Capital Power Corp

Randy Mah - Senior Manager of IR Brian Vaasjo - President and CEO Bryan DeNeve - SVP and CFO

Rob Hope - Scotiabank Andrew Kuske - Credit Suisse David Quezada - Raymond James Robert Kwan - RBC Capital Markets Patrick Kenny - National Bank Financial Jeremy Rosenfield - Industrial Alliance Securities

Good morning and thank you for joining us today to review Capital Power's first quarter 2017 results which were released earlier this morning. The financial results and the presentation slides for this conference call are posted on our website at capitalpower.com.

Joining me on the call are Brian Vaasjo, President and CEO; and Bryan DeNeve, Senior Vice President and CFO. We will start the call with opening comments and then open up the line 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 therefore are unlikely to be comparable to similar measures used by other enterprises. These measures are provided to compliment GAAP measures in the analysis of the Company's results from managements prospective.

Reconciliations of these non-GAAP financial measures can be found in the Company's first quarter 2017 MD&A. I'll now turn the call over to Brian Vaasjo for his remarks starting on Slide 4.

Thanks, Randy. The highlight of the first quarter is Capital Power's execution on its growth strategy with recent acquisitions of contracted natural gas assets totaling 179 megawatts of capacity.

On April 13th, we completed the acquisition from Veresen of the York Energy Center in East Windsor facilities both located in Ontario. The transaction was originally announced in February of this year.

On April 12th, we announced the acquisition of the Decatur Energy Center from LS Power, which I’ll provide more details on shortly. These acquisitions are expected to increase the Company's AFFO by 67 million and adjusted EBITDA by 115 million in the first full year of operations.

Overall, our long-term contracted adjusted EBITDA as a percentage of total adjusted EBITDA is expected to increase from 66% in 2016 to 80% in 2017. Turning to Slide 5, I’ll provide more details on the Decatur Energy transaction.

We have an agreement with LS Power for the purchase of the Decatur Energy Center for $441 million subject to working capital and other closing adjustments. Decatur is a 795 megawatt natural gas combined cycle plant located in Alabama.

The facility operates under a 10-year tolling agreement which expires in December 2022. This is the third PPA for Decatur and it's well positioned for re-contract and based on its re-contracting history and the need for capacity in the region.

This is -- there is also optionality for Decatur as the facility will sell power into the PJM markets starting in 2023. The acquisition is being financed with both equity and debt.

This includes the completion of a subscription received offering for gross proceeds of 183 million. The debt portion will come from utilizing a temporary expansion of our credit facility followed by long-term financing.

Decatur is expected to add 43 million in AFFO in the first full year of operation and expected to generate approximately 60 million of adjusted EBITDA per year. We expect the acquisition to be completed in June of this year, subject to regulatory approvals and satisfaction of other customary closing conditions.

With the next two slides, I want to highlight the benefits from adding the two Ontario facilities and the Decatur facility in the United States. First Slide 6 illustrates our geographical breakdown based on capacity.

At the end of 2016, 74% of Capital Power's megawatts were in Alberta. This was followed by 13% in B.C., 7% in Ontario and 6% in the U.S.

With the recent acquisition and including our Bloom Wind project in the U.S., that is expected to be in commercial operation soon and you can see how we've achieved a geographical diversification away from Alberta. The capacity in Alberta will be reduced from 74% to 53%.

It will largely ship to the U.S. where capacity will increase from 6% to 26% of our total.

Turning to Slide 7, we've updated this chart to include Decatur. This chart shows the growth in our contracted adjusted EBITDA from 2010 to 2017.

As you can see our contracted adjusted EBITDA has increased 211% during this period which translates into an 18% compound annual growth rate. The 2017, you can see the significant increase in contracted adjusted EBITDA from several sources, which includes Bloom Wind starting in the third quarter, the start of annual off-coal compensation payments from the Alberta government and contributions from the acquisition of the three natural gas plants that I discussed.

Moving to Slide 8, this slide summarizes the availability operating performance of our facilities for the first quarter of 2017 compared to the same period a year ago. We had excellent operational performance in the first quarter with average availability of 97%, which was unchanged from a year ago.

Our annual 2017 target is 95%, which reflects major schedule maintenance outages for Genesee 1, Clover Bar, Southport, Roxborough and Keephills 3. I'll now turn the call over to Bryan DeNeve.

Thanks, Brian. I'll start on Slide 9 with a review of our first quarter financial performance.

Overall, first quarter 2017 financial results were in line with our expectations. This includes generating 91 million in adjusted funds from operations and normalized earnings per share of $0.34.

Alberta Power prices in the first quarter averaged $22 per megawatt hour compared to $18 per megawatt hour in the first quarter of 2016. Our trading desk performed well and captured 150% higher realized average price, a $55 per megawatt hour on our Alberta commercial assets versus the spot price.

Turning to Slide 10, I’ll review our first quarter financial results. Overall, the financial results this quarter were comparable on a year-over-year basis.

Revenues were $338 million up 1% from the first quarter of 2016. Adjusted EBITDA before realized changes in fair values was $134 million, up 5% from the first quarter of 2016.

This is primarily due to lower corporate expenses, reflecting the off-coal compensation and higher contributions from the Alberta Ontario and BC contracted facilities. Normalized earnings of $0.34 per share were up 3% compared to $0.33 in the first quarter of 2016.

As mentioned, we generated adjusted funds from operations of $91 million, which was down 2% on a year-over-year basis. Of note, 2017 marks the beginning of annual off-coal compensation payments that will be received in July of each year.

Our financial results will include the county recognition of this income that will be distributed equally throughout the year. From a cash flow perspective, AFFO will include the coal compensation annually in the third quarter when the cash is received.

On Slide 11, I’ll conclude my comments with an updated financial look for 2017. As mentioned, the annual off-coal compensation payments of $52.4 million start this year.

The acquisitions of York Energy and East Windsor in April and Decatur energy expected in June will provide partial year contributions to have a forward adjusted EBITDA. Brian, will provide an update on our revised financial guidance for 2017 shortly.

Our commercial hedging profile for 2018 to 2020 as of March 31, 2017 is shown on the slide. For 2018, we’re 61% hedged at an average contracted price in the high $40 per megawatt hour range.

For 2019, we’re 40% hedged at an average contracted price in the lower $50 metro megawatt hour range; and for 2020, we’re 33% hedged at an average contracted price in the high $40 per megawatt hour range. In summary, our base load merchant exposure is fully hedged in 2017.

And we continue to increase our hedges in 2018, which is increased from 53% at the end of 2016 to 61% at the end of the first quarter 2017. I’ll now turn the call back to Brian Vaasjo.

Thanks, Brian. The chart on Slide 12 shows our first quarter operational and financial results versus the 2017 annual targets, and in some cases, our revised annual targets.

The revised annual targets reflect the expected contributions from the acquisitions discussed earlier. In the first quarter, average availability was 97%, which is ahead of our 95% plant availability target for 2017.

Our sustaining CapEx in the first quarter was $4 million compared to the $80 million revised annual target. We reported $49 million in facility operating and maintenance expense in the first quarter versus the revised $215 million to $240 million target.

Finally, we generated $91 million in adjusted funds from operations in the first quarter. With the acquisitions, we’ve increased our 2017 AFFO target range to $340 million to $385 million, which is a 12% increase compared to the original target.

Slide 13 shows our growth targets for 2017. This includes the completion of our Bloom Wind project on time for commercial operations in the third quarter and on budget.

Our growth targets also include the execution of contracts for the output of two new developments. We continue to make progress on our development pipeline in the U.S.

and in Alberta under the renewable electricity program. We’re well positioned to provide renewable generation from our Halkirk 2 and Whitla Wind sites.

I’ll now turn the call back to Randy.

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

May be just looking at your strategy moving forward, we've seen you being quite active on the M&A front. Looking forward, can you add some color on your U.S.

strategy, is this now more of a greenfield for renewables as well as potential M&A for thermal assets and is there anything else in the hopper?

In actual fact, our general strategy has not changed though over the last number of years. We've looked for per contracted opportunities, both from a greenfield perspective and from M&A perspective across North America.

What's happened of late is that -- and we've seen the progress of that in terms of the opportunities we've looked that. We've seen that, from a natural gas perspective, we are becoming more and more competitive and hence our ability to prevail on two bidding processes, one here in Canada and of course one in U.S.

So, you will continue to look at opportunities as they arise. And again, continue to apply the same discipline we have historically that if acquisitions make sense for Capital Power, we'll go forward and execute on those opportunities.

If they prove to be not meeting our financial characteristics or not meeting our strategy, then we won't pursue them. So, if more of a case that -- again, we've seen to have become more and more competitive on opportunities, and as we look forward, if those types of opportunities continue to arise, you could expect to see more and more M&A activity.

And again, on the other hand, if they don't meet our criteria, you won't see any.

Thank you for that color that is appreciated. Moving on -- and I realize it's still early days, but how have the discussions and kind framework for the Alberta capacity market?

How are those shaping up versus your expectations?

So I think your opening comments, it's early days, is reflective of where we're at. There has been some -- I'll call it, modest consultation taking place.

I wouldn't say anything that there is overly indicative directionally. So again, not really a lot to comment on it at this point.

May be just following up on the diversification and just the rigor that you put it on your M&A activities and that have to be accretive to CPX. I'm just wondering, just longer-term, how do you think about the strategy in the U.S.

if you go back number of years ago, you had the network top strategy, I think, you called it around the IPO and trying to build up effectively, regions of influence in certain geographies, so is that something that if all the conditions are fine from an economic standpoint, that's something that you'd endeavor to do again?

Good morning Andrew, certainly there is some value in having facilities close to each other versus my finding that with our two assets in North Carolina and Canada too obliviously great efficiencies of having a significant amount of assets in Alberta or certainly in Ontario. In that benefit continues to be there and where we have opportunities that are in the same geographic regions, we see that is being quite positive and generally in those circumstances we can see some synergies associated with again operations are being to each other.

Okay. Helpful.

And then maybe just closer to home, in your home market of Alberta, we've seen maybe some signs of life in the Alberta power market that look interesting, there has been fewer hours trading extremely low levels. So I guess, what's your read of this in the market, is it some positive indications of the economy is back that are giving good support to demands, what extent is to whether maybe just some color on what you're seeing in the market activity right now?

Yes, it's Bryan DeNeve. We would agree, Andrew, we have seen some recovery in pricing in Alberta.

There's a couple of things we would observe. The first one is, when you look at demand growth for electricity in Alberta over the first three months, it certainly was very strong running around the 3.5% range on an annualized basis.

So you've strong demand following -- we actually saw a little bit of negative demand growth in 2016. So that's one positive.

The other one is we're starting to see some clarity in terms of older existing coal-fired assets in the intent to shut down or those facilities. So we had TransAlta Sundance 1 and 2.

And today, we had some comments around the facility. I think that clarity is also, as we see that supply exit, the market that's helping bolster pricing.

And then just finally on that given the signs of life in the market and everything starts to look more positive, does that change the dialogue you have with the government in relation to the market transition?

No. It would have really no impact from the perspective of -- this is the energy only market that we're referring to.

And certainly, there's an element of energy in the capacity market that will evolve. But certainly, it wouldn't have a significant impact on the dialogue.

Actually, it has more of a significant impact with investors.

First question on the Decatur asset. Any additional operational detail or color you can provide there and are there any synergies involved at all with that acquisition?

So as you know, and we've indicated, we were under some degree of confidentiality around that acquisition. We'll -- once we close, which we continue to believe to be in the June time frame, we'll be in a position where we can disclose much more to the market.

Okay. That's fair enough.

And just my other question on the renewable side, your U.S. pipeline, any commentary on how things are trending there, you're still comfortable with availability of financing and power opportunities, are there any trends noteworthy there?

No. Certainly, we still continue to actively bid in two to three of those are opportunities at any given point in time.

There's still an appetite in the market. In terms of financial capability, as noted in the materials, we anticipate -- still anticipate two development projects coming across the line balance of this year.

And certainly, we would expect at least 1 of those to be in the U.S. So as we look forward, those are part of our capital allocation and we're looking to finance as we move forward in time.

You just, with respect to the new AFFO guidance range, just given your initially reaffirm that range with the Decatur acquisition, I'm just wondering what are some of the major drivers, is it just, at the time that you just didn't want to have any range or was it the Q1 results versus something else as you think about 2017 that's driving the number?

No Robert. In hindsight, we should have included that updated range and when we announced the Decatur.

So we thought just provided an opportunity to clarify that we're on track in accordance with the original guidance and then the acquisitions are just out into that as we move forward.

Okay. And then maybe just to finish here, are there any kind of updates in terms of your potential involvement around the renewable electricity call and just your expectations for that given the number of renewable facilities that already been permitted and ready for transmission connections?

So, Robert, in respect, the upcoming call, as you say, it will be very competitive. Though our Whitla site specifically is an extremely competitive site with an excellent wind regime, and certainly, we think that there are some advantages being in Alberta that we can bring to bear.

So we expect to be very competent in that first round.

And do you think that the call itself is shaped, and probably is the wrong word, but kind of to your advantage or to your liking, is it relates to location any advantages of being in the right places?

So as we understand, in the messaging has been very that there's essentially going to be two criteria. One is that from a transmission perspective that it's out of sight that you basically plug it in.

And both of our sites Whitla in particular meet that status. The second one is as we understand it, again, and it could change over time, but it's strictly economic.

So what is the price that you want to be paid per megawatt hour over your production over the next 20 years? And again, we think we'll be very competent of from that perspective.

And our understanding is that, that is the only two criteria.

Bryan, if I can just clarify that on I'm pleased to understand #1, is it just that you need to be able to be physically connected to the transmission system, even if the transmission system itself is bottleneck or has problems getting into the main grid?

That is our understanding.

Just back on the M&A front year. So you've been able to achieve goat at mid-single digit accretion on the last to transactions in large part because of the dry powdered you had on the balance sheet as well as in the case of Decatur at least, utilizing some old tax yield, but looking forward, if you assume a more normalized 50-50 debt equity split, let's call it on financing structure, and also a more normalized cash tax burden.

Just wanted to get your thoughts on whether or not you still be comfortable transacting on deals going forward just given the strategy to diversify geographically or to continue ramping up your contract to cash flow profile, even if the transaction didn't result in near-term accretion?

So, when you look at the issue of dry powder, certainly, one of the elements around that, as you mentioned was our tax situation in the U.S. We continue to have some capability to utilize tax yield in the U.S.

So I guess, to put it in your terms, there continues to be some dry powder there. And in terms of utilization of our balance sheet, we continue to have significant cash flow coming into Capital Power, which certainly we're utilizing for both greenfield and acquisition purpose as they would arise.

But also what we've seen, and I think, as you've obviously seen, there's been some significant appreciation in share price. So the accretion criteria that we have, obviously, as share price increases, become easier and easier to meet from a financing and from a shareholder result perspective.

Over this last year, since December that aggregate of analyst expectations have increased over 10%, which gives us currency that's much more conducive to generating accretive acquisitions.

And on the contracted cash flow profile, you mentioned, over 80% contracted pro forma Decatur. But I guess with Genesee 1, 2, PPA coming off at the end of 2020, is that 80% mark, is that the target that you're looking at heading into the next decade as you bring on another contracted assets?

Yes. Certainly, we'll have a drop in contracted cash flow as the PPA expires post 2020.

But when we look forward and as we see more opportunities and continue to develop our pipeline of construction opportunities, we would see coming into 2021 in the 70% range, and that increasing over time in the next to get back towards 80%.

Just lastly, any update on the 7 U.S. wind farms that you have the PTC safe harbored just with respect to timing of maybe locking down some PPAs there?

Yes, we're still optimistic that we're still going see one to two of those come across wire here in 2017 with off takes in place.

And just to confirm back to Brian's comment about, you still have a little bit of tax yield in the U.S., so safe to assume for now, you'll be bringing in tax equity partner, your tax appetite isn't quite there yet?

That's correct.

Just one strategy question related to dividend payout as we move forward with the higher sort of contracted cash flow profile. Has there been any thought at the Board level in terms of all three modifying dividend payout strategy to give some of that cash back to the shareholders in the form of a higher payout ratio overtime.

Obviously, recognizing the balancing act between maintaining that cash flow for growth purposes versus being just your thoughts on that?

It is an ongoing discussion with our Board and within management as to what it is the reasonable payout ratio for business going forward. As you know, we've indicated what our intentions are for 2017 and 2018 and those continued to be the same.

We may have additional guidance at Investor Day this year in December or we may well continue with our guidance for 2017 and 2018.

So on table then, but nothing definitive?

That is correct.

And then just on Bloom still maybe a little bit more precision in terms of the Q3 timing. I'm just wondering, if the current assumption is that it's going to be early Q3, mid-Q3, late Q3 and I am relatively speaking we're talking about matter of months which, but if you can have any additional detail there?

Yes. So, certainly, we were -- the original COD target was very early, Q3, in fact probably early July.

The construction is going very well. So, we would expect there's a possibility that could move up into the June timeframe.

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

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