Capital Power Corporation

Brian Vaasjo - President and CEO Stuart Lee - SVP, Finance and CFO Randy Mah - IR

Paul Lechem - CIBC World Markets Linda Ezergailis - TD Newcrest Andrew Kuske - Credit Suisse Robert Kwan - RBC Capital Markets Matthew Akman - Scotia Capital

Good morning and thank you for joining us today to review Capital Power’s fourth quarter 2014 results, which were released earlier this morning. The financial results and the presentation slides for this conference call are posted on our Web site at 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 2. In today’s presentation, we will be referring to various non-GAAP financial measures as noted on Slide 3.

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 2014.

I will now turn the call over to Brian for his remarks starting on Slide 4.

Thanks, Randy. Good morning.

I’ll start off by reviewing our highlights for 2014. During 2014, significant progress was made on our two construction projects, the final stages of construction at a Shepard Energy project, our joint venture with ENMAX were completed.

Shepard is currently in the commissioning phase with a start of commercial operations expected next month. For our K2 Wind project in Ontario, the project financing was completed in the first quarter of 2014 and the project commenced construction.

Construction is on schedule and K2 Wind is expected to begin commercial operations in mid-2015. Our future growth plan in Alberta is focused on Genesee 4 and 5.

In 2014, we executed agreements with ENMAX to develop, construct and operate the Genesee 4 and 5 project. Last month, the project received all major regulatory approvals to proceed with construction.

I’ll provide more details on the construction plans later in the call. In late 2014, we acquired Element Power and its attractive portfolio of wind and solar development sites in the United States that will provide Capital Power with a solid foundation for future growth.

Finally, we announced the company’s first common dividend share increase, a 7.9% increase in the annual dividend that was effective with a third quarter payment. Turning to Slide 5, this slide summarizes the plant availability, operating performance of our plants for the fourth quarter of 2014 compared to the same period a year ago.

Overall, we had strong operating performance with an average plant availability of 94% in the fourth quarter compared with 93% for the fourth quarter of 2013. Of note, we achieved this mark despite the 74% availability of Genesee 3, which reflected a 27-day planned outage that occurred in September and October last year.

Turning to Slide 6, the chart on this slide shows our average plant availability over the past six years. As you can see, our track record has been strong with our plant availability consistently above 90% over a six-year period.

In fact, in 2014, we achieved our highest operational performance in the past five years with a 95% average plant availability. We have a similar operational target for 2015 of 94%.

I’ll now turn the call over to Stuart to review of our financial performance.

Thanks, Brian. I’ll start my comments on Slide 7.

In the fourth quarter, the company generated $102 million in funds from operations, which was in line with our expectations. Normalized EPS of $0.20 in the fourth quarter was lower than expected due to the non-cash impact of 2014 deferred tax expenses and lower wind generation Quality Wind and Port Dover and Nanticoke.

Alberta spot prices in the fourth quarter were weak averaging $30 per megawatt hour compared to $49 per megawatt hour in the fourth quarter of 2013. However, despite this 39% price decline, our trading desk capture realized price of $58 per megawatt hour, which was 93% higher than the spot prices.

Our realized price was 31% above spot in Q4 2013. Slide 8 presents our Alberta power market trading performance over time.

You can see that over the past five years, our trading desk has captured an average realized power price that is 16% higher on average compared to the spot power price. Not only does our portfolio optimization activities continue to create incremental value by capturing a higher realized Alberta power price in spot, it also helps to manage our exposure to commodity risks and reduce volatility, as illustrated by the flatter orange line on the chart in contrast to the more volatile spot power price shown by the blue line.

Turning to Slide 9, I’ll review our fourth quarter 2014 financial performance compared to the fourth quarter of 2013. Revenues were $432 million, up 32% from Q3 2013 due primarily to higher unrealized changes in the mark-to-market of our commodity derivatives and emission credits.

The Alberta commercial plants and portfolio optimization segment also contributed higher revenues, which were offset by the 2013 November sale of the New England assets. Adjusted EBITDA before unrealized changes in fair values was $104 million in Q4 2014, up 2% primarily due to lower corporate expenses.

Normalized earnings per share of $0.20 was lower than the $0.40 in the fourth quarter a year ago, primarily due to higher coal costs for the Alberta contracted plants and the non-cash impact of 2014 deferred tax expenses. As I highlighted earlier, funds from operations of $102 million were in line with our expectations for the fourth quarter.

Turning to Slide 10, I’ll review our financial performance for the year. Revenues of $1.23 billion for 2014 were 12% lower than the $1.39 billion in 2013, due mainly to the sale of the New England assets in 2013 and lower revenues in Alberta commercial plants and acquired Sundance PPA.

Adjusted EBITDA before unrealized changes in fair values was $387 million in 2014, down 20% primarily due to lower results in the Alberta commercial plants and acquired Sundance PPA segment, a function of weaker average spot price and lower production. This is also reflected in normalized earnings per share, which came in at $0.72 compared to $1.74 in 2013.

Finally, funds from operations of $362 million was in-line with 2014 financial target of $360 million to $400 million. I’d now like to review our 2015 outlook starting with an outlook on the Alberta power market on Slide 11.

This chart shows the 2015 forward price curve starting from September 1, 2014 to February 17, 2015. Last September 2015 forward prices were in the mid $50 per megawatt hour range and the price has gradually drifted downwards.

You can see a sharp decline in 2015 forwards starting in late January, which were associated with a number of factors including the decline in spot prices, Shepard Energy Centre reaching material generation levels during its commissioning process and declining natural gas prices. Turning to Slide 12, from a macroeconomic perspective, due to a significant decline in global oil prices that 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 over the next couple of years have recently declined.

As shown on the previous slide, forward prices for 2015 are currently in the mid $30 per megawatt hour range, which is lower than our original forecast assumption of $44 per megawatt hour. The actions taken over the last several years including our hedging and cost reduction programs were initiated in anticipation of lower pricing in 2015.

With our Alberta base-load position fully hedged for 2015, it will have a reduced financial impact on our 2015 financial guidance. Despite the lower forecast for Alberta power prices for the year, our 2015 funds from operations expectations remains in the target range but at the lower end of the $365 million to $415 million guidance.

Capital Power’s financial strength is based on the foundation of strong contracted cash flow, which is not impacted by changing Alberta power price outlook. We remain confident in our credit rating and dividend growth outlook.

I’ll now turn the call back to Brian.

Thanks, Stuart. Starting on Slide 13, I’ll conclude my comments by reviewing our 2014 operational and financial performance versus targets and recap our 2015 targets.

As mentioned, we achieved our 95% plant availability target for 2014 and have a 94% target for 2015, which includes major plant outages at Genesee 1 and Keephills 3. Our sustaining CapEx was 75 million in 2014, which was below our $85 million target due to lower spending at the Genesee mine land purchases.

We are targeting 65 million for 2015. Our plant operating and maintenance expense for 2014 came in at 185 million, which was in line with our target range of $165 million to $185 million.

For 2015, we are targeting $180 million to $200 million for our plant operating and maintenance expenses, which includes Shepard. As Stuart indicated, we were within our 2014 cash flow guidance by generating 362 million in funds from operations.

For 2015, we are now expecting to be at the lower end of the 365 million to 415 million guidance range. Slide 14 outlines our development and construction targets for 2015.

For K2 Wind, we expect to complete construction with commercial operations near the middle of the year. The Genesee 4 and 5 project has been on a path to reach completion as early as 2018.

We have incorporated tremendous contractual flexibility to push the project timing out if appropriate with minimal cost consequences. The flexibility was developed to allow Capital Power and our partner ENMAX to adjust completion based on market dynamics.

Certainly lower demand for power as a result of lower demand growth in Alberta could have the impact of targeting and completion date after 2018 and reducing our 2015 construction activity. In conjunction with our partner, we are currently accessing the market dynamics and the appropriateness of targeting a completion date after 2018.

We should arrive at a conclusion sometime over the next quarter. To conclude, I want to comment on our financial strength going forward.

Slide 15 is a slide we presented before illustrating the coverage of our financial obligations including dividends to cash flow, showing specifically the relationship for contracted cash flow and contracted cash flow plus sensitivity to merchant cash flow at various Alberta price levels. The first point is that the contracted cash flow line upon which we based our dividend increase we announced last July is virtually unchanged.

This line continues to support the existing dividend plus future dividend growth. The second point is that even under low price scenarios, the merchant cash flow line continues to make a strong contribution to total cash flow.

I’ll now turn the call back over to Randy.

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

Thank you. Good morning.

Just wanted to ask about the adjustments to the coal cost of the Genesee units. You seem to suggest in the write up that it impacted the earnings but if it’s just shifting them from one unit to another, how is there an overall impact on your results and can you give us a magnitude of that?

It shifts some, Paul, but also obviously with the portfolio of G3 going to TransAlta, it also has an impact overall. So to the extent that more gets picked up by G1 and G2, it has an overall impact on us, and it a couple million dollars.

It’s not real significant but it does have a modest impact.

Okay, thanks. Can you discuss the disallowance with your U.S.

tax NOLs for accounting purposes?

Sure. So obviously a true-up at year end but also a portion of it is related to Q4 and the fact that we’re not recognizing those.

So, on a go-forward basis, I think we would expect that a project like Element will hopefully – will be successful in generating taxable U.S. income in the future, which will have subsequent of NOLs to use against and potential for re-recognition.

But for the quarter, we haven’t recognized any of the U.S. NOLs consistent with the rate down there we took in Q3.

Okay. And finally, can you give us a magnitude of a cost for winding up your defined benefit plant at the Genesee coal mine?

That was about $2 million.

All right. Thank you.

Thank you.

Thank you. I’m wondering what the seasonality might be in the duration of your planned outages scheduled for 2015 G1 and K3?

Seasonality we expect for the Genesee facility to be in Q2 and for K3 expected it’ll be Q4 and similar type of timings what we saw this year for G2 and G3, so typically those outages run for G1 and G2 about three weeks and for K3 and G3 typically around four.

That’s very helpful. And just a follow-up question.

Are you starting to see or think about maybe a silver lining to all of this oil and gas activity weakness as translating perhaps into some sort of cost relief or relief at least of inflationary pressures in your operations and can you comment on that?

So certainly there are implications to the overall decreasing activities in the province. We would see that there’s certainly one of the offsets associated with potentially lower demand is that there continues to be lower crude oil prices, a number of the oil sand projects that have coal Gens associated with them may not be proceeding.

So that’s a fairly significant offset to declining demand. The other thing from an overall cost perspective is we’re already seeing cost being lowered in the province.

You’re seeing wage settlements being lower, you’re seeing companies such as ours with annual compensation increases significantly below what they otherwise would have been or were planned to have been. So you’re seeing certainly some decreasing cost pressures.

As we move forward with a lower level of activity generally in Alberta, we would see the eventual construction of Genesee 4 and 5 benefit with greater labor availability. And certainly in our maintenance costs, we would see not only potentially lower costs but probably tapping into a more experienced labor force.

So, there are certainly some benefits to, I’ll call it a lower level of economic activity in the province.

That’s very helpful. And just one other cleanup question.

At your Investor Day, your hedging was at slightly different levels for 2016 and 2017 and also the rich level of pricing shifted around a little bit. Can you comment on is that just a shift in your production mix or is there something else going on?

So the 2016 changes, I think, were pretty modest, Linda. For 2017, I think the quote that we had in for average power price hedges in the low 60s wasn’t accurate and it should have been probably still in the mid-50s.

Okay, that’s very helpful. Thank you.

Yes.

Thank you. Good morning.

Just a question on the hedging given the rapid decline in Alberta power prices and sort of the very divided view on outlook on whether prices go up or down, just how do you think about your hedging strategy now as it stands for the next couple of years? Is it more of the same as we’ve seen in the past or do you anticipate revising your strategy just a little bit on the laddering?

I think you’d expect to see some changes in our strategy on the laddering. I think our view on 2015 is fairly consistent with where the market is at.

As you move out 2016 and beyond, which means you get into the latter years, there’s not a lot of liquidity in the market and I don’t think that the forwards necessarily reflect our view of where power prices are likely to move. I think we view that additional demand will create higher prices in the province going forward and therefore I think we all probably look at 2016 and beyond layering and stuff on a pretty modest basis.

Okay, so probably a bit more open position than you would normally have in the last few years just because you take the view of the prices are just too depressed right now relative to what we might see?

Correct. A good example of that is we went into 2013 about 50% of our base-load position we left open on a view that the forwards weren’t reflective of our fundamental view on prices.

And obviously it reflected in 2013 performance and similar as we move out to 2016 and beyond.

Okay, that’s helpful. And then are you seeing significant changes in just your customers’ behavior given the fact we’re going to see a few of the PPAs rolling off in '17?

Is there really a reluctance right now to lock into any kind of structured term for a period of time at what you would view reasonable prices?

We’re actually seeing no real level of identifiable increase or decrease in activity. This is typically going to the first quarter a time of less activity for say industrials to be hedging and that’s consistent – what we’re seeing is consistent with that view.

Typically, it’s the fourth quarter and the third quarter that you see more of the activity in the market.

Okay, that’s great. Thank you.

Good morning. If I can just first follow up on the hedging but more so as it relates to your outlook.

So I’m understanding that your bullish on the curve for '16 and '17 and so even with the oil prices, it sounds like you still think we’re going to see decent demand growth in the province?

I don’t know if I’d call it decent relative to historical, Robert. Again, I think historically we’ve seen 3% to 3.5% demand growth and certainly under the current expectations around GDP growth in the province, we scale that back.

I think we’re still working through our current update to the forecast, but expect that that’s likely to move down to probably 1% to 1.5%. But even that level of GDP growth and demand growth in the province coupled with likely push out in some of the coal generation facilities that may get built in the province provides some additional support for pricing going forward.

Got it, okay. Do you have any updated thoughts on how CASA might play out?

There was some comments from somebody else that there may be a decision imminently that would involve effectively a harmonization with the carbon rules?

Currently, there are a number of avenues of discussions taking place with the government. Generally speaking, those discussions are to be confidential, so not really appropriate for me to comment on it.

I would say it’s pretty early to speculate on anything.

Okay. I guess if we went back into the fall you were pretty confident that the existing goals would stick, I guess, directionally or you may be a little less confident then at this point?

No.

Okay. Just a last question here.

If you look at Slide 15, based on your contracted cash flows, you’ve got good coverage of the divi, you’ve got room to increase that. I guess I’m just wondering with the weak Alberta power prices, does that change the thought process on whether it’s prudent to increase it annually and/or your thoughts on just the magnitude of the increases?

So I think going back to when we first showed you this slide probably over a year ago, the whole concept was that we’ve got a very strong base of contracted cash flow and that’s what we look to support both the dividend, dividend growth and certainly supports our credit rating what we refer to as the upside at the Alberta market and the range that you see there is more a function of certainly the general upside that utilized more or considered more rebuilding balance sheet for capital expenditures, for paying down debt, potentially buying back shares, that kind of more capital intensive use. So really our perspective hasn’t changed that much by the changes in power prices.

On the other side of the coin, power prices went up dramatically and we are looking at a $0.80 power price today. We wouldn’t be looking at necessarily increasing the dividend more than we otherwise would.

We’re looking for a long-term sustainable dividend based on secured cash flows. So, our proposition around dividends really hasn’t changed with the lower oil prices.

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

Thanks. Good morning.

Stuart, I’m just wondering if G4 and 5 are delayed, have you thought about what to do with the surplus cash flow this year?

Good question, Matthew. I think the impact overall is about $15 million to $20 million of CapEx that we had earmarked for G4 and G5 in 2015, so not all that material.

But as we look at our excess cash, which is substantive for 2015 I think absent a new development opportunity and obviously the team is working hard on some of the Element portfolio and some of the wind and solar opportunities, but absent an opportunity there, would expect that we’ll look at both debt reduction and potentially some share buybacks associated with it.

Is there anything on the debt reduction front that you see as urgent or is the decision between debt reduction and share buybacks in the balance there going to be more related to your stock price?

So there’s nothing urgent whatsoever on the debt buybacks. We did over the course of I think as we noted in the MD&A, we bought back about $50 million of debt in late 2014 and continued with a small buyback through 2015.

So we reduced our overall debt balances by about $70 million, but nothing urgent. We’re very, very comfortable with where our credit metrics are and where our rating debt.

As we look at the combination of debt reduction and potential share buybacks going forward, it’s really a function of where share price is at as well as the overall balance to balance sheet, and so expect that there might be a mix of both.

Okay. Thank you.

Those are my questions.

Thanks. Just maybe a couple of follow-ons in terms of the previous questions.

On the emissions front in Alberta, you paid your SGER compliance requirements by using cash rather than your CO2 credits. Just wondering given your expectation that there’s going to be no change in the environment, why continue to pay cash, why not use the credits?

So we will be for this most recent compliance here, Paul, we’ll be using our inventory.

Okay. And then just on the Element’s portfolio.

Is there anything in terms of the tax environment that you’re waiting for? Do you need further clarity on the U.S.

production tax credits before moving forward on any of those sites or how should we think about when you might move forward on some of those projects?

Paul, the situation is that there tends to be around the existing regulations, there’s a lot of clarity around them and around interpretation. So as it relates to the Element portfolio, what we’ve done is as you know there’s a number of those that are in very, very late development stages and what we’ve done is we’ve actually gone out at the end of last year and put orders down for two transformers, which will make two of those properties eligible for the current tax credit regime, so we’re definitely moving ahead on trying to obtain PPAs on two of those projects.

And those projects one would under the current regulations would have to be complete by the end of 2016. So, a significant amount of work, focus on that.

And again, those would be with tax partners, et cetera, so the capital cost commitment isn’t as significant as one would expect on those projects in total. Also, we’ve won one other project.

It was a small solar project in North Carolina that actually has a PPA associated with that and we’re moving forward on that subject to – continuing to do some work but may well start construction on that by say early July for completion this year. So there’s certainly some promising activities around the Element portfolio.

Okay. Thanks very much.

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

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