Capital Power Corp

Randy Mah - Senior Manager of IR Brian Vaasjo - President and Chief Executive Officer Bryan DeNeve - Senior Vice President and Chief Financial Officer Mark Zimmerman - Senior Vice President, Corporate Development and Commercial Services

Jeremy Rosenfield - Industrial Alliance Securities David Quezada - Raymond James Robert Catellier - CIBC World Markets Ben Pham - BMO Capital Markets Andrew Kuske - Credit Suisse Patrick Kenny - National Bank Financial Robert Kwan - RBC Capital Markets

Good morning. Thank you for joining us today.

Earlier this morning, we announced the acquisition of 294 megawatts of contracted power facilities in Ontario and BC. We also released Capital Power’s fourth quarter and 2016 annual financial results and announced the appointment effective April 3 of two new directors.

These news releases 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, Bryan DeNeve, Senior Vice President and CFO and Mark Zimmerman, Senior Vice President, Corporate Development and Commercial Services.

We will start with an overview of the acquisition transactions followed by a review of our fourth quarter and annual financial results. 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 Number 2. In today’s presentation, we will be referring to various non-GAAP financial measures as noted on Slide No.

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.

These measures are provided to complement GAAP measures in the analysis of the Company’s results for management’s perspectives. Reconciliations of these non-GAAP financial measures can be found in the Company’s 2016 MD&A.

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

Thank you, Randy. Good morning.

I am pleased to announce that we have reached an agreement with Veresen for the acquisition of four fully contracted generation facilities. We are acquiring two natural gas-fired facilities and two waste heat assets.

A $500 million purchase price consists of $225 million in cash subject to working capital and another closing adjustments and the assumption of $275 million of project level debt. The cash portion of the transaction will be financed through existing cash and use of our credit facility.

The transaction will provide immediate accretion to both adjusted funds from operations and earnings. For the first full year of operations, the acquired assets are expected to add $24 million to AFFO, which is about $0.25 per share representing a 7% increase.

The accretion on earnings per share is $0.11 per share. The projected EBITDA contribution from these assets is approximately $55 million per year.

The closing of the transaction is expected to occur in the second quarter of this year and is subject to regulatory approval and satisfaction of closing conditions. Overall, the transaction will significantly add to our contracted cash flows out to the end of the next decade.

Moving to Slide 5, I want to provide more details on the assets. The two Ontario natural gas facilities are York Energy Center and East Windsor Co-gen Center.

We are acquiring a 50% interest in York Energy, which provides us with 200 megawatts of capacity from the total 400 megawatts capacity of the plant. We will have a 100% interest in East Windsor, which is an – which has an 84 megawatt capacity.

Both facilities are under long-term PPAs with the Ontario IESO and have an average remaining PPA life of 14 years. Under the PPAs the plant’s earn revenues through fixed capacity payments that are partially indexed to inflation and there was a pass-through of O&M fuel and start-up costs.

The assets are strategically located in Ontario which supports future re-contracting of the PPAs on strategic – on economic terms. Slide 6 describes the waste heat generation facilities in BC.

The two waste heat assets 5 megawatts heat are located in West Coast Energy’s BC gas pipeline capacitor stations in Savona and 150 Mile House. Both waste heat generation facilities are fully contracted with BC Hydro and have 11 years of contract life remaining after expiry in 2028.

The electricity purchase arrangements have partial inflation indexation and provide premium pricing under peak load hours. Turning to Slide 7, this updated chart shows the growth in our contracted EBITDA from 2010 to 2017.

As you can see, our contracted EBITDA has increased 194% during the same period which translates into a 17% compound annual growth rate. For 2017, you can see the significant increase in contracted EBITDA from a number of new sources, which includes Bloom Wind, which is expected to be completed in the third quarter to start off annual off coal compensation payments from the Alberta government and expected contributions from the acquisition of the two natural gas plants and two waste heat assets that I discussed.

Accordingly, the long-term contracted EBITDA has a percentage of total EBITDA increases from 66% in 2016 to 79% in 2017. On Slide 8, I will summarize the transaction by highlighting the numerous benefits.

We are acquiring young, high quality assets that have an excellent operating history, which will strengthen our existing fleet of assets with the waste heat facilities located in BC and natural gas facilities located in Ontario they provide geographical diversification from our incumbent market in Alberta. All of the assets are under long-term contracts.

The weighted average remaining contract life of 14 years enhances our contracted cash flow as these original contracts expire between 2028 and 2032. And the Ontario PPAs are well positioned for re-contracting on economic terms after these original PPAs expire.

The transaction provides immediate accretion. In the first full year of operations, we expect AFFI accretion of $0.25 per share and $0.11 per share to earnings.

For 2017, our contracted EBITDA is expected to increase approximately 8%. All of these assets are under long-term contracts.

The transaction will enhance our contracted cash flow profile and our ability to grow our dividend. Finally, the transaction will improve the overall business results.

We expect the credit rating agencies to affirm our credit ratings and outlook. Turning to Slide 9, I’ll briefly review our highlights for 2016.

Capital Power’s performance in 2016 was strong with the company meeting its annual operating and financial targets. This includes achieving average facility availability of 94%, generating $384 million in funds from operations which was within the $380 million to $430 million target, but at the lower end of the range, primarily due to the Sundance PPA settlement payment in the fourth quarter.

Financial results also included a strong year of EBITDA of $520 million and we continued to construct the Bloom Wind project, which is on schedule for commercial operations in the third quarter of 2017. Other highlights for 2016 include reaching a satisfactory agreement on fair compensation for early phase-out of coal-fired generation and the settlement of the Sundance PPA dispute with the Alberta government.

Finally, we increased Capital Power’s share dividend by 6.8% and confirmed annual dividend growth guidance by 7% per year to 2018. Moving to Slide 10.

This slide summarizes the availability operating performance of our facilities for the fourth quarter of 2015 and 2016 for the full year of 2016. We had solid operating performance in the fourth quarter with average facility availability of 94%, which was lower than the exception of 99% performance in Q4, 2015 due to the planned outages at Genesee 3 and Shepard in the fourth quarter of 2016.

For 2016, our facilities performed well with an average availability of 94%. The strong operational performance is illustrated on Slide 11.

This chart shows the average availability of our facilities over the past five years. As you can see, 2016 is a continuation of our strong track record of operations and high fleet availability.

This strong operational performance has resulted in an average availability of 94% over the past five years. I will now turn the call over to Bryan DeNeve.

Thanks, Brian. On Slide 12 I’ll review our fourth quarter financial performance.

We generated $75 million in funds from operations, which was down 40% compared to $125 million in the fourth quarter of 2015 due to the one-time Sundance PPA settlement payment of $20 million and realized losses from the settlement of interest rate swaps. We reported normalized earnings per share of $0.27, which was lower than the $0.42 in the fourth quarter of 2015.

Our trading desk performed well and captured realized price of $67 per megawatt hour on our Alberta commercial assets, that is 205% higher than the average spot price of $22 per megawatt hour in the fourth quarter of 2016. Slide 13 shows the summary of our fourth quarter financial results compared to the fourth quarter of 2015.

Revenues were $280 million, down 17% from the fourth quarter of 2015, primarily due to unrealized changes in the fair value of commodity derivatives and emission credits and lower revenues from the Alberta commercial facilities, Sundance PPA and portfolio optimization segments. Adjusted EBITDA before realized changes and fair values was $138 million, down 5% from the fourth quarter of 2015.

This was primarily due to the one-time Sundance PPA settlement payment and a net realized loss from the termination of interest rate derivatives. Normalized earnings of $0.27 per share decreased 36% compared to $0.42 in the fourth quarter of 2015.

As mentioned, we generated funds from operations of $75 million in the fourth quarter, which was down 40% on a year-over-year basis and impacted by the Sundance payments. Slide 14 shows our annual 2016 financial results compared to 2015.

Revenues in 2016 were approximately $1.2 billion, which was down 2% year-over-year. Adjusted EBITDA before unrealized changes in fair values was $509 million, up 5% from 2015, primarily due to strong portfolio optimization results.

Normalized earnings per share were $1.22 in 2016, up 6% compared to $1.15 in 2015 and funds from operations were $384 million in 2016, which was down 4% year-over-year, primarily due to the Sundance settlement payment and realized losses from the settlement of interest rate swaps. The realized losses from interest rate swaps flows through FFO but do not impact adjusted EBITDA.

I’ll conclude my comments with our updated financial outlook for 2017 on Slide 15. 2017 marks the commencement of annual off-coal compensation payments of $52.4 million, that we will receive each year for the next 14 years.

With the acquisition of two natural gas and two waste heat facilities that’s expected to close in the second quarter, we expect to experience an increase in EBITDA. The projected EBITDA contributions on a full year basis from these assets is approximately $55 million.

The slide shows our commercial hedging profile for 2017 to 2019 as of the end of 2016. For 2017, we continue to be fully hedged at an average contracted price in the mid-$40 per megawatt hour range.

In 2018, we are 53% at an average contracted price in the low $50 per megawatt hour range and for 2019, we are 14% hedged at an average contracted price in the low $50 per megawatt hour range. In summary, our base load merchant exposure is fully hedged in 2017.

I'll now turn the call back to Brian Vaasjo.

Thanks, Bryan. On slide 16, I'll review our 2016 operational and financial results, compared to the 2016 annual targets and provide an update on our 2017 target.

In 2016, we achieved all of our annual targets. This includes an average facility availability of 94% which met our annual target.

Our sustaining CapEx was $55 million, which was lower than the $65 million target due to lower expenditures on planned outages and the accrual of various projects in the future periods. Our plant operating and maintenance expenses in 2016 were $205 million, this was in line with the $200 million to $220 million target.

Finally, we’ve generated $384 million in funds from operations, which was in line with the $380 million to $430 million annual target range. The slide shows our original 2017 targets which we announced at our Investor Day in December 2016 with a guidance of the natural gas and waste heat assets, we have provided updated guidance.

The acquisition is expected to increase O&M expenses from the original range of $195 million to $215 million to a revised range of $205 million to $230 million. And we have increased our 2017 AFFO financial target from the original $305 million to $345 million to the new range of $320 million to $365 million.

Turning to Slide 17. We had two development and construction growth projects in 2016.

Our Genesee 4 and 5 projects, the full notice to proceed decision has been deferred, the continuation and timing of the projects will be considered once more Alberta market structure certainly exists and new generation is required to balance supply and demand in the province. Turning to Slide 18.

Our growth target for new development outside of Alberta was to execute a contract for output for new developments. This was achieved with our Bloom Wind project with a ten year fixed price contract having a 100% of the output.

For 2017, our target is to complete Bloom Wind 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 as we continue to actively progress our development pipeline in the US.

I’ll now turn the call over to Randy.

All right. Thanks, Brian.

Operator, we're ready to start the question-and-answer session.

Thanks. Just a few questions on the acquisition announced this morning and congratulations on that.

But, with regard to the AFFO guidance, does the $24 million number there, is that from the assets alone, excluding sort of the project level debt payments? Or have you assumed something with regard to additional interest costs due to the transaction?

Yes, so that AFFO would include the interest expense from the existing project debt in place as well as any incremental debt we would see associated with the transaction.

Okay. So then, you are assuming some portion of permanent debt financing associated with the cost there?

With regard to the balance sheet, just following on that, do you have a view as to where this takes the balance sheet in terms of leverage following the transaction and how comfortable you are with the new level as to where you’d like to be over the longer term?

Yes, so, certainly that’s one of the key areas we look at. We are considering the implications of a potential acquisition.

In this case, when we look at our FFO-to-debt metric, it does decline of course to some degree given we are looking at a 100% debt financing. However it declines to around 18% FFO-to-debt from the S&P’s perspective and how they calculate it.

So that still leaves us a cushion over the minimum threshold of 15%. So, this acquisition certainly adds leverage, but leaves us with lots of cushion relative to the credit metrics at DBRS and S&P are looking at.

Okay, great. Maybe just one additional question.

In terms of the Ontario PPAs, for the Ontario assets, do you know what the terms are with regard to carbon cost pass-through? Those are pass-through to the buyers under the PPAs?

It’s Mark Zimmerman here, yes, they are.

Okay, great. I’ll leave it there for the moment.

I’ll jump back in queue. Thanks.

Thanks, good morning guys. Just first on the Ontario natural gas facilities, I see here in the presentation they are strategically located.

With the odds of re-contracting, could you give us any color on, I guess, detail on and why there the locations are so advantageous, compared to others, I guess, that hasn’t gotten re-contracted?

Mark Zimmerman here again. Just in terms of the location of these things and the center of the grid and transmission constraints that we have there, it is very advantageous for the operation and York itself is a very strategically placed peak and is called upon quite frequently has lowered both winter and summer.

So we feel very confident that they will continue to need that. The alternative is building a much more expensive transmission to try and alleviate that and connecting other facilities.

Okay, great. Thanks, that’s helpful.

And then, just in terms of the timing of the acquisition, I see a closing in 2Q 2017, but I guess, just based on the additional FFO you are targeting for 2017 it kind of looks like it will probably be towards the earlier part of the quarter, is that fair to say?

Directionally, yes, but of course, it does require in a number of typical closing conditions. So we’ll need to see all those play out to refine our thinking as we move down the road here.

Okay, great. And then, just my last one here, just on the US development portfolio, potential to do new projects there, any update on the environment that you are seeing in light of potential tax reform in the US?

So we are not seeing, although there is a lot of controversy around potential tax reform and so on and certainly it does impact on the potential or the economics of an equity or a tax equity partner. That we expect should be settling down sometime over the next couple of months.

Don’t see that is actually disrupting the level of activity in terms of people looking for long-term power purchase arrangements. On the other hand, we do see a little bit of pushback from some traditional interest in some of the states relating to more call it, anti-renewable segments are certainly coming out a little bit more in force.

Okay, great. Thank you very much.

I’ll get back in the queue.

Hi, good morning and congratulations on the acquisitions. I had a couple questions.

What are you assuming in terms of synergies for the acquisition? And what are the nature and timing of these synergies?

So we do have an infrastructure here in place that relates to many of the corporate functions that need to support services like that. So we would expect there is some value that we will be able to materialize out of that.

As it relates to the plant itself and the cost synergies, you have a complement of individuals there that will be taking over to run that and we haven’t factored any synergies into our thinking on that front. There of course will also be some potential revenue synergies that as we look at the cost of the commodity and the transportation of it.

But again, not a huge amount that we are assuming in the early days at these plants.

So just on that transportation, so if there were to be a re-contracting of the TransCanada Mainline and rates come down, is that included in your synergies or is the company have been exposed to that element?

So, specifically, we have not included that in our synergies as to the level of benefit that we would get for that or have to share. I am not at a position right now to give guidance on that.

Okay, and just finally, I guess, two wrap up questions. One, did it – this acquisition come with a development portfolio at all?

Or, and then finally, the average availability on these assets since inception?

So on the development portfolio, generally not. As it relates to availability, we are into the high 90s.

I’ll probably have to get Randy with these specific numbers, but it is high 90s that we have on these assets.

Okay, thank you very much.

Okay, thanks. Good morning.

I just want your thoughts about your priorities for capital allocation post this transaction it looks like you have taken a bit more debt than perhaps your overall corporate structure on a debt to EBITDA basis as your pay out seems pretty low. Does this transaction potentially target to grow higher or more of an extension or more status quo?

So, I think, as we look forward, our number one priority of course is maintaining the existing dividend and growing it. But the priority following that of course is growth that makes sense and meets our financial metrics.

I think as you look forward, you can expect depending on the nature and size of the potential growth opportunity we are looking at, you may see a financing structure that starts to bring in more equity. But certainly that will depend on its timing and nature of the growth opportunity.

And just a follow-up on that. Would you say that your balance sheet capacity for grow for acquisitions look this deal as potential but more less flexible than it was coming into the deal that you may have to potentially look at alternative sources of equity such as external financing or asset sales?

No, certainly, we’d be comfortable with looking at raising equity in the market for the right acquisition or right development project that comes to us. So, certainly, you wouldn’t see us applying the same leverage that we did here, because we did have that room and capability on the balance sheet.

But, we will be comfortable moving forward with an opportunity that did require some equity financing.

And can you comment, I mean, there is some other assets that Veresen will transfer in Ontario, was that more of a balance sheet constraint on you guys near-term or is it something else?

And so, I am not at liberty to kind of go through all the pros or the ups and downs of the whole discussion. Suffice it to say that, we are very intrigued with the strategic nature of these gas assets or capabilities as it relates to other parts of the portfolio while we had some interest, not interest at the same level of – say some others.

So, we very much focused our attention on the gas operations only.

Okay, that’s helpful. Thanks everybody.

Thank you. Good morning.

It’s an interesting acquisition this morning from an economic standpoint and strategic standpoint, but what does the acquisition also say about the balancing act of your Alberta versus your non-Alberta exposure? And does that send any kind of messaging to the government on capital allocation as they work in through the capacity payment process?

Actually, one of the things when you look at Alberta, Andrew is, in terms of spending capital, a large amount of capital over the next few years, those opportunities are relatively limited. And as you know, and as evidenced by this transaction we got a lot of balance sheet capacity and we still have a little bit of dry powder on our balance sheet and a lot of very, very strong cash flow.

We – I think you’ve made it very clear that we expect to be putting out a whole lot of capital into the US and the balance of Canada not just for diversification reasons, but there is, I’ll call it an absence of near-term capital commitments available in Alberta.

Okay, that’s helpful. And then, maybe just building upon that, when you look at, just your development portfolio and the opportunities you have in particular on the wind projects in the US, what kind of appetite have you seen to really do a rinse and repeat on bloom and the structure you’ve used on bloom and some of the other things that are in the pipeline in the US?

So, Bloom was a little bit of a unique structure, although we’ve seen a significant amount of interest in the market associated with it, so there definitely could be opportunities, I’ll say that to reuse the Bloom structure. I would say, most of the opportunities that are out there that we are participating in, I’ll call it, are more a vanilla in nature than say, Bloom was.

Okay, very helpful and then one final one if I may, just to Bryan DeNeve just on the impairment test in the Alberta assets being grouped as one. I noticed the details in the note, but is this just really a function to avoid some undue volatility in the near-term in the financials just on single-unit impairment versus just having it and collection of one?

Well, we – earlier this year, we looked at our cash generating units and their grouping and it became apparent to us that, Genesee 1 and Genesee 2 which we refer to as our Alberta contracted cash generating unit has really now reached the point where it will be fully merchant starting 2021. So it made sense to have one group of Alberta assets that were a single cash generating unit just given, they are also closely tied to the Alberta market.

So that was a decision we made earlier this year and as we roll through the impairment and completed that testing, it was just basically bringing all the components together what the payment was from the government and our current forward views on those assets. We then tested that as a single cash generating unit and came to the conclusion that we weren’t in a place where there was an impairment on those assets.

Okay, that’s great. Thank you.

Thank you. Morning guys.

I am wondering if you might be able to quantify for us your internal assumptions surrounding East Windsor and York after the PPAs expire, what percentage reduction in EBITDA you are assuming if any after the re-contracting?

So, I guess, as we look out there and bear in mind as well, we are looking at 14 or 13.8 years out there for I think East Windsor and excess of 14 for York, We are expecting that there should be a nominal reduction in EBITDA as we get way out there just given the profile that we are looking at and the strategic nature of these assets. But that being said, a lot of that’s going to depend upon the nature of the fleet at that point in time, load growth, what Ontario does with it, nukes et cetera.

So I would be hesitant to firmly package just given how far in the future this is.

Okay, and then you are funding the cash purchase price, wondering if it makes sense to look at securitizing a portion of your coal compensation payments here or is it more attractive to pursue term debt at current market pricing?

Well, we’ve certainly been exploring in looking at securitization of some or a portion of the coal compensation payments. There are a number of considerations to doing that.

But I will say that, certainly it’s – it does potentially provide attractive financing cost but comes with a credit degree of complexity. We are very pleased though like in terms of our spreads on term debt and whether they have come down to.

So, certainly raising debt, our medium-term notes in the market in Canada is a very competitive alternative for us at this point.

Okay, great and then one last question if I could. Just at Genesee, if you can reconcile for us the higher coal costs experienced in 2016 with your overall Genesee mine optimization program and maybe what your targets are for reduced coal cost per ton through 2017?

We are in the process, of course, working with Westmoreland in terms of a revised mine plan given we’ll be off coal at the end of 2030 and working through that. Where that – the specific answer to your question something we will have to follow-up with you on.

Okay, thank you very much.

Good morning. Just looking at the EBITDA guidance and then working way down the FFO guidance, just in terms of the different line items, I think you’ve covered off interest expense and I am just wondering, can you give any granularity around expectations for cash taxes, maintenance CapEx?

And then, are you including the amortizing principal on the debt in the AFFO?

So, we aren’t including the amortizing principle in terms of the calculation of FFO. So, at Investor Day, we walked through the adjusted funds from operations calculation.

So, it basically takes funds from operations and then goes to the next step in terms of removing the preferred shares, share dividends and capital maintenance, expenditures and then adds back to coal compensation. So, that’s how we get to the AFFO calculation in the number.

The $24 million associated with this acquisition is consistent with that approaching calculation. So, again, in response to your question, it would exclude what we see as – or would have taken out, what we see as capital maintenance for the asset over the next year.

Interest payments, but not the principal payments on amortizing debt.

Okay, so just in terms of that bridge from 55 down to 24 is obviously you’ve got the interest as just a huge component of it.

Yes.

Is it after the rest maintenance CapEx or is there a material cash tax that you are seeing.

No, there wouldn’t be a material cash tax. So, majority is interest expense.

Okay, just knowing that gas can be a little lumpy, is maintenance CapEx any higher in the near-term than kind of a normal runrate?

No.

Okay. There was just the discussion on synergies.

I just want to make sure I am clear. So does the $55 million include your estimate of synergies?

Or is that excluding synergies?

It does, Robert, include our estimate of synergies.

Okay. And, I think, Mark, you mentioned just on the Mainline and you don’t have anything there on any long-haul toll.

I am just wondering, are those contracts actually exposed to that or are they a Don index?

It’s gone. It’s just more what’s the relationship between NIT and Don and how that may change vis-à-vis the cost of gas, sort of pricing of it for any changes they have on the transportation side.

Okay, so are you not flow through though out of Don or?

We are and that ends my – until we see how that would manifest itself, what we go through the commodity, different things that we might do if there is some benefit we will obviously pursue it, but on the phase of it we are predominantly a flow through mechanism here.

Understood and if I can just finish, Bryan you mentioned in earlier questions just you look forward past the transaction that you may look at financial structures that bring in more equity and I guess, just coming back to securitizing the Alberta payment, you mentioned that as an option, but how does that kind of comment square up with looking at something that would require kind of more equity?

Well, certainly, if we securitize the payments, we view that as an alternative source of debt effectively at the end of the day. And generally, that’s just because of how it will work through and affect our credit metrics.

So, yes, we look at securitization as an alternative to going to do a private placement in the US or potentially accessing the bond market here in Canada. But it wouldn’t be viewed as a substitute for equity.

Okay, understood. Thank you.

. Just on a different topic for a second, maybe high level if you can comment just on the tone of the concentration that have been going in Alberta with regards to the development of the capacity market and how you think that’s developing so far?

The process is laid out and there is a number of processes that are, again, have been laid out. It’s pretty early days, but I would have to characterize it as, certainly continuing to be a positive tone and one on which the government both from the policy perspective and from the implementation perspective, they’ll continue to have a positive tone.

Okay, great. Thanks.

Okay, if there are no more questions, we will conclude our call. Thank you for joining us today and for your interest in Capital Power.

Have a good day everyone.