Capital Power Corp

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

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

Good morning and thank you for joining us today to review Capital Power’s third quarter 2014 results, which were released on Friday, October 24. 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 prescribed by GAAP, and are therefore 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 dated October 24, 2014 for the quarter ended September 30, 2014.

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

Thanks Randy. I'll start off by providing an update on the Shepard Energy Centre project, and then review our operating performance, followed by a discussion on the Alberta power market and how it impacted our third quarter financial results.

First, let me update you on the construction of the Shepard Energy Centre which is being built in Calgary. The construction of the 800 megawatt natural gas combined cycle facility with our joint venturer, ENMAX, is now 99% completed.

The commissioning of the plant is ongoing with steam blowing of the main steam lines. The steam blows are expected to be completed before the end of this month.

Overall, the construction project is expected to be completed on budget and with the commercial operation date targeted for early 2015. Slide 5 highlights the plant availability, operating performance of our plants for the third quarter of 2014 compared to a year ago.

Overall, we had strong operating performance in our operated fleet with an average plant availability of 97% in the third quarter, which was unchanged from a year ago. Although the Keephills 3 facility had a 100% availability, its production was reduced due to derates.

For our acquired Sundance PPA, for units 5 and 6, these units achieved 85% plant availability in the third quarter, which I'll elaborate further on in a moment. Through the first nine months of the year, we have achieved a strong 95% average plant availability and we are on track to finish the year close to 95%.

Turning to Slide 6, I'd like to discuss the Alberta power market and our Alberta Commercial segment as it was the largest impact on the third quarter results. Our generation volumes in the third quarter were well below due to lower availability at the Sundance 5 and 6 units from planned and unplanned outages, the Keephills 3 derate, and lower wind generation at Halkirk.

Alberta power prices averaged $64 a megawatt hour in the third quarter compared to $84 per megawatt hour in the third quarter of 2013. On the surface, the average power price for the quarter was reasonable.

However, if you look at each of the three months within the quarter, there were significant price volatility with July averaging $122, $45 in August and $24 in September. The Sundance 5 and 6 outages occurred primarily in July, coinciding with periods of high price volatility, which I'll discuss in more detail shortly.

With our commercial production 100% sold forward in July, the trading desk had to cover short market positions created by lower availability at prevailing high spot prices, partially offsetting the cost of buying power at high spot prices and the capacity payments that we received under the Sundance C PPA for units 5 and 6. The capacity payments are based on a trailing 30 day rolling average power price or RAPP.

Unfortunately, the RAPP for July was only $71 per megawatt hour which did not cover the cost of covering our short positions. Overall, the EBITDA variance for the Alberta Commercial portfolio was $16 million below our expectations in the third quarter with $15 million of the shortfall attributed to trading activities in July.

The performance in August and September generally met our expectations. On Slide 7, I'll discuss the dynamics of the Alberta power market in more detail.

The chart on this slide shows the extreme pricing volatility in the third quarter, correlated with some of the various plant outages. The red solid line represents the daily settled price and the dotted line represents average monthly forward prices which ranged in the low to high $60 per megawatt hour price range.

The expected production from our Alberta baseload coal plants and the Sundance PPA in July was 100% hedged. However, a planned outage at Sundance 6 was extended and unplanned outage at Sundance 5 and derates at Keephills 3 resulted in short market position.

As you see in the chart, the timing of the Sundance 5 and 6 outages coincided with the significant price spikes in the three periods in mid July, end of July and mid-August, when we were in a short position and which required us to purchase power at high spot power prices. As the short position was backstopped with Clover Bar generation, that peaking facility was unable to fully capture the upside from the high power prices.

Power prices in the third quarter were also impacted by weather as Alberta experienced extremely high temperatures. In fact, July had the second highest average daily temperature in the past 30 years.

Associated with the hot weather, there was also very little wind generation and thermal generation experienced heat related derates across the province. Overall, the third quarter was an unusual quarter with significant price volatility, especially in July when a combination of events such as numerous plant outages, record high temperatures and no wind leading to high power prices over their durations.

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

Thanks, Brian. I'll start my comments on Slide 8.

During the third quarter we had a $73 million non-cash write-down of deferred tax assets relating to U.S. income tax loss carryforwards that can no longer be recognized for accounting purposes based on the current long-term forecast for U.S.

taxable income. The forecast showed a decline in taxable income over the latter years of the forecast.

For income tax purposes, these U.S. net operating losses do not expire until the 2027 to 2033 period.

Accordingly, they retain economic value. We continue to pursue U.S.

contracted power opportunities and the U.S. business development pipeline is active.

Our expectation is that with many successful development opportunities in the U.S. we could write up these deferred tax assets.

Turning to Slide 9, as Brian indicated, the weak financial results in the third quarter on a year-over-year basis was due to lower-than-expected performance in the Alberta Commercial plants and acquired Sundance PPA segment, and lower average Alberta power prices and lower realized power prices. As Brian mentioned, the average Alberta power price in the third quarter, $64 per megawatt hour, compared to $84 per megawatt hour a year ago.

Due to the events that Brian described, our trading desk at Capital realized power price of $56 per megawatt hour which was 13% below the average power price. Turning to Slide 10, I'll review our third quarter 2014 financial performance compared to the third quarter of 2013.

Third quarter results reflect the timing impact from planned and unplanned outages of the Sundance 5 and 6 units, the Keephills 3 derate, and lower average Alberta power prices. Revenues were $248 million, down 35% from Q3 2013, due to weaker performance in the Alberta Commercial plants, acquired Sundance PPA and portfolio optimization.

Lower revenues also reflected the November 2013 sale of the New England assets. Adjusted EBITDA before unrealized changes in fair values was $86 million in Q3 2014, down 43% primarily due to lower result in Alberta Commercial plants and acquired Sundance PPA segment.

This is attributable to the extended planned outage and unplanned outages at Sundance 5 and 6 units and the derates at Keephills 3 plant. These outages occurred primarily in July and negatively impacted our portfolio optimization position, as Brian discussed earlier.

Normalized earnings per share of $0.12 was lower than the $0.72 in the third quarter a year ago, primarily reflecting lower performance at Alberta Commercial plants and acquired Sundance PPA segment. And funds from operation of $83 million was down 34% from $125 million in Q3 2013.

Turning to Slide 11, I'll review our financial performance on a year-to-date basis. Our financial performance in the first nine months of the year reflected lower Alberta power prices that averaged $56 per megawatt hour compared to $90 per megawatt hour in the first nine months of 2013.

They also reflected the divestiture of the New England assets in November 2013 and lower generation from the Alberta Commercial plants and acquired Sundance PPA segment. Revenues were $796 million on a year-to-date basis, down 25% from the same period in 2013, due mainly to the sale of the New England assets and lower production from the Alberta Commercial plants and acquired Sundance PPA.

Adjusted EBITDA before unrealized changes in fair value was $283 million on a year-to-date basis, down 26%, driven primarily by lower [help] (ph) from the Alberta Commercial plants and acquired Sundance PPA segment from a weaker average spot price and lower production. This is also reflected in normalized earnings per share which came in at $0.51 compared to $1.35 in the first nine months of 2013.

Finally, funds from operations of $260 million were down 18% from the $316 million a year ago. I'll conclude my comments by reviewing our financial outlook for 2014 on Slide 13.

As disclosed in the October 17th press release, we have lowered our 2014 annual financial guidance. We now expect to generate funds from operations near the low end of our $360 million to $400 million target, including the $20 million received from the amendments to the Genesee Coal Mine Agreements.

This is changed from our previous expectation of generating FFO on the midpoint of our targeted range. Our updated guidance includes our forecast for Alberta power prices in the high $50 per megawatt hour range for the fourth quarter of 2014.

Our Alberta portfolio hedge positions have increased compared to the second quarter. We are 100% hedged for the fourth quarter of 2014 at an average hedge price in the high $50 per megawatt hour range.

For 2015, we are 92% hedged than the average hedge price in the mid-$50 per megawatt hour range, and for 2016 we are 49% hedged in the mid-$50 per megawatt hour range. The average hedge prices for 2015 and 2016 are slightly higher than where the forward prices were at, at the end of September 2014.

I'll now turn the call back to Brian.

Thanks, Stuart. I'll conclude my comments by providing a brief status update on our 2014 corporate priorities on Slide 13 and 14.

The operational targets include the average plant availability of 95%. Our expectation is that we will be close to the 95% target for the full year.

Our target for sustaining CapEx is $85 million with $42 million spent on a year-to-date basis. We are forecasting to be below the annual target due to the lower spending of the Genesee Mine land purchases.

Our plant operating and maintenance expense target is $165 million to $185 million. We expect to be at the upper end of this range.

And as Stuart indicated, our 2014 cash flow guidance is to generate between $360 million to $400 million in funds from operations. With the inclusion of the $20 million received from the amendments to the Genesee Coal Mine Agreements, we expect 2014 funds from operations to be near the low end of the guidance range.

Slide 14 outlines our development and construction targets. Construction on K2 Wind started earlier this year and is progressing well.

All access roads have been constructed, 140 foundations have been excavated, and 39 of the 140 turbines have been erected. As I highlighted earlier, the construction of the Shepard Energy Centre in Calgary is nearly completed with commercial operation scheduled for early 2015.

Finally, Genesee 4 and 5 is tracking well with joint arrangement agreements finalized with ENMAX and good progress being made towards our target of obtaining permitting approval in the first quarter of 2015. I'll turn the call back over to Randy.

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

I have a question about your broader hedging strategy. I realize this was a little, quite an unusual quarter, but I'm wondering if you've put some thought to maybe tweaking it or changing it outright, and within the context of that, maybe you can help us understand what role if any the peakers played physically in mitigating your short position?

So we obviously on an ongoing basis we are continually looking at our strategy in back-casting to make sure the strategies are appropriate for the different circumstances, whether you've got lots of production in the province or a little production in the province, it's just an ongoing process. And as we've looked back over this year, we're finding that the strategy is working reasonably well, particularly if you consider the month of September and October and going back in August as well.

So in looking at it, we continue to study it but at this point we're not seeing any reason to cause any sort of significant change in what that strategy might be.

And can you just walk us through how the peakers contributed to the quarter in terms of mitigating – like how much worse would it have been without help from the peakers physically or any sort of context around that?

I don't think [we can] (ph) specifically quantify exactly the impact. Obviously with Clover Bar you have about 250 megawatts of available capacity coming off that unit.

And at all times, our expectation is that we could have backed the position absent any major operational issues at the other facilities by using Clover Bar. So we were never at any point in time physically short based on our expected production capability, but obviously when you have a unit like Sundance 6 and at times 5 and 6 coming off the same time and you're losing upwards of 370 megawatts, it would have been impossible to fully hedge that with Clover Bar.

Okay. And maybe just if you can help us understand the cause of the derates at K3 in the quarter, was it heat related or water restrictions?

K3 was on I'll call it the tail end of derates that have been through the year and at various times expecting them somewhat to come off. I would say it's probably more appropriate, given that we're not the operator of the plant, to talk to TransAlta about that.

Having said that, we have been working with TransAlta more reasonably close to the issues and they've been working very diligently to try and eliminate the derates.

I'm wondering if you can give us any updated insights into the specified [CASA] (ph) regulation, any updates to that, and the CASA regulations expected out at the end of this year, if you have any thoughts or insights into how that's playing out?

I think the way it's evolving is with the change in leadership of the conservative party, a lot of the environmental regulations and actions around those are on hold for a short period of time. But prior to those changes, they were going according to expectations, the CASA regulations were sitting with the government having reached an impasse, which is what the process is, and we were anticipating receiving direction from the Alberta government.

Again, we're expecting it in and around the end of the year or slightly thereafter.

Okay, do you have any thoughts in terms of any increased costs for this year to credits?

No.

At this point, do you think cash to pay for your mission is credit – your mission's cost?

So for 2014, Paul, we expect to revert back the inventory use of our credits, because again I think one of the things that [Jim] (ph) [indiscernible] had mentioned in his disclosure is the fact that he wasn't looking to up this SGR rate from $15 a ton. And so at this point in time we would anticipate using this existing inventory.

I just wanted to go back to your hedged position in the quarter, and now I'm just curious was there anything different in terms of how you layered on your on-peak and off-peak hedges in this quarter relative to the past, did you get a wrong call on peak in July and just misread the market there?

So the on-peak off-peak ratio wouldn't have changed significantly, Ben, from what we would historically have hedged. On-peak is slightly higher hedged and a lot of the hedging was put in place up to the year before, in some cases longer than that, and traditionally speaking you're effectively hedging blocks as opposed to specific timeframes when you're hedging that for in advance.

So would it be that standard outage then that you would have – because it's been about, because it's a year prior that would've caught you off-guard there?

So I think it was a combination of both the extended outage as well as unplanned outages at some of the other facilities.

Okay. And going forward, would you be less inclined to hedge on-peak during seasonally strong months like July?

Again I think to Brian's point, as we look at back-casting, obviously a month like July we ended up with a negative variance relative to our expectations but then you move into a month like September and that strategy was pretty [inaudible] as it was in August and as it has been month to date in October. So as you kind of scroll forward and say, obviously we've disclosed what our baseload hedge is going to be in 2015, you also have to overlay on top of that what Shepard does to the marketplace, and adding 800 megawatts into Alberta we wouldn't expect necessarily to see a month like July again over the next, over the course of the next 12 to 18 months.

So you both back-cast your results and then you look at what changes fundamentally in the market going forward, that would alter your portfolio positioning.

Okay. And just on that commentary, Stuart, I mean your thoughts about additional peaking capacity, that's probably something that you're uninterested in upping at this stage?

Have no plans at this point in time.

Just my first question really relates to the main part of your clientele being the prospectively energy consumers and producers, and just with the recent decline in oil and just the general sentiment around it, what are your prospective customers and off-takers essentially saying to you around your generation needs into the future, are they as bullish as they were say six months ago, and do they think this is just a temporary blip in their plans?

We haven't heard anything specific around people's longer-term concerns. Most of the significant development that is ongoing in Alberta and slated to take place over the next number of years is by generally long-term players who take a very long term view, and our sense of that far is that they are not seeing it as a step change in crude oil prices in the market.

And then just as a follow-up to that, you're not really seeing any changes at this stage on labor rates or just intentions on build cost, any of those things?

No, there hasn't been a lot of pressure as yet but certainly what's happening in the provinces, although you have I'll call it a modest level of activity on the oilsands front, you've got a significant amount of activity on the infrastructure side, a significant amount of building taking place in Edmonton and Calgary and throughout the province. So although it's not directly oilsands related, there's just a tremendous amount of activity taking place.

So we are starting to see a bit of pressure in some of the trade areas.

And I would [indiscernible] as well, [indiscernible] where the most pressure is.

That has traditionally been an area that there is always been pressure on, just generally a shortage in – there's nothing has occurred to sort of overcome that shortage.

Okay. And then just related to that last point, and I guess this is a question more for Stuart, just on the P&L, the decline in staff costs and employee benefits, when we look at the Q3 '13 numbers versus '14, so the $37 million versus $29 million, is that largely attributable to just the restructuring activities that you had in New England?

Yes.

If I can just come back to what happened in July, so you had the Clover Bar back up and I'm wondering as well Joffre in there, it sounded like you're trying to say or you're saying it was largely effective. I'm wondering, point blank, was the desk short at the same time?

So, Robert, I think when we say it was effective on a year-to-date basis for July specifically, clearly not effective. But again, I think you have to look at the strategy not on a month by month basis but on a cumulative basis when we look at back-casting.

So, I think what we disclosed, we were 100% baseload sold forward coming into the quarter, and it certain times were also sold upwards of our gas assets, although again typically speaking we always maintain some level of length if you include our gas assets on the overall book, and in July we would have sold forward a portion of the gas production as well.

Okay, so effectively it was desk short backed by Clover Bar and Joffre on the physical side is what you guys were doing thinking about it?

Correct.

And Joffre not as much because we don't have dispatch control. I mean there is obviously the ability to end up with some additional coming out of Joffre but typically we don't look at it on that basis because we don't have dispatch control on Joffre.

Okay. I guess just taking a step back and thinking about your hedging strategy, how do you think about being 100% hedged on the baseload and then having a short position on the desk, i.e.

from a corporate perspective, you're effectively short the market, is that something that you continue to feel comfortable with as we go forward or is that potentially changing in the hedging and trading strategy?

Maybe a simple way to look at it is when you look at our baseload position and consider whether we're fully – assuming we're fully hedged, that leaves us with the gas position that can back up any outage, and coincidentally any unit that goes out is no more than 250 megawatts. So there's a beautiful matching between Clover Bar and any particular outage, and as Stuart said and as you commented on, there is usually in period of high prices you can count on the facility that's being run by ATCO, and so that's about another 130 megawatts.

The way we think about it and the way we look at it and from an overall corporate standpoint, there's periods of time when you want to be no more than one unit away from being actually totally physically short. And then there's times, depending on the volatility of the market and what you see happening, you may want to be two units away from being physically short.

That's actually the way we look at it. Going into the summer and going into the third quarter, the view is broadly you do want to have the ability to cover one short, that is one unit going out, and assuming high prices again, that also brings in the Joffre facility.

So that's generally the way we look at it when we think about it from a corporate perspective. Now when it gets to the trading desk and with those kinds of broader guidelines, there's certain things happening around temperature and derates and so on that impacts on the ultimate number that you're long or short in any particular period.

But that's the way we look at degrees of protection of the portfolio. And when that's under I'll call it seasonally adjusted normal circumstances and when you hit periods of time when you have more than one outage of your facility or your capacity and you have unusual pricing circumstances, it turns out to be a month like July.

Sure, okay. I guess just the last question, when you reported second quarter results, this had already occurred and at the time you reiterated guidance, and I guess my question relates more though to you were 100% hedged at the time, so what was in the base plan for the remainder of the year that left you thinking you could offset it or you could offset whatever $15 million to $20 million of FFO downside?

So at the time, Robert, that we disclosed Q3 guidance, we were down about $10 million in EBITDA at that point in time and typically we go through our forecast process early July and our early July forecast had FFO slightly above the midpoint of the guidance, and with the $10 million downside that we had seen at that point in July when we released Q3 guidance, we've been slightly below but still within the mid-range guidance and that's how we ended up disclosing the expectations for the balance of the year.

Okay, got it, thank you.

Okay, if there are no further questions, we'll conclude our call. I would like to also announce that Capital Power will be hosting its annual Investor Day event on the morning of December 4.

The event will be held in Toronto and more details on the event will be communicated in the near future. Thanks again for joining us today and for your interest in Capital Power.

Have a good day, everyone.