Capital Power Corporation

Randy Mah - Senior Manager, Investor Relations Brian Vaasjo - President and CEO Bryan DeNeve – SVP and CFO

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

Good morning. And thank you for joining us today to review Capital Power’s second quarter 2015 results, which were released earlier this morning.

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 Bryan DeNeve, 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 Q2, 2015. I’ll now turn the call over to Brian Vaasjo for his remarks starting on slide 4.

Thanks, Randy, and good morning. I'll start off with a quick review of the highlights for the second quarter.

We had a solid operating performance with an average plant availability of 90% reflecting both planned and unplanned outages for all assets. We reported normalized earnings per share of $0.10 which were slightly below expectations but higher than the $0.07 for the second quarter of 2014.

Funds from operations of $70 million were modestly below expectations and lower than $85 million for the same period a year ago. Based on the results in the first half of the year and our expectations for the remainder of 2015, our outlook is modestly improved but remains at the low end of our stated FFO target range.

Turning to Slide 5. This slide summarizes the plant availability operating performance of our clients for the second quarter of 2015 compared to the same period a year ago.

As mentioned average plant availability in the second quarter was 90% compared to 92% for the second quarter of 2014. Operating performance was below our expected rate reflecting the 73% availability at the new Shepard facility.

This was a result of 28 day unplanned outage relating to the heat recovery steam generator. Repair work on this defect has been completed and the Shepard facility return to operations in late June.

In the second quarter, we also completed a major scheduled outage at Genesee 1 that reduced the unit's availability to 92% or 72%. Turning to Slide 6.

On May 29, K2 Wind became fully operational in Ontario and capable of generating 270 megawatts with one third of the generation capacity belonging to Capital Power. The output is contracted to the Ontario Power Authority under a 20 year PPA.

Capital Power, Samsung Renewable Energy and Pattern Energy Group are equal partners on the K2 Wind project. Capital Power's share of the final construction cost is expected to be $310 million.

With the addition of K2 Wind, the company's total generation capacity of 577 megawatts now represents 18% on the company's overall capacity with a majority of the wind output under long-term PPAs. Moving now to Slide 7 to discuss the recent changes to Alberta carbon emissions regulations.

On June 25th, the Alberta government announced changes to the Specified Gas Emitters Regulation or SGER. SGER requires facilities that emit 1,000 tons of more of greenhouse gases per year to reduce emissions intensity by a specific target.

The changes will increase the required reduction in emission intensity from the current 12% to 15% at 2016 and 20% in 2017. There were also an increase in the cost of contributions to the Alberta tech fund from the current $15 per ton to $20 per ton in 2016 and $30 in 2017.

We expect that between 2016 and 2020, the increase in Capital Power's compliance cost will be partially mitigated by higher wholesale power prices directly caused by the new regulations. The Company has a significant inventory of low cost carbon offset credits that have been developed over the past eight years which are expected to offset the balance of the compliance costs through 2020.

Turning to Slide 8. Capital Power's Board of Directors has approved a $0.10 per share increase in the annual dividend.

Effective with the third quarter dividend, the quarterly dividend will increase 7.4% to $0.365 from $0.34 per share. Our contracted cash flow base has grown significantly with recent additions of Shepard and K2 Wind in 2015.

And as you are aware the Board bases its dividend determination on a level of sustainable cash flows attributable to contracted assets. Moreover, Capital Power is well positioned to consistently increase the dividend while also investing in growth opportunities.

I'll now turn the call over to Bryan DeNeve.

Thanks, Brian. I'll discuss our financial results starting on Slide 9.

In the second quarter, the Company generated $70 million in funds from operations which was modestly below our expectations which reflected the impacts from the unplanned outage at Shepard that I'll discuss shortly. Normalized earnings per share of $0.10 in the second quarter.

In the second quarter the Alberta government announced changes to the corporate tax rate increase in the provincial rate from 10% to 12% effective July 1, 2015. As a result of the tax rate increase, we've recognized $19 million in additional deferred income tax expense.

Overall, the increased Alberta tax rate is not expected to have a cash income tax impact on the company until 2018. Moving to Slide 10 I'd like to review the performance from the Alberta commercial plants and portfolio optimization segment.

Alberta power prices average $57 per megawatt hour in the second quarter of 2015 compared to $42 for the second quarter 2014. The Shepard outage occurred primarily in June coinciding with other non-Capital Power operated plant outages as well as warmer weather.

This resulted in Alberta spot prices averaging $97 per megawatt hour in a month compared to $21 in April and $54 in May. With our commercial production a 100% sold forward in June, the Company was required to cover short market position at prevalent spot prices.

Although the high spot prices negatively impacted the second quarter results, it also caused the temporary increase in forward rate that we were able to take advantage off to benefit our portfolio position over the last half of the year. We also capitalized on the higher forward rates by increasing our hedge positions from 49% to 86% in 2016 and from 12% to 25% in 2017, compared to our position at the end of the first quarter.

Turning to Slide 11 I'll review our second quarter financial results compared to the second quarter of 2014. Overall, second quarter financial results primarily reflect the impacts from the unplanned Shepard outage.

Revenues were $83 million, down 65% from Q2, 2014, primarily due to the unrealized changes in fair value of commodity derivatives and emission credits and lower results from portfolio optimization. Excluding the mark-to-market adjustment revenues were $254 million in Q2, 2015 slightly higher than the $253 million in Q2 of 2014.

Adjusted EBITDA before unrealized changes in fair values was $92 million, up slightly from the second quarter of 2014. All plant segments had higher adjusted EBITDA year-over-year which was offset by higher corporate expenses.

The increase in corporate expenses was due to higher finance expenses and depreciation and amortization from the completion of the Shepard project. Income tax expense also increased in the second quarter from the increase in Alberta statutory corporate income tax rate that I discussed earlier.

Normalized earnings per share of $0.10 increased 43% compared to $0.07 a year ago. Funds from operations of $70 million were modestly below our expectation for the quarter and down 18% year-over-year.

Turning to Slide 12. I'll quickly cover our financial results for the first half of 2015 compared to the same period in 2014.

Overall, the year-to-date results showed slight improvement. Revenues were $441 million, down 20% year-over-year primarily due to unrealized changes in fair value of commodity derivatives and emission credit.

Adjusted EBITDA before unrealized changes in fair values was $208 million, up 6% from a year ago due to higher EBITDA contributions from both the Alberta Commercial plant and portfolio optimization segment and the Alberta contracted plant segment which were partly offset by higher corporate expenses. Normalized earnings per share were $0.40 on a year-to-date basis in 2015, up 3% compared to $0.39 a year ago.

Funds from operations are $178 million for the first half of 2015 which is up slightly on year-over-year basis. I'll conclude my comments for the financial outlook on Slide 13.

The average Alberta power price of $43 per megawatt hour in the first half of 2015 is consistent with our original forecast assumption of $44 per megawatt hour. At the beginning of the year our Alberta baseload position for 2015 was significantly hedged in the mid $50 per megawatt hour range which is not materially changed.

Based on year-to-date results and our expectations for the balance of the year, our outlook has moderately improved from three months ago. But remains in low end of our $365 million to $415 million FFO guidance range.

Capital Power's financial strength is based on our foundation of 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'll now turn the call back to Brian Vaasjo.

Thanks, Bryan. I'll conclude with an update on our targets and corporate priorities.

The charts on slide 14 show our year-to-date operational and financial results versus the 2015 annual target. The first six months average plant availability was 94% consistent with our target for 2015.

Our sustaining CapEx was $35 million versus the $65 million annual target. We recorded $92 million in plant operating and maintenance expense versus the $180 million to $200 million annual target.

Finally, we generated $178 million in funds from operations. Overall, we are on track to meet our 2015 annual operational and financial target.

Turning to Slide 15. 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.

As I mentioned the K2 Wind project was completed on time and on budget in the second quarter. For Genesee 4 and 5 our goal is to transition to the construction phase this year.

We are on track with the COD for Genesee 4 targeted for 2019 based on our shared view with ENMAX but this is the early state but the Alberta market would need this addition of generation. I'll now turn the call back over to Randy.

Thanks, Brian. Operator we are ready to start question-and-answer session.

Thank you, good morning. Just to start off with the Shepard outage.

Maybe could you give us some thoughts on why a plant which is maybe only two months old would have major outages at this point? And do you have any -- would be there be any warranty or insurance recoveries on the outage?

Good morning, Paul. The outage itself was as a result of basically a design flaw that has been analyzed, reengineered and corrected within the – structure, essentially there was -- it was under designed from pressure perspective and just a component of it.

And that component again has been replaced and so we don't anticipate any further issues associated with the outage or with that design flaw was -- the question of whether or not this is normal or not, generally speaking in the first year or so of new plant operations, there is an expectation that you have lower availability or either overall through the year a lower availability or whether there be an incident availability. Certainly this outage I would say modestly exceeded the magnitude of unavailability for this year but certainly is within the scope of normal kinds of activities that happen with new plants.

Okay. And as the question on warranty or insurance coverage or --

So the outage itself is not large enough to trigger business interruption insurance. The actual material costs are being covered by the vendor.

And -- so were you not able to -- you said you had a short position but would you not be able to cover that off through your Clover Bar peaker, was that not enough -- or did you sold Clover Bar production forward as well in the quarter?

We had sold some of the Clover Bar production forward in the quarter based on our expectations of prices. So certainly with Shepard not being available that would have removed about 100 megawatts from our position.

So certainly it was a combination of two things. We were -- we had sold some of it forward and then we lost the 100 megawatts of length out of Shepard.

Got you. And lastly before I hand it off but in your MD&A or in your commentary you said that your outlook for the balance of the year have modestly improved.

So I am just wondering what has improved that gives you - that allows you to make that comment.

Yes. So what occurred was as we saw spot prices increased dramatically in June in particular near the back end of the June.

We also saw an increase in forward prices over the balance of 2015. Now certainly we had some length remaining in the balance of the year for 2015.

So we are able to sell those length forward at higher prices than we had anticipated earlier in the year.

Okay, thanks and good morning, everybody. I wanted to follow up on the last commentary about you indicated you have increased your forward pricing.

But in your presentation maybe I missed this or misunderstood you mentioned that your mid 50s forward price is unchanged. Can you reconcile that for me?

Look the mid 50s is the approximate value of our forward hedges. So certainly we've seen that increase relative to Q1 earlier this year.

Okay. So it moved up a little bit in terms of your average hedge pricing for the balance of the year but it is roughly still in the mid-50 context.

That's correct.

Okay. Just on going back to Shepard, I wanted to check in on the capacity payments for the quarter and with an unplanned outage, was there a reduction in your capacity payments at all, and how does that play out with an unplanned outage?

Right. So under the contractual arrangements we have in place for Shepard, there is a provision there for certain amounts of unexpected outages.

What happen in June is that we had a negative variance or under recovered on the capacity payment of about $1.8 million.

Okay. And maybe my last question is on your commentary about the expectations for power prices increase with the carbon tax and I am just wondering what are you budgeting for 2016 pricing?

Our price expectations for 2016 are more or less consistent with current forward prices.

Thank you. Good morning.

I guess the question is in relation just to the dividend growth on a longer term basis. How do you and the Board really think about that dividend growth?

Is it something that should be consistent year-after-year or is it going to be more sporadic as some larger projects come online and then I guess there is the second element to the question is, just to proportionality of your cash flows, how should we think about longer term? Obviously there is [slight] [ph] level of cash flows from contracted assets and then maybe the second bucket is more merchant exposure and then maybe the third bucket is essentially your optimization portfolio and how do you think about borrowers around those.

So in terms of that dividend, in the longer term and how might you think about it, I think as we've demonstrated we were on a path of increasing $0.10 a year. And I think the reasonable expectations that until you see a significant step up in cash flows and one that is certainly sustained, we would continue that level and again you would see us step up, you would see a raise in the level of dividend and then that would set sort of the new bar for increasing dividend.

You would not expect the dividend to be going up and down. Just constant set of steps going up.

In terms of how we would we think about it as it relates to the different sources of cash flow and are there any bounds around that certainly we look at the contracted cash flow at the level that is today as the foundation and as you go forward there is a -- with other contracted assets added to the portfolio, there is a modest contribution by the merchant cash flows which again over the medium and longer term are going to go pretty substantially associated with rising power prices in Alberta. Now we wouldn't see forming a significant amount of dividend increase associated with increasing cash flows from the merchant business because in and of itself is not -- is subject to great volatility.

So again we wouldn't see that as being forming a significant amount of the base of sustained growth in cash flow. In terms of optimization, the optimization would have been largely on -- whether that's coming from merchant or our contracted assets.

And we would see it falling into one bucket or the other in terms of its contract - contribution to dividend growth.

Okay. That's very helpful.

And just on the risk management side on the optimization portfolio. Has anything really changed there or is the last quarter really the outages Shepard is a bit more of an anomaly as opposed to anything as your normal course.

So is there anything changing on the risk and benefit perspective on go forward basis given where we see power pricing in Alberta right now?

No. Certainly we continue to have virtually all of our baseload portion of our portfolio is contracted forward as we look forward for 2015, we will be optimizing that as we move forward in time but there hasn't been any changes in our risk management approach, certainly there is going to times when we face operational upset which will have adverse consequence but we believe over time the strategy we've been deploying on selling forward is create net benefit for the organization, we will continue to do so on a go forward basis .

Thank you. Just a question about your maintenance activity for the balance of the year.

Can you give us an update and comment on if K3 schedule for Q3 or Q4?

Yes. So planned outage for Keephills 3 has been moved forward from September to August timeframe and that was due to a number of factors just that would be taken in account in the market environment.

That's helpful. And just maybe amore high level question to the extent that you can comment on any discussions you had with the government as well as the subsequent discussion with the debt rating agencies on their views on the Alberta power market and its effect change, would be helpful.

So in respect of discussions with the Alberta government on the carbon side, Linda, there really has been not a lot of new information but what I can say is the messages from the government have remained consistent with the early readings that we have that there is certainly as they move forward across the Alberta economy and across all sectors, they are extremely sensitive to employment, the economy and respect to existing investments. So we continue to have a relatively positive view as to what the outcome of the further deliberation of a government.

That's helpful. And debt rating agencies, have you had any conversations with them and how they are looking at the Alberta government and market situation?

Yes. So we met with SMP and DBRS in early June.

And that was an area of discussion, from our perspective they are taking a wait and see view; they want to see what a new government does in Alberta and what's sort of policy changes they make. They haven't predetermined a negative or positive perspective at this point.

Good morning. I guess just looking at the 2016 hedges; it looks like or let me ask this way.

Is there any change in the volume assumption or is the movement down in the total hedge price a function of just hedging at lower prices indicative in the forward curve?

It is due to selling forward at lower prices than the average at the 49%.

Okay. And so I know that there was tiny bit -- there was a little bit of potential optimism around 2016 pricing, whether that was cash or related in terms of capacity coming out of the market.

Is it fair to say based on what you have done on the hedging that really your focus now is on 2017?

I think we've reached a point where 2016, we certainly feel we are in a very good place in terms of the amount we sold forward. We'll continue of course to monitor what happen in Alberta market and we believe there is that opportunity is there to further increase that hedge position we certainly would.

But yes I would agree 2017 becomes an increasing year of focus for us and certainly looking to increase that hedge percentage as we move forward in time.

But as you look at kind of your price expectation and the supply situation is the relatively low percentage for 2017 just a function of lack of liquidity in the curve or is there a natural bullish on that year.

It would be a combination of two so certainly we have more bullish expectations around 2017 than where we've seen those prices typically trade. But also to your point we saw a quite bit of liquidity in June and 2017 we are able to get advantage of that.

But liquidity remains very low for that period.

Okay. That's great.

Maybe the last question just on G4, G5. You've talked in the past about how you built of lot flexibility into the equipment and construction timing just allowing it to move the in service date around to best fit your guidance views.

At what point do you have to fully commit and really put the pin in for -- for at least the first unit coming in?

That timing would be well into next year.

Sorry, just a question on the Beaufort Solar, on the other renewable projects. You move Beaufort Solar into construction.

Just wondered if you have any of your other US renewable projects that you expect to be sanctioned through the remainder of this year that -- do you have any or you getting closer on any of contracting any of them to allow it move forward on the wind side maybe?

At this point time the bloom project looks quite positive. We are involved in a couple of processes that may well allow that project to move forward this year on a fully contracted basis.

And can you give us a sense of how big that would be in terms of dollar amount?

Bloom actually in part is depended on -- there is a little bit optionality associated with one of their particular bids, the overall total capital cost is in the order of $225 million or probably $300 million in total in terms of order of magnitude. But again we would have tax equity partner associated with that.

So the call on how our capital ultimately would be a portion of that.

Okay. And maybe I could just ask one last question following up on Robert's question on G4 or G5 the timing and so do you need to make a decision next year on whether you are moving forward on G4 and if pricing ends up where the forward curve is, how do you make a decision about at that of pricing a show if it is close to your high 40s number.

Is that the right number, is it pricing issue that will allow you to move forward, I mean do you need to see better pricing than that, do you need to see better forward curve, what is it that's going to allow you to actually make a big capital commitment to that point?

Well, as you know, Paul, forward curve as you move out get less and less reliable. As based on very, very thin trading.

It will be based on obviously -- although we can't share our view per se with ENMAX, we have to both be coming to a conclusion that a supply demand balance for 2019 and beyond would be sufficient to be moving power prices up. And again based on our independent views as to the supply demand balance.

And again with the flexibility that we have certainly 2019 could become 2020. And that's been the whole pieces of the way that we put this project together.

But again you do have to look at the fundamental supply demand balances as opposed to the forward curves when move and you get out that far.

Thank you very much. I am not sure if I missed if you guys quantify the impact of the Shepard outage on EBITDA or cash flow.

So we didn't breakout that in fact separately. But certainly that outage was the primary driver of the negative variance we have in Q2 for the Alberta commercial portfolio.

Which portion of the contracted output of the plant, does that impact affect because there are three portions? Is the tolling agreement and then some other contract and a contract for differences or is it all three portions?

It would all three portions combined.

So even the piece that's directly contracted with ENMAX is affected that way?

Yes. There would be I think as I mentioned earlier the tolling arrangement with ENMAX under the availability incentive terms and conditions; we would have realized a net loss of about $1.8 million.

Okay. And in terms of what you said Bryan about having additional length for you guys, could you just offset, was that somewhere in the trading book because baseload plants are contracted already for the balance of the year right.

That's correct. So 100 megawatts from Shepard is merchant for us and yes we loss that as available generation which is part of our baseload piece.

I am just wondering if the profit that you guys anticipate offsetting the second quarter negative variance had been locked in already or is that something that still depended on market conditions for the back half of the year.

For the most part it is locked in.

So that must have been quick trade.

There was a lot of trading activity in the back half of June.

We will just wait a moment to see if there are any further questions. Okay, I guess none so thank you for joining us today and for your interest in Capital Power.

Have a good day everyone.