, EPCOR also exchanged its remaining CPLP units to common shares on a 1 for 1 basis and effectively transitioned into one of Capital Power’s largest institutional shareholders. The decrease in ownership resulted in the termination of the registration rates agreement, meaning Capital Power is no longer obligated to assist EPCOR in making secondary offering under a prospectus.

EPCOR has advised it plans to eventually sell all or a substantial portion of its remaining interest subject to market conditions and requirements for capital. With EPCOR no longer holding CPLP units, we will be reviewing the CPLP structure with the goal of simplifying the organizational structure and reporting, and reducing costs associated with CPLP entity.

Turning to slide eight, Capital Power is generating strong contracted cash flows and with minimal committed growth CapEx, our capital allocation decisions have based on the following three options. The first priority is dividend growth.

We have robust contracted cash flow and a base to support of a continuing to increase the dividend. Second is growth opportunities.

In order to increase long-term contracted cash flow and cash flow in general over time and to be able to support a growing dividend, we need continue to expand our asset base and then third, looking at alternatives like debt reduction and share buybacks. We recently bought back $75 million in debt and will now look at share buybacks.

The TSX has approved our normal course issuer bid application to purchase up to 5 million common shares over one year period ending April 6, 2016. We’ve also suspended the DRIP, effective with the second quarter dividend payable this July.

I will now review our first quarter results, starting on slide nine. In the first quarter, the company generated $108 million in funds from operations, which was in line with our expectations.

Normalized EPS of $0.32 in the first quarter benefited from higher captured prices from the portfolio trading activities that were offset by lower settled prices for the Alberta commercial plants and the one-month delay from March to April on the effective date for the Shepard’s Energy Services Agreement. Despite a 52% decline in average Alberta power prices in the first quarter year-over-year, our trading desk captured 103% higher realized average price of $59 per megawatt hour versus the spot price of $29 per megawatt hour.

Turning to slide 10, I will review our first quarter 2015 financial performance, compared to the first quarter of 2014. Revenues were $358 million, up 16% from Q1 2014, primarily due to the impact of our portfolio optimization operations where revenue increase from $55 million to $160 million, reflecting the successful hedging program I referenced on the previous slide, with average realized prices of $30 above spot.

Adjusted EBITDA, before unrealized changes in fair values, was $116 million, up 9%. This increase was also attributable to portfolio optimization activities, which more than offset weakness in the plant dispatch level, in addition to a $5 million contribution from the U.S.

contracted segment and a small decrease in the corporate segment. Normalized earnings per share of $0.32 was flat year-over-year.

As I highlighted earlier, funds from operation of $108 million were in line with our expectations for the quarter and up 17% year-over-year. Overall, we had a positive year-over-year financial results, despite weak Alberta power prices.

I will conclude my comments with our financial outlook on slide 11. Due to a significant decline in global oil prices, it is expected to lower both economic and power demand growth in Alberta, along with lower forward natural gas prices for 2015.

Alberta power price forwards for the next couple of years have declined. The forward prices for 2015 are currently in the low $30 per megawatt hour range, which is lower than our original forecast assumption of $44 per megawatt hour.

However, at the beginning of this year, our Alberta baseload position for 2015 was significantly hedged in the mid-$50 per megawatt hour range. With the first quarter results in line with our expectations, there is no change to our revised funds from operations guidance.

We continue to expect 2015 FFO to be in the lower end of the $365 million to $450 million guidance range. Capital Power’s financial strength is based on the foundation of strong contracted cash flow, which is not impacted by fluctuations in Alberta’s power price outlook.

We remain confident in our credit rating and dividend growth outlook. I will now turn the call back to Brian.

The chart on slide 12, show our first quarter operational and financial results versus the 2015 annual targets. In the first quarter, average plant availability was 98%, which exceeded by 94% plant availability target for 2015.

Our sustaining CapEx was $6 million versus the $65 million annual target. We reported $41 million in plant operating and maintenance expense versus the $180 million to $200 million target.

Finally, we generated $108 million in funds from operations. Overall, we are on track to meet our 2015 annual operational and financial targets.

Turning to slide 13, we have two development and construction targets in 2015, relating to the K2 Wind project in Ontario and Genesee 4 and 5 here in Alberta. For the K2 Wind project, our goal is to be completed in construction and start commercial operations in the middle of this year.

For Genesee 4 and 5, the goal is to transition to the construction phase this year with a revised commercial operations start date in 2019. In conjunction with ENMAX, we have concluded that this is the earliest date that the Alberta market would need this additional generation.

Lastly, I’d like to comment on an executive rotation that we recently announced as noted on slide 14. Capital Power has an ongoing development program to build on the skills and knowledge of the leadership team.

Stuart who was currently Senior Vice President, Finance and CFO, will rotate with Bryan DeNeve who is currently Senior Vice President, Commercial Development and Commercial Services. The move will be effective on May 1, 2015.

I'll now turn the call back to Randy.

Thanks Brian. Peter, we’re ready to start the question-and-answer session.

Okay. Thank you.

And good morning, everybody. I just -- I want to go back to your commentary of Shepard and the change in economics.

And just wondering what is changing, is it the heat rate that’s coming lower than what you initially forecasted? I just want to get a bit more clarity on what’s changing that.

Sure, Ben. So still work to be done as far as confirming exactly what the positive benefits associated with both higher output and heat rate are, and so that work is ongoing.

But preliminary indications, our output is approximately 5% better than contractually required and heat rate about 1.5% better than contractually required. So positive, but again lots of works still to be done to confirm exactly those numbers.

Okay. And do you guys share that change EPCOR?

Is that mostly just looking at the merchant margins going forward?

So that’s with ENMAX?

Oh, ENMAX sorry?

And the overall economics for both parties would change reflecting that.

Okay. I just wanted to clarify on page 21, you highlighted $75 million for share buyback, are you looking at debt repayment and share buyback kind of in the same category when you talk about that $75 million?

So we have bought back already about $75 million worth of shares through the course of Q4 last year -- I am sorry debt through Q4 last year and Q1 this year. And I think consistent with the philosophy of looking at both sides of the balance sheet we will be looking at equity repurchases in a similar amount through the course of the balance of the year.

Okay. So it’s additive then, okay.

Thanks for that. That’s all for me.

Thank you. I am wondering if you can give us an update on seasonality or the timing of your turnaround this year, specifically G1 and K3.

And I don’t know if there is anything smaller plans for Q2 specifically.

So no change in timing, G1 is Q1 of this year and K3, we would be looking at into Q4.

Okay. And nothing else planned even on the mining level?

Nothing else major. There are some smaller turnarounds at some of the gas assets, but nothing that we quantify as major.

Okay. That’s very helpful.

And just a follow-up question on the quarter. Can you speak to the cost difference between how you address your CO2 credits?

I think in Q2 you dipped into your inventory, can you comment on how much cost you saved on that?

So if you look at prior year in 2014, we would have used SGER rate at $15 a ton and the cost associated that for the full year was about $3 million, and so a reduction this year associated with year-over-year basis by using our inventory associated with that.

Okay. So the inventory gets booked into the income statement at zero cost?

No, typically we end up buying those credits or some of it’s self-generated on average. Historically, the cost of those credits has been in the $10 to $11 range.

Right now, it’s a little bit higher than that. But historically, there has been a positive delta between buy those at and what the SGER costs are.

Okay. Great.

Thank you.

Thank you. Good morning.

I was wondering if you could give us some color around the hedging in 2016 and 2017. The contracted price have gone up from last reports from Q4 2016.

It’s gone from low 50s to now to, I believe, mid 50s. So next for 2017, it’s gone from mid 50s up to high 60s.

So can you say how you’re able to do that in such a depressed power price environment and what else you are seeing in the hedging outlook?

So for 2017, Paul, we would have -- again from our perspective, when we look at the forwards relative to our internal forecast, we look at particularly 2017 as forward has been significantly below where we think the market is likely to move. And so we stepped in and bought some 2017 power, which has overall moved up our balance of hedged prices due to buyback at relatively low prices.

And for 2016, it's a movement between periods, non-peak and off-peak and so not a significant movement but enough to tick it up a couple dollars.

Okay. Can you talk a little bit about -- you make some comments about potentially collapsing the CPLP structure.

Can you talk about what that would involve the timeframe to get there? What kind of savings you might be able to achieve if you do that?

So looking at couple different options associated, we’re trying to reduce the amount of extra reporting and some of the compliance costs associated with having effectively two public entities both at the CPC level on the equity side and CPLP on the debt side. And one option would be collapsing the structures altogether.

Another option might be trying to move the debt from CPLP level up to CPC and leaving the structure in place but reducing the reporting requirements. So we are looking at number of different options, not likely to see things before the end of the year, associated with the different options.

Potential cost savings would be kind of in the minimum dollar per year range associated with that.

Okay. And just lastly on -- now that EPCOR is down below 10% and they converted into common shares.

Is there any change to their call option on the debt that they have that option that they call it debt? Is that still -- does that still remain?

Yeah. There are no changes to the call option.

Okay. And how much debt do you have outstanding with that call right now?

I believe it’s about $335 million. And again from our perspective, if that was called early, we -- that would be positive for us front because we could have financed it at lower rates.

Got you.

But not something we’re necessarily expecting, given the fact that it’s back to back debt.

Got you. Okay.

Great. Thank you.

Thank you. Good morning.

I guess, maybe if you just give us some perspective on potential changes in customer behavior in Alberta just given what we’ve seen happen with the forward curve in the power markets. And obviously there’s a lot happening in the next few years, you’ve got some of the plants coming off of PPA.

You’ve tried to build some gas plants out into the future, gas prices are at really record lows at least in the last few years. So maybe just give us a sense of the conversations with the clients and how they’ve changed over the last 12 months or so?

So the -- when we look at the market and certainly with the discussions that we have with others generally reflect a higher degree of uncertainty particularly given where oil prices have gone. The issue is how long will the oil prices be at the existing levels and what will be the runway for them to move back to higher levels.

General expectations are that they are not going to be getting back to over $100 a barrel mark but more in $80, 80 plus dollar range. And the time frames for that vary depending on who you are speaking to.

Generally speaking the view is it should certainly be there in two plus years. Although more and more there’s discussions around how that kind of a recovery might happen sooner rather than later depending on global demand and what's happening around crude oil development and drilling on a worldwide basis.

So a lot of the discussion has very much circled around what’ll happen with oil prices and in particular its impact on Alberta. The other thing that we're seeing and is getting a bit of a higher profile is the fact that there's a fair amount of momentum in the Alberta economy.

So demand continues to go up for power. And for example, we’ve seen normalized growth in power demand in Alberta in their first quarter it’s been about 2% adjusted for weather.

So we are still seeing some -- again some robust growth in power demand. So it’ll be when the impact of lower oil prices meet with the momentum in the economy.

And if power prices have -- pardon me -- if oil prices have started to rebound and give confidence for some of the major projects that are being contemplated in the province, it maybe a relatively shallow impact on power prices. So that's generally where the broader conversations are.

Okay. That's very helpful.

And I guess related to that, do you think we are in a situation just overshoot to the downside now on power pricing? And then potentially setting up for as we’ve seen in the past cycles, some short moves to the upside in power where things get tighten get and squeezed very hard?

So our advice to the market has always been if you see significant downside, it's probably been overstated. In the same on the -- when you see forwards in power prices that shoot up relatively quickly and that tends to be overshooting as well.

Our view would continue to be the same that the market is overshot to downside.

Okay. That's very helpful.

Thank you.

Good morning. If I can just comeback and clarify in the 2017 hedges -- so the hedges you bought back effectively have you deferred the gain than into 2017 that gets the hedge price up?

Yeah. So we wouldn’t have recognized anything Robert.

Nothing in the quarter.

No. Nothing in the quarter and nothing in 2015 at this point.

Okay. Perfect.

And then I guess if we look at environmental, is there any update on CASA and the other thing we’re starting to see here is the potential for kind a sub federal framework here on carbon? So don't know if you have any thoughts on that may or may not unfold?

So there is certainly -- here in Alberta, there is a significant amount of momentum in terms of doing something more on the carbon side and certainly tied into that is CASA framework. There is ongoing discussions on an industry-wide basis.

And it's too early for us to comment or even to have a strong sense as to the direction the Alberta government may be going. As you can appreciate, they are holding everything relatively close to their best from the standpoint of depending on again the actions they take can have very positive or negative impacts on, not just the power industry but across industries.

Okay. Can I take though that based on your actions to use your carbon credits that you're thinking that either something will be done more aggressively on carbon via CASA or even earlier decommissioning than the 50 years rather than some sort of larger carbon tax for your credits to become more valuable?

The utilization of credits. So firstly, that is -- intends to be an accrual as opposed to the way you ultimately price your carbon so or utilize your carbon credit.

So for example, last year there was an adjustment in 2014 results based on 2013 and a change in decision to use or utilize that credit as opposed to $15 a ton. So that tends to remain somewhat of an open question.

Our view today is that it is more prudent to be going the direction we are, but we are able to change that as we go through the year.

Okay. And I guess just the last question.

M&A environment, your thoughts on acquisitions valuations if you are seeing things gets worst, gets better. If they are getting better, are there any particular geographies or fuel types that are looking more promising at this point?

So on the M&A front, certainly a lower level of activity, but we are also as a general comment seeing others be more aggressive from a pricing perspective. So from our perspective, there is even less of a chance of anything coming across to us in terms of an operating contracted facility that would be of interest to us or that we would be even closely competitive on.

And I guess with, Brian, not moving kind of further away from you, does that change how you’re thinking about potential for some divestitures?

No, not at this point. There is always one other questions around divestiture is utilization of capital.

And we are not seeing a lots of opportunities out there, don’t believe investors want to see us sitting on cash. But as always, if there were significant opportunities that arise, the sale of asset is absolutely something that we consider when looking at financing.

Okay. So the thought of selling, you are now setting north of 10 times in buyback stock, under 10 times, if the spreading is wide enough for you?

I think when you look at levels of buyback and the fact that we’ve got significant cash flow today without going into the sale of assets, I think certainly -- we’d certainly wait until what we’ve seen, what we’re able to do from a cash flow perspective before we start selling assets.

Okay. That’s great.

Thanks very much.

Thank you. I just had a follow-up question on your hedging activity.

I think -- possibly, we all assume that you’re still substantially hedged for the balance of the year. But can you just confirm that?

I don’t remember hearing or seeing anything post Q1, what your hedging position is for this year?

Yeah. So, we remain materially hedged.

And I think from an ongoing basis coming into the year, we’ll provide guidance around what our position is for the prompt year as we did through Investor Day and year end disclosure for 2015. But I think one of the things that we modified in disclosure is the fact that we’ve dropped on going quarterly updates on the 2015 position.

And that’s reflected of the fact that I don’t think it’s helped a lot from a modeling perspective, for the market and at the same time provide a set of competitive disadvantage in providing that information to our peer group. But to the extent that there were material changes -- there would be material changes to the previous disclosure we’d be required to update that.

And I can confirm that there hasn’t been material changes.

Great. Thank you.

Thanks. On this the Beaufort Solar project that you’ve announced you are moving forward with, can you give us some sense of what the CapEx would be on that?

And why is it not in your CapEx schedule in the MD&A of the amount that this project’s going to cost?

So, total CapEx on that, Paul is about $35 million. And the reason why it’s not included is because effectively, it’s a sale leaseback and we’ll sell it back to the tax equity partner, Wells Fargo.

And so at the end of the day, there’s not really a net outflow on the capital spending side by the time you get to year end.

Okay. And how should we think about the returns on this versus the other projects you have like Shepard and K2?

It’s a bit of a different structure with a tax equity partner than you’d normally see. So when we look at it, at the end of the day there is really not much of equity or overall capital investment.

What it does provide is just under $1 million worth of annual EBITDA going forward with effectively normal amount of upfront capital. And then once it flips after 10 years, a little bit more than that.

So from our perspective a great project, very low risk, a reasonable return on low risk project allows us to develop solar expertise.

All right. And so you’re assuming construction risk, is that correct.

Correct.

And has there been any BC contract at this point or no?

Not signed yet, but we will go down that path with pricing in hand.

Okay. Got you.

All right. Thank you.

Thanks.

Okay. If there are no further questions, we will conclude our call.

Thanks again for joining us today and for your interest in Capital Power. Have a good day everyone.